EX-99.1


		NEWS RELEASE

FOR IMMEDIATE RELEASE

NRG Energy, Inc. Reports Second Quarter 2006 Results;
Expands FORNRG Performance Improvement Program;
Announces Capital Allocation Plan; Revises 2006 Guidance

•		$238 million of cash flow from operations, including return of $42 million cash collateral;

•		$338 million of adjusted EBITDA, excluding mark-to-market (MtM) impacts;

•		2006 cash flow from operations and adjusted EBITDA guidance adjusted to $1,324 and $1,500 million, respectively;

•		$1.98 billion of total liquidity at June 30, 2006;

•		$200 million recurring cost improvement target by 2009 under the FORNRG program (revised upward from the previous $105 million annual target by 2008); and

•		$750 million capital allocation program in two phases—the first phase is a $500 million common stock repurchase program to be completed by year end 2006.

Princeton, NJ; (August 1, 2006)—NRG Energy, Inc. (NYSE: NRG) today reported second quarter 2006 operating income of $416 million versus $43 million for the second quarter of 2005. Cash flow from operations was $238 million, including a $42 million reduction in the amount of cash collateral posted in support of trading operations, compared to $27 million during the same period last year which included a collateral outflow of $179 million. For the six months ended June 30, 2006, operating income was $626 million versus $90 million for the same period last year. Cash flow from operations year to date was $604 million for 2006, an increase of $513 million over 2005. Net income for the three and six months ended June 30, 2006 was $203 million and $229 million, respectively, as compared to $24 million and $47 million for the same periods last year. Net income in 2006 included $105 million in after tax refinancing expenses incurred as part of the first quarter closing of the Texas Genco acquisition, partially offset by $49 million in after-tax one-time gains related to the resolution of disputes and litigation.

The quarter-on-quarter and year-to-date operating income increases largely reflect the February 2, 2006 acquisition of Texas Genco (now known as NRG Texas). Also contributing to the improved second quarter performance were plant operating rate improvements at five of the six classic NRG baseload coal plants and higher New York capacity prices versus the same period last year. These improvements were partially offset by increased general and administrative expenses associated with the NRG Texas integration and Mirant-related expenses. The year-to-date results benefited from $67 million in surplus emissions allowance sales and $30 million in improved South Central margins achieved primarily through higher plant operating rates and increased merchant sales. Offsetting these increases were $69 million in lower Northeast margins due primarily to the unseasonably mild weather in the first quarter, higher operations and maintenance expenses due to increased major maintenance, and higher general and administrative expenses.

“As we informed the market during the Texas Genco acquisition financing, we expected cash generation from both our Texas business and the classic NRG portfolio to pay immediate benefits in terms of a return to our shareholders,” said David Crane, NRG’s President and Chief Executive Officer. “Now, with all aspects of our business performing at higher levels as a result of the continued

success of the FORNRG program and the integration of NRG Texas almost complete, we are in a position to fulfill our promise with a $750 million capital allocation program.”

Regional Segment Review of Results

Table 1: Three Months Income from Continuing Operations and Adjusted EBITDA


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

Three months ending	6/30/06			6/30/05			6/30/06			6/30/05

Texas		292			—			253			—
Northeast		51			39			75			59
South Central		(6	)		(7	)		15			8
Australia ⁽¹⁾		6			6			6			6
Western		8			6			9			6
Other North America		1			(6	)		(4	)		2
Other International		16			23			15			13
Alternative Energy, Non-generation, Corporate and Other ⁽²⁾		(74	)		(30	)		27			14

Total		294			31			396			108

Less: MtM forward position accruals ⁽³⁾		(37	)		(5	)		(37	)		(5	)
Add: Prior Period MtM reversals ⁽⁴⁾		(21	)		8			(21	)		8

Total net of MtM Impacts		236			34			338			111

⁽¹⁾ Includes only Gladstone Equity Earnings; Flinders is reported as a Discontinued Operation.

⁽²⁾ Includes net interest expense of $83 million and $38 million for 2006 and 2005, respectively.

⁽³⁾ Represents a net domestic MtM gain of $37 million in 2006 (primarily in the Northeast and Texas regions) and a net domestic MtM gain of $5 million in 2005, primarily in the Northeast region.

⁽⁴⁾ Represents the reversal of $21 million in 2006 associated with the $119 million net domestic MtM losses recognized in 2005 and reversal of $8 million in 2005 associated with the $59 million net domestic MtM gain recognized in 2004, primarily in the Northeast region.

Table 1: Six Months Income from Continuing Operations and Adjusted EBITDA


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

Six months ending	6/30/06			6/30/05			6/30/06			6/30/05

Texas		285			—			345			—
Northeast		183			72			255			112
South Central		29			2			74			34
Australia ⁽¹⁾		11			12			12			12
Western		4			9			5			9
Other North America ⁽²⁾		60			(12	)		(2	)		1
Other International		40			69			42			49
Alternative Energy, Non-generation, Corporate and Other ⁽³⁾		(302	)		(99	)		35			31

Total		310			53			766			248

Less: MtM forward position accruals ⁽⁴⁾		(67	)		33			(67	)		33
Add: Prior Period MtM reversals ⁽⁵⁾		(65	)		50			(65	)		50

Total net of MtM Impacts		178			136			634			331

⁽¹⁾ Includes only Gladstone Equity Earnings; Flinders is reported as a Discontinued Operation.

⁽²⁾Includes $67 million pre-tax gain for settlement with equipment manufacturer in 2006.

⁽³⁾ Includes interest and refinancing expenses of $313 million and $115 million for 2006 and 2005,

respectively.

⁽⁴⁾ Represents a net domestic MtM gain of $67 million in 2006 (primarily in the Northeast and Texas regions) and a net domestic MtM loss of $33 million in 2005, primarily in the Northeast region.

⁽⁵⁾ Represents the reversal of $65 million in 2006 associated with the $119 million net domestic MtM losses recognized in 2005 and reversal of $50 million in 2005 associated with the $59 million net domestic MtM gain recognized in 2004, primarily the Northeast region.

Texas: Lower than anticipated power prices realized on merchant energy sales from our gas fleet and the unhedged portion of our baseload fleet offset these results during the quarter and half year. Results benefited from continued strong operating performances from our baseload fleet, coupled with higher than expected generation from our Texas gas plants. This was largely driven by increased demand from hotter than normal weather and significant outages by other baseload power plants in the region. Amortization associated with net out-of-market contracts increased pre-tax operating results by $212 million and $225 million, for the quarter and year-to-date, respectively. Quarterly baseload plant operating performance was excellent at Limestone, Parish and the South Texas Project. Integration of the NRG Texas business continued throughout the second quarter and is on target for completion during the third quarter.

Northeast: Lower quarterly results for the Northeast, after adjusting for MtM impacts, were driven by weaker power prices and lower generation. Decreased demand, predominantly due to milder than expected weather, for our peaking assets resulted in lower generation hours from the oil-fired and intermediate gas-fired assets. Partially offsetting the lower demand was significantly improved equivalent forced outage rate performances from the Indian River, Huntley and Dunkirk plants, the reversal of a net $15 million station service reserve, and improved capacity pricing in New York. For the year-to-date, mild weather in the first quarter and continuing weak power prices were partially offset by sales of surplus emission allowances related to the reduced first quarter generation levels, and the improved operating performance and capacity prices.

South Central: Quarterly and year to-date results reflect higher net merchant sales at prices above contracted energy prices. Improved unit availability reduced the need to purchase power to service our long-term coop contracts. By contrast, during the second quarter of 2005, Big Cajun II experienced a number of unplanned outages which required us to purchase energy to serve contracted load.

Western: Improved quarterly results are largely attributable to the acquisition of Dynegy’s 50 percent interest in West Coast Power (WCP), which closed March 31, 2006. The impact of the additional ownership is offset by lower reliability-must-run (RMR) fixed cost recovery by Encina units 4 and 5 and lower equity earnings from our Saguaro investment due to the June 2005 expiration of its favorable gas contract.

Australia: In June 2006, NRG announced it had entered into a purchase and sale agreement to sell its Flinders and Gladstone investments in Australia to Babcock & Brown and Transfield Services, respectively. Flinders has been reclassified as discontinued operations and excluded from income from continuing operations while Gladstone results continue to be reported as part of equity earnings of unconsolidated affiliates. Completion of the Flinders sale is expected in the third quarter and the Company is seeking to close the Gladstone sale later in the fourth quarter, subject to significant conditions precedent.

Other North America: Results for the quarter reflect our continuing efforts to monetize non-strategic assets. This quarter, we sold our interests in the James River and Cadillac equity investments for total cash proceeds of $19 million and a book gain of $11 million. Year-to-date results include

other income of $67 million related to a settlement agreement reached with an equipment manufacturer associated with turbine purchase agreements from 1999 and 2001, and the Rocky Road sale.

Other International: Improved quarterly results were due to lower operating costs at our Itiquira operation in Brazil and increased equity earnings from our MIBRAG investment, the 2005 quarterly results of which were lower due to customers’ planned outages. Additionally, we sold our interests in various Latin Power funds for net cash proceeds of $23 million and a pre-tax gain of $3 million. Year-on-year results are lower largely due to the impact of the sale of Enfield on April 1, 2005, which contributed $16 million to earnings during the first half 2005, partially offset by higher equity earnings from our MIBRAG investment.

MtM Impacts of Hedging and Trading Activities
The Company, in the normal course of business, enters into contracts to lock in forward prices for a significant portion of its expected power generation. While these transactions are predominantly economic hedges of our baseload portfolio, a portion of these forward sales are not afforded hedge accounting treatment and the MtM change in value of these transactions is recorded to current period earnings. Driving the forward MtM gains in the first quarter of 2006 was the unseasonably mild weather in the Northeast that resulted in lower energy prices for the first quarter with further declines in the second quarter. For the second quarter 2006, we recorded $37 million of forward domestic net MtM gains, compared to a $5 million net domestic MtM loss recorded in the second quarter 2005. In addition to this forward gain in the quarter, of the $119 million MtM loss recognized in 2005, $21 million reversed to income during the second quarter in 2006 and $65 million year-to-date.

Liquidity and Capital Resources

Table 2: Corporate Liquidity


($ in millions)	June 30, 2006		March 31, 2006⁽¹⁾		December 31, 2005⁽¹⁾

Unrestricted Cash		957		818	$	506
Restricted Cash		58		67		64

Total Cash		1,015		885	$	570
Letter of Credit Availability		116		202		38
Revolver Availability		846		846		150

Total Current Liquidity		1,977		1,933	$	758

⁽¹⁾ These amounts have not been reclassified for discontinued operations

Liquidity at June 30, 2006 was $1.98 billion, up $44 million since March 31, 2006 and approximately $1.2 billion since December 31, 2005. The $130 million cash increase during the quarter resulted from $238 million of cash from operations which included a reduction of $42 million in the amount of cash collateral posted to support trading operations, and $42 million in proceeds from asset sales. These improvements were offset by $72 million in cash interest payments, $39 million in capital expenditures, $46 million in principal debt repayments and $13 million in preferred dividend payments.

Posted cash collateral supporting hedging and trading activities at June 30, 2006 totaled $209 million, of which $135 million is expected to be returned to the Company during 2006 as the underlying trading positions settle during the year.

Capital Allocation — Share Repurchase Program
The Company is announcing today a $750 million share repurchase program which, due to the restrictions imposed by our loan covenants, will be implemented in two phases. Phase One is a $500 million common share repurchase program which the Company intends to commence immediately and complete over the course of 2006. In addition, the sale of the Australian business is expected to provide approximately $400 million in net cash proceeds that NRG intends to use to pay down its Term B loan in the first quarter of 2007. Consolidated project level debt associated with Australia is $177 million, bringing total expected debt reduction to $577 million. Phase Two of the share repurchase plan—which will be initiated after the expected step up in the Company’s restricted payment capacity at the end of the first quarter 2007—is an additional $250 million common share buyback. The Company reserves the flexibility—based on market conditions at the time—to reallocate all or a portion of Phase Two to the initiation of a common share dividend.

“The capital allocation program that we are announcing today has been carefully sized and structured to return significant capital to shareholders in the near term, reduce leverage at the corporate level, and retain financial flexibility to support the ongoing fleet redevelopment initiative,” said Robert Flexon, NRG’s Executive Vice President and Chief Financial Officer. “By focusing on a large buyback in the near term, we expect to be able to take maximum advantage of the significant undervaluation of our equity,” added Flexon.

To execute the first phase of the share repurchase plan, within the limitations contained in the Company’s credit agreement and bond indenture, the Company will form two wholly owned subsidiaries to hold the repurchased shares. The initial capitalization of the subsidiaries includes $166 million in cash from the NRG parent. Additionally, the subsidiaries will enter into non-recourse debt and preferred purchase agreements with units of Credit Suisse for an incremental $334 million—funded through $250 million in debt and $84 million of preferred equity. Neither the debt nor the preferred will be recourse to NRG. The shares, which will be repurchased between now and year end, will serve as collateral for the debt. Periodic funding will be drawn pro rata from the subsidiary’s $166 million in cash received from the parent and the $334 million in debt and preferred financings from Credit Suisse. The difference between the $334 million of facilities and the $400 million of maturities reflects accrued interest and dividends to be paid at maturity. Credit Suisse will retain the economic benefit of share price appreciation in excess of a 20 percent compound annual growth rate.

FORNRG — Increased Targets
The Company is also announcing today the expansion and extension of the Focus on ROIC@NRG (FORNRG) program. NRG achieved $39 million of related savings in 2005 and expects to have cumulative savings of $81 million by year end 2006. With the addition of NRG Texas, the current target of $105 million improvement in EBITDA by 2008 is being increased to $200 million of recurring EBITDA improvement plus an additional $50 million of incremental cash benefit by 2009 recognizing:

•		continued benefits from improved reliability and reduced EFOR results; and

•		cost synergies and purchasing related initiatives, which are driving enhanced returns for NRG Texas.

Repowering Update — Analyst Conference
On June 21, 2006, NRG announced a comprehensive portfolio redevelopment effort, which involves the development, financing, construction and operation of up to 10,500 megawatts (MW) of new multi-fuel, multi-technology generation capacity at NRG’s existing domestic sites to meet the growing demand for (principally) non gas-fired generation in all of the Company’s core domestic

markets. NRG expects to provide additional detail with respect to this program at our first Analyst Conference to be held October 16-18, 2006.

Outlook
The Company is lowering 2006 adjusted EBITDA guidance from $1,600 million to $1,500 million to reflect:

•		The classification of Flinders as discontinued operations (approximately $45 million)

•		Development expenses associated with Requests for Proposals for several repowering and development initiatives (approximately $10 million);

•		Mild weather in the first quarter; and

•		Lower power prices due to the steep decline in 2006 natural gas prices.

Although 2006 natural gas calendar strip prices have declined over 30 percent from fourth quarter 2005 levels, the net impact on our previous 2006 adjusted EBITDA guidance is approximately three percent, demonstrating the benefit of our actively managed hedging program and our diverse asset base. Cash flow from operations guidance is being reduced from $1,380 million to $1,324 million. The reduction reflects an August close for the Flinders sale. Achieving our revised target remains dependent on several factors, including normally seasonal weather and stable power prices, particularly for the balance of the third quarter.

Table 3: 2006 Reconciliation of Adjusted EBITDA Guidance ($ in millions)


	2006 guidance
Adjusted EBITDA ⁽¹⁾		1,500
MtM adjustment		116

Adjusted EBITDA, including MtM		1,616
Interest payments		(439	)
Income tax		(13	)
Other funds used by operations		(236	)
Return of posted collateral		407
Working capital changes		(11	)

Cash flow from operations		1,324

⁽¹⁾Adjusted EBITDA and cash flow from operations guidance reflects 100 percent ownership of WCP and the sale of Rocky Road.

Earnings Conference Call
On August 1, 2006, NRG will host a conference call at 9:00 a.m. eastern to discuss these results. To access the live web cast 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. now owns and operates a diverse portfolio of power-generating facilities, primarily in Texas and the Northeast, South Central and Western 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 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 our Adjusted EBITDA and Cash Flow from Operations guidance, expected earnings, future growth and financial performance, expected results of the NRG Texas and WCP integration processes, the expected timing of sales of our assets in Australia, and the expected benefits and timing of the capital allocation program 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, changes in government regulation of markets and of environmental emissions, 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 companywide processes, our ability to achieve the benefits from the NRG Texas and WCP integration efforts, our inability to close the sales of Australia assets as described herein, and our ability to achieve the expected benefits of the capital allocation program.

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 and cash flow from operations are estimates as of today’s date, August 1, 2006 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 results to differ materially from those contemplated in the forward-looking statements included in this news release should be considered in connection with information regarding risks and uncertainties that may affect NRG’s future results included in NRG’s filings with the Securities and Exchange Commission at www.sec.gov.

# # #

More information on NRG is available at www.nrgenergy.com


Contacts:

	Media:	Investors:
	Meredith Moore	Nahla Azmy
	609.524.4522	609.524.4526

		Kevin Kelly
		609.524.4527

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three months ended June 30						Six months ended June 30
(In millions, except for per share amounts)	2006			2005			2006			2005

Operating Revenues
Revenues from majority-owned operations	$	1,423		$	522		$	2,513		$	1,070

Operating Costs and Expenses
Cost of majority-owned operations		746			387			1,447			796
Depreciation and amortization		178			41			297			83
General, administrative and development		83			50			143			97
Corporate relocation charges		—			1			—			4

Total operating costs and expenses		1,007			479			1,887			980

Operating Income		416			43			626			90

Other Income (Expense)
Equity in earnings of unconsolidated affiliates		8			16			29			53
Write downs and gains on sales of equity method investments		14			12			11			12
Other income, net		8			6			88			31
Refinancing expense		—			—			(178	)		(35	)
Interest expense		(152	)		(46	)		(266	)		(98	)

Total other expense		(122	)		(12	)		(316	)		(37	)

Income From Continuing Operations Before Income Taxes		294			31			310			53
Income Tax Expense		90			8			89			14

Income From Continuing Operations		204			23			221			39
Income/(loss) from discontinued operations, net of income tax expense/(benefit)		(1	)		1			8			8

Net Income		203			24			229			47
Dividends for Preferred Shares		13			4			23			8

Income Available for Common Stockholders	$	190		$	20		$	206		$	39

Weighted Average Number of Common Shares Outstanding — Basic		137			87			127			87
Income From Continuing Operations per Weighted Average Common Share — Basic	$	1.39		$	0.22		$	1.55		$	0.35
Income/(loss) From Discontinued Operations per Weighted Average Common Share — Basic		(0.01	)		0.01			0.06			0.09

Net Income per Weighted Average Common Share — Basic	$	1.38		$	0.23		$	1.61		$	0.44

Weighted Average Number of Common Shares Outstanding — Diluted		159			88			148			88
Income From Continuing Operations per Weighted Average Common Share — Diluted	$	1.26		$	0.21		$	1.47		$	0.34
Income/(loss) From Discontinued Operations per Weighted Average Common Share — Diluted		—			0.01			0.05			0.09

Net Income per Weighted Average Common Share — Diluted	$	1.26		$	0.22		$	1.52		$	0.43

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30,		December 31,
	2006		2005
(in millions, except shares and par value)	(unaudited)

ASSETS
Current Assets
Cash and cash equivalents	$	957	$	493
Restricted cash		58		49
Accounts receivable, less allowance for doubtful accounts of $2 and $2		473		259
Inventory		402		242
Derivative instruments valuation		528		387
Collateral on deposits in support of energy risk and management activities		209		438
Prepayments and other current assets		187		188
Current assets — held-for-sale		—		43
Current assets — discontinued operations		96		98

Total current assets		2,910		2,197

Property, plant and equipment, net of accumulated depreciation of $668 and $343		11,815		2,620

Other Assets
Equity investments in affiliates		307		603
Notes receivable, less current portion		480		458
Goodwill		1,462		—
Intangible assets, net of accumulated amortization of $131 and $79		1,182		257
Nuclear decommissioning trust fund		326		—
Derivative instruments valuation		191		18
Funded letter of credit		—		350
Deferred income taxes		42		26
Other non-current assets		242		124
Intangible assets held-for-sale		66		—
Non-current assets — discontinued operations		419		813

Total other assets		4,717		2,649

Total Assets	$	19,442	$	7,466

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	125	$	95
Accounts payable		340		247
Derivative instruments valuation		640		679
Accrued expenses and other current liabilities		467		174
Current liabilities — discontinued operations		58		162

Total current liabilities		1,630		1,357

Other Liabilities
Long-term debt and capital leases		7,631		2,410
Nuclear decommissioning reserve		226		—
Nuclear decommissioning trust liability		325		—
Deferred income taxes		152		129
Derivative instruments valuation		398		56
Out-of-market contracts		2,320		298
Other non-current liabilities		378		170
Non-current liabilities — discontinued operations		278		568

Total non-current liabilities		11,708		3,631

Total Liabilities		13,338		4,988

Minority Interest		1		1
3.625% Convertible perpetual preferred stock (at liquidation value, net of issuance costs)		246		246
Commitments and Contingencies
Stockholders’ Equity
Preferred stock (at liquidation value, net of issuance costs)		892		406
Common Stock; $.01 par value; 500,000,000 shares authorized; 136,979,082 and 80,701,888 outstanding		1		1
Additional paid-in capital		4,454		2,431
Retained earnings		374		261
Less treasury stock, at cost — 0 and 19,346,788 shares		—		(663	)
Accumulated other comprehensive income/(loss)		136		(205	)

Total stockholders’ equity		5,857		2,231

Total Liabilities and Stockholders’ Equity	$	19,442	$	7,466

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six months ended June 30,
(In millions)	2006			2005

Cash Flows from Operating Activities
Net income	$	229		$	47
Adjustments to reconcile net income to net cash provided by operating activities
Distributions in excess of equity in earnings of unconsolidated affiliates		(13	)		16
Depreciation and amortization		308			96
Amortization of financing costs and debt discount		16			5
Amortization of intangibles and out-of-market contracts		(211	)		15
Amortization of unearned equity compensation		9			5
Write-off of deferred financing costs and debt premium		47			(8	)
Write down and (gains)/losses on sale of equity method investments		(11	)		(12	)
Deferred income taxes		96			(4	)
Nuclear decommissioning trust liability		3			—
Minority interest		—			1
Loss on sale of equipment		3			—
Unrealized (gains)/losses on derivatives		(114	)		82
Gain on legal settlement		(67	)		(14	)
Gain on sale of discontinued operations		(10	)		—
Gain on sale of emission allowances		(67	)		—
Collateral deposit payments in support of energy risk management activities		272			(179	)
Cash provided by changes in other working capital, net of acquisition and disposition affects		114			41

Net Cash Provided by Operating Activities		604			91
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, net of cash acquired		(4,303	)		—
Acquisition of WCP, net of cash acquired		(25	)		—
Decrease/(Increase) in restricted cash and trust funds, net		(9	)		26
Decrease in notes receivable		14			93
Investments in nuclear decommissioning trust fund securities		(106	)		—
Purchases of emission allowances		(78	)		—
Sales of emission allowances		84			—
Proceeds from sale of equipment		1			—
Proceeds on sale investments		86			65
Proceeds on sale of discontinued operations		15			—
Proceeds from sales of nuclear decommissioning trust fund securities		103			—
Return of capital from (investments in) equity method investments and projects		—			1
Capital expenditures		(74	)		(37	)

Net Cash Provided by Investing Activities		(4,292	)		148
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders		(23	)		(8	)
Funded letter of credit		350			—
Issuance of common stock, net of issuance costs		986			—
Issuance of preferred shares, net of issuance costs		486			—
Deferred debt issuance costs		(164	)		(1	)
Proceeds from issuance of long-term debt, net		7,175			204
Principal payments on short and long-term debt		(4,662	)		(722	)

Net Cash Used by Financing Activities		4,148			(527	)

Change in Cash from Discontinued Operations		1			(3	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		3			(1	)

Net Increase (Decrease) in Cash and Cash Equivalents		464			(292	)
Cash and Cash Equivalents at Beginning of Period		493			1,071

Cash and Cash Equivalents at End of Period	$	957		$	779

See notes to condensed consolidated financial statements.

Appendix Table A-1: Second Quarter 2006 Regional EBITDA Reconciliation
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss)


(dollars in millions)	Texas			Northeast			South Central			Western		Other NA			Australia		Other Int’l			Other			Total

Net Income (Loss)		256			51			(6	)		8		2			3		13			(124	)		203

Plus:
Income Tax		36			—			—			—		—			1		3			50			90
Interest Expense		38			15			9			—		3			—		2			77			144
Amortization of Finance Costs		—			—			—			—		—			—		—			6			6
Amortization of Debt (Discount)/Premium		—			—			1			—		1			—		—			—			2
Depreciation Expense		131			22			15			1		2			—		—			7			178
Amortization of Power Contracts		(225	)		—			(5	)		—		—			—		—			—			(230	)
Amortization of Fuel Contracts		11			—			—			—		—			—		—			—			11
Amortization of Emission Credits		6			2			1			—		—			—		—			—			9

EBITDA		253			90			15			9		8			4		18			16			413
(Income) Loss from Discontinued Operations		—			—			—			—		(1	)		2		—			—			1
Write-Down and (Gain)/Losses on Sales of Equity Method Investments		—			—			—			—		(11	)		—		(3	)		—			(14	)
Acquisition Integration Costs		—			—			—			—		—			—		—			5			5
Station Service Reserve Reversal		—			(15	)		—			—		—			—		—			—			(15	)
Mirant Defense		—			—			—			—		—			—		—			6			6

Adjusted EBITDA		253			75			15			9		(4	)		6		15			27			396

Appendix Table A-1: Second Quarter 2005 Regional EBITDA Reconciliation
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss)


(dollars in millions)	Northeast		South Central			Western		Other NA			Australia		Other Int’l			Other			Total

Net Income (Loss)		39		(7	)		6		(5	)		4		19			(32	)		24

Plus:
Income Tax		—		—			—		1			1		4			2			8
Interest Expense		—		1			—		4			—		1			38			44
Amortization of Finance Costs		—		—			—		—			—		—			1			1
Amortization of Debt (Discount)/Premium		—		1			—		1			—		—			(1	)		1
Depreciation Expense		18		15			—		1			—		1			6			41
Amortization of Power Contracts		—		(3	)		—		2			—		—			—			(1	)
Amortization of Emission Credits		2		1			—		—			—		—			—			3

EBITDA		59		8			6		4			5		25			14			121
(Income) Loss from Discontinued Operations		—		—			—		(2	)		1		—			—			(1	)
Write-Down and (Gain)/Losses on Sales of Equity Method Investments		—		—			—		—			—		(12	)		—			(12	)

Adjusted EBITDA		59		8			6		2			6		13			14			108

Appendix Table A-2: YTD 2006 Regional EBITDA Reconciliation
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss)


(dollars in millions)	Texas			Northeast			South Central			Western			Other NA			Australia		Other Int’l			Other			Total

Net Income (Loss)		274			183			29			6			68			8		30			(369	)		229

Plus:
Income Tax		11			—			—			(2	)		1			3		10			66			89
Interest Expense		64			34			19			—			7			—		4			125			253
Amortization of Finance Costs		—			—			—			—			—			—		—			10			10
Amortization of Debt (Discount)/Premium		—			—			1			—			2			—		—			—			3
Refinancing Expense		—			—			—			—			—			—		—			178			178
Depreciation Expense		205			44			30			1			4			—		1			12			297
Amortization of Power Contracts		(263	)		—			(8	)		—			—			—		—			—			(271	)
Amortization of Fuel Contracts		37			—			—			—			—			—		—			—			37
Amortization of Emission Credits		17			9			3			—			—			—		—			(2	)		27

EBITDA		345			270			74			5			82			11		45			20			852
(Income) Loss from Discontinued Operations		—			—			—			—			(9	)		1		—			—			(8	)
Write-Down and (Gain)/Losses on Sales of Equity Method Investments		—			—			—			—			(8	)		—		(3	)		—			(11	)
Bourbonnais Legal Settlement		—			—			—			—			(67	)		—		—			—			(67	)
Acquisition Integration Costs		—			—			—			—			—			—		—			7			7
Audrain Bad Debt Reserve		—			—			—			—			—			—		—			2			2
Station Service Reserve Reversal		—			(15	)		—			—			—			—		—			—			(15	)
Mirant Defense		—			—			—			—			—			—		—			6			6

Adjusted EBITDA		345			255			74			5			(2	)		12		42			35			766

Appendix Table A-2: YTD 2005 Regional EBITDA Reconciliation
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss)


(dollars in millions)	Northeast		South Central			Western		Other NA			Australia			Other Int’l			Other			Total

Net Income (Loss)		72		2			9		(10	)		14			61			(101	)		47

Plus:
Income Tax		—		—			—		1			3			8			2			14
Interest Expense		—		4			—		7			—			4			78			93
Amortization of Finance Costs		—		—			—		—			—			—			3			3
Amortization of Debt (Discount)/Premium		—		1			—		2			—			—			(1	)		2
Refinancing Expense		—		—			—		—			—			—			35			35
Depreciation Expense		37		30			—		3			—			2			11			83
Amortization of Power Contracts		—		(6	)		—		5			—			—			—			(1	)
Amortization of Emission Credits		3		3			—		—			—			—			—			6

EBITDA		112		34			9		8			17			75			27			282
(Income) from Discontinued Operations		—		—			—		(3	)		(5	)		—			—			(8	)
Corporate Relocation charges		—		—			—		—			—			—			4			4
Write-Down and (Gain)/Losses on Sales of Equity Method Investments		—		—			—		—			—			(12	)		—			(12	)
Proceeds Received from Crockett Contingency		—		—			—		(4	)		—			—			—			(4	)
Gain on TermoRio Settlement		—		—			—		—			—			(14	)		—			(14	)

Adjusted EBITDA		112		34			9		1			12			49			31			248

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.