NRG Energy (NRG) 8-K Results of Operations and Financial Condition

NEWS
RELEASE

FOR IMMEDIATE RELEASE

NRG Energy Reports Fourth Quarter and Full-Year 2005 Results
and Subsequent Events
 

• Successfully completed Texas Genco acquisition—for $6.1 billion and $2.7 billion in assumed debt—and associated balance sheet recapitalization on February 2, 2006;

• Agreed to acquire Dynegy’s 50% interest in West Coast Power (904 MW net) and to sell to Dynegy our 50% interest in Rocky Road (165 MW net) for a net purchase price of $160 million (FERC approval received March 1, 2006);

• Agreed to sell the Audrain power plant (577 MW) to Ameren which finalizes the elimination of $412 million of liabilities at closing (approval pending);

• Fourth quarter adjusted EBITDA results of $202 million, before the impact of mark-to-market (MtM) adjustments;

• Full-year adjusted EBITDA of $722 million before the impact of MtM adjustments; and

• Reaffirms 2006 adjusted EBITDA guidance and raises cash flow outlook.

Princeton, NJ; (March 7, 2006)—NRG Energy, Inc. (NYSE: NRG) today reported net income of $64 million for the fourth quarter, or $0.68 per diluted share, compared to $19 million or $0.18 per diluted share for the same period in the prior year. Net income for 2005 totaled $84 million or $0.75 per diluted share versus $186 million or $1.85 per diluted share in 2004.

The quarter-on-quarter increase was driven primarily by higher generation and more favorable market pricing in the Northeast region, coupled with lower G&A (approximately $25 million) and reduced interest and refinancing costs ($56 million). Full-year results for 2005 versus 2004 were favorably affected by higher energy prices, increased generation from our New York City assets, lower general and administrative costs, and reduced interest and refinancing expenses. Offsetting these improvements was $119 million of net domestic MtM losses related to the Company’s open asset-backed hedges that are economically neutral to the Company. In addition, non-core asset divestitures and other changes within the portfolio also accounted for a portion of the decline.

“This was an eventful year for NRG, and we are a stronger and better positioned company at all levels today—commercial, operations, regulatory and financial—than at any time in our past,” said David Crane, NRG’s President and Chief Executive Officer. “This year we built on the Company’s strong foundation to extend NRG’s strategic and competitive advantages within the industry. We have continued to focus on commercial and operational excellence—through such programs asFORNRG, strategic hedging and risk management policies, disciplined acquisitions and divestitures—while maintaining our commitment to prudent balance sheet management and return of capital to stakeholders.”

MtM Impacts of Hedging and Trading Activities

In the fourth quarter of 2004 and over the course of 2005, the Company entered into contracts to lock in forward prices for a significant portion of its expected power generation, largely related to our Northeast assets, for the balance of 2005 and calendar year 2006. These hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy sold. While these transactions are predominately economic hedges of the portfolio, a majority of NRG’s current forward sales portfolio

1

are afforded hedge accounting treatment. The sharp rise in forward electricity prices, particularly during the third quarter, led the Company to record $206 million in year-to-date MtM losses through the third quarter associated with our open economic hedged positions. During the fourth quarter 2005, lower forward electricity prices led to a $87 million net reduction in the Company’s MtM loss at year end. Additionally, during the fourth quarter of 2005 we had $27 million in MtM gains resulting from entering into various transactions not tied to specific assets, but to support our overall portfolio.

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	12/31/05			12/31/04			12/31/05		12/31/04
Northeast(1)		146			90			159		112
South Central		14			7			32		23
Australia		(2	)		(4	)		11		11
Western		(25	) (4)		23			3		49
Other North America		(22	)(4)		(13	)		—		18
Other International		16			11			23		20
Alternative Energy, Non-generation, and Other		(35	)(2)		(97	)(3)		12		(18	)
Total	$	92		$	17		$	240	$	215

(1)	Includes net domestic MtM gain of economic hedges totaling $38 million and $60 million in 2005 and 2004, respectively.
(2)	Includes interest and refinancing expense of $46 million and interest income.
(3)	Includes interest and refinancing expense of $89 million and interest income.
(4)	Includes asset impairments/writedowns of $27 million for Saguaro and $20 million for Rocky Road.

Table 2: Full-year Income from Continuing Operations before Taxes and Adjusted EBITDA by region

($in millions)	Income from Continuing						Adjusted EBITDA
	Operations before Taxes
Twelve months ending	12/31/05			12/31/04			12/31/05		12/31/04
Northeast(1)		222			322			299		415
South Central		11			49			71		115
Australia		17			5			61		70
Western		(10	) (4)		65			18		185
Other North America		(36	) (4)		(42	)		9		77
Other International		107			79			96		93
Alternative Energy, Non-generation, and Other		(191	)(2)		(252	)(3)		49		16
Total	$	120		$	226		$	603	$	971

(1)	Includes net domestic MtM loss of economic hedges totaling $119 million in 2005 and MtM gain of $59 million in 2004.
(2)	Includes interest and refinancing expense of $215 million and interest income.
(3)	Includes interest and refinancing expense of $261 million, the $39 million CL&P settlement and interest income.
(4)	Includes asset impairments/writedowns of $27 million for Saguaro and $20 million for Rocky Road.

2

Northeast:For the year, NRG’s Northeast operations benefited from a significant increase in power prices resulting in wider dark spread margins, and higher gas and oil generation output. In addition, since the end of 2005, there have been significant regulatory developments affecting the Company’s Northeast portfolio including:

• On February 1, 2006, the Federal Energy Regulatory Commission (FERC) approved the Company’s Reliability-Must-Run (RMR) contracts for NRG’s Middletown, Montville, and Devon (Connecticut) plants. The new RMR agreements continue until the units are no longer needed for reliability or a suitable market alternative is implemented.

• On February 9, 2006, the New York-Independent System Operator (NYISO) increased the New York City locational capacity requirement to 83% from 80%.

• On March 6, 2006, the FERC settlement judge filed a comprehensive LICAP case settlement with the Commission. The broad terms cover multiyear interim payments for all generators in New England and provide for a forward procurement capacity market design. The Commission is expected to issue a decision by early summer.

The Company expects the net impact of these regulatory changes on the financial performance of our Northeast region to be moderately positive over time.

South Central:Despite improved fourth quarter commercial and operational performance, NRG’s South Central results were down year-on-year. This decline was largely due to increased purchased power costs to meet larger than anticipated load following contract obligations, due to higher demand from warmer than normal weather conditions and increased forced unit outages at the Big Cajun II facility.

Western:Lower results are primarily attributable to the expiration of the California Department of Water Resources (CDWR) contract at the end of 2004.

• A tolling agreement for El Segundo’s total capacity from May 1, 2006 through April 30, 2008 has been executed with a major load serving entity. The CAISO designated Encina unit 4 as an RMR unit. If approved by FERC, Encina units 4 and 5 will receive partial cost recovery under RMR and both units will be available in the market for 2006. The Red Bluff and Chowchilla facilities have received capacity contracts for the period April 1, 2006 through December 31, 2007.

• In December 2005, NRG entered into an agreement to acquire Dynegy’s 50% ownership interest in West Coast Power and to sell to Dynegy its 50 percent ownership interest in Rocky Road Power LLC for a net purchase price of $160 million. On March 1, 2006, the Company received FERC approval for these transactions. The Company continues to anticipate closing both transactions before April 1, 2006.

Australia:While generation was higher for the year, unseasonably mild summer weather led to weak pool prices in the first quarter 2005 lowering year-on-year results.

• As part of the Company’s focus on value enhancing opportunities, NRG announced on January 5, 2006 that it is exploring strategic alternatives for its Australian assets. We anticipate achieving greater certainty with respect to the likely outcome of this process by the end of the second quarter.

3

FORNRG Update
In May 2005, NRG announcedFORNRG,a comprehensive cost and margin improvement program, consisting of a large number of asset, portfolio and headquarters-specific targeted initiatives. The ultimate objective of this program was to produce $100 million of recurring benefits by 2008.

As of December 31, 2005,FORNRG achieved $39 million of related savings, exceeding our $30 million first year savings target. For 2006, NRG expects to achieve approximately $59 million of recurring cumulative savings, principally through improved performance at NRG’s coal-fired plants. The $59 million target is up from our prior estimate of $54 million, reflecting the recurring benefit of our first year’s success with the cumulative goal being $105 million.

“While it is still too early to reach definitive conclusions, the exceptional post-outage performance of those coal-fired units, which were subject to major planned outages during the fall, gives us a high degree of confidence that we will meet or exceed our second yearFORNRG target,” Crane continued.

Liquidity and Capital Resources

Table 3: Corporate Liquidity

	Estimated
	Post-Acquisition of
	Texas Genco		Pre-Acquisition of Texas Genco
($ in millions)	2/28/06		12/31/051		12/31/041
Unrestricted Cash:	$	764	$	506	$	1,110
Restricted Cash:		63		64		113
Total Cash	$	827	$	570	$	1,223
Letter of Credit Availability		230		38		193
Revolver Availability		845		150		150
Total Current Liquidity	$	1,902	$	758	$	1,566

¹ These amounts have not been reclassified for discontinued operations.

NRG’s hedging and trading activities require credit collateral support when prices change from the levels where trades were executed. Collateral supporting these activities at December 31, 2005 totaled $530 million, of which $438 million was in cash and $92 million was letters of credit. Any outstanding collateral is returned when the underlying trades settle. Cash collateral returned between year end 2005 and March 3, 2006 was $271 million.

To fund the Texas Genco acquisition, in February 2006 NRG closed the following financings:

• Senior secured credit facility in the aggregate amount of $5.575 billion to replace its existing senior credit facility. The senior secured credit facility consists of a $3.575 billion senior first priority secured term loan facility, and liquidity facilities comprised of $1.0 billion senior first priority secured revolving credit facility and $1.0 billion senior first priority secured letter of credit facility;

• Senior unsecured notes totaling $3.6 billion of borrowings in two tranches: $1.2 billion at a per year rate equal to 7.250% to mature on February 1, 2014 and $2.4 billion at a per year rate equal to 7.375% to mature on February 1, 2016;

• Common stock offering totaling $1 billion, net proceeds of $985 million (20,855,057 shares of common stock at $48.75 per share); and

4

• Mandatory convertible preferred stock offering totaling $500 million, net proceeds of $485 million (2,000,000 shares at an offering price of $250 per share). Shares of the mandatory convertible preferred stock will be mandatorily convertible into NRG common stock on March 16, 2009.

In addition to the above borrowings and equity issuances, the Company issued 35.4 million shares of common stock to the former owners of Texas Genco. The sellers are prohibited from selling their shares received for the acquisition before August 1, 2006 without NRG’s consent. At closing of the Texas Genco transaction, common shares outstanding totaled approximately 137 million shares.

“NRG’s strong cash flows and our prudent capital allocation enabled us to create significant value for NRG’s stakeholders in the past year,” said Robert Flexon, NRG’s Executive Vice President and Chief Financial Officer. “In addition to reducing debt and executing a $250 million accelerated share buyback, we invested in a number of growth opportunities, including the recently completed acquisition of Texas Genco, andFORNRG initiatives to improve the long-term economic and environmental performance of our assets. In the coming year, we expect continued debt reduction, investments in strategic growth opportunities and the return of capital to our shareholders to be our capital allocation priorities.”

NRG Texas Integration
While the Company has owned Texas Genco, now known as NRG Texas, for only three weeks, the Company is confident that it will achieve its top integration priorities in a timely fashion. The Company will report more fully on the integration progress during our next quarterly earnings call.

Outlook
The Company reaffirmed its adjusted EBITDA guidance outlook for 2006—adjusted EBITDA of $1.6 billion—and is increasing its cash flow from operations guidance by $140 million to nearly $1.4 billion. The improved outlook for cash flow from operations reflects lower interest rates and the timing of cash interest payments of our new debt facilities. With respect to our adjusted EBITDA and cash flow from operations guidance, our outlook, as always, is based on normal weather patterns going forward. As such, if the unusually moderate weather experienced to date in 2006 should continue through the remainder of the winter or if we experience an unusually moderate summer, this would likely result in a declining 2006 outlook for adjusted EBITDA and cash flow from operations. Adjusted EBITDA and cash flow from operations guidance excludes the net impact of the pending West Coast Power and Rocky Road transactions.

Table 4: 2006 Reconciliation of Adjusted EBITDA Guidance ($ in millions)

	2006 guidance
Adjusted EBITDA	$	1,600
MtM adjustment		116
Adjusted EBITDA, including MtM	$	1,716
Interest payments		(475	)
Income tax		(15	)
Other funds used by operations		(207	)
Return of posted collateral *		405
Working capital changes		(37	)
Cash flow from operations *	$	1,387

* The 2006 cash flow from operations includes the return of $405 million of cash collateral that was outstanding at the end of 2005 for transactions that will settle in 2006.

5

Earnings Conference Call
On March 7, 2006, 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 athttp://www.nrgenergy.comand 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.

Annual Meeting of Shareholders
NRG’s Annual Meeting of Shareholders will be held on Friday, April 28, 2006 at 9:30 a.m. eastern at the Hotel DuPont in Wilmington, Delaware.

About NRG
With the recent acquisition of Texas Genco LLC, NRG Energy, Inc. now owns and operates a diverse portfolio of power-generating facilities, primarily in Texas, 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, but are not limited to, expected earnings, future growth and financial performance, anticipated timing of the WCP, Rocky Road and Audrain transactions, expected timing and results of the NRG Texas integration process, 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 companywide processes, the timing of and the ability to complete the WCP, Rocky Road and Audrain transactions and our ability to achieve NRG Texas integration priorities.

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, March 7, 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

6

Contacts:
Meredith Moore	Nahla Azmy
Media Relations	Investor Relations
609.524.4522	609.524.4526
	Katy Sullivan
	Investor Relations
	609.524.4527

7

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, including per share amounts.

	Three Months Ended						Three Months Ended
										Diluted
(Dollars in millions, except per share amounts)	12/31/2005			Diluted EPS			12/31/2004			EPS
Net Income	$	64		$	0.68		$	19		$	0.18
Plus:
(Income) Loss from discontinued operations, net of tax		6			0.06			(2	)		(0.01	)
Corporate relocation charges, net of tax		—			—			2			0.02
Reorganization items, net of tax		—			—			(7	)		(0.07	)
Impairment charges, net of tax		—			—			2			0.02
Termo Rio legal matters, net of tax		2			0.02			—			—
Gain on settlement, net of tax		(5	)		(0.05	)		—			—
Gain on sale of land, net of tax		(2	)		(0.03	)		—			—
Write downs and (gains)/losses on sales of equity method investments, net of tax		28			0.30			1			0.01
Adjusted Net Income	$	93		$	0.98		$	15		$	0.15
Note: Diluted EPS in 2005 is after adjusting for preferred stock dividends

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, including per share amounts.

	Twelve Months Ended						Twelve Months Ended
										Diluted
(Dollars in millions, except per share amounts)	12/31/2005			Diluted EPS			12/31/2004			EPS
Net Income	$	84		$	0.75		$	186		$	1.85
Plus:
Income from discontinued operations, net of tax		(7	)		(0.09	)		(25	)		(0.25	)
Corporate relocation charges, net of tax		3			0.04			10			0.10
Reorganization items, net of tax		—			—			(8	)		(0.08	)
Impairment charges, net of tax		4			0.05			27			0.27
FERC-authorized settlement with CL&P, net of tax		—			—			(23	)		(0.23	)
Proceeds received on Crockett contingency, net of tax		(2	)		(0.02	)		—			—
TermoRio legal matters, net of tax		(6	)		(0.07	)		—			—
Gain on settlement, net of tax		(5	)		(0.05	)		—			—
Gain on sale of land, net of tax		(2	)		(0.03	)		—			—
Write down of note receivable, net of tax		—			—			2			0.03
Write downs and (gains)/losses on sales of equity method investments, net of tax		31			0.36			10			0.10
Adjusted Net Income	$	100		$	0.94		$	179		$	1.79
Note: Diluted EPS in 2005 is after adjusting for preferred stock dividends

8

Appendix Table A-3: Fourth Quarter 2005 Regional EBITDA Reconciliation

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

				South												Other
Three months ending December 31, 2005	Northeast			Central			Western			Other NA			Australia			Int'l		Other			Total
Net Income (Loss):	$	146		$	17		$	(25	)	$	(25	)	$	(2	)	$	11	$	(58	)	$	64
Plus:
Income Tax Expense/(Benefit)		—			—			—			2			—			5		15			22
Interest Expense		—			1			—			3			3			3		22			32
Amortization of Finance Costs		—			—			—			—			—			—		13			13
Amortization of Debt Discount/(Premium)		—			1			—			1			—			—		(1	)		1
Refinancing Expenses		—			—			—			—			—			—		12			12
Depreciation Expense		18			16			1			2			7			1		5			50
Amortization of Power Contract		—			(4	)		—			—			3			—		—			(1	)
Amortization of Emission Credits		2			1			—			—			—			—		—			3
EBITDA	$	166		$	32		$	(24	)	$	(17	)	$	11		$	20	$	8		$	196
Loss from Discontinued Operations		—			—			—			1			—			—		4			5
Write Down and (Gain)/Losses on Sales of Equity Method Investments		—			—			27			20			—			—		—			47
Gain on settlement		(7	)		—			—			—			—			—		—			(7	)
Gain on sale of land		—			—			—			(4	)		—			—		—			(4	)
TermoRio legal matters		—			—			—			—			—			3		—			3
Adjusted EBITDA	$	159		$	32		$	3		$	—		$	11		$	23	$	12		$	240

Appendix Table A-4: Fourth Quarter 2004 Regional EBITDA Reconciliation

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

			South											Other
Three months ending December 31, 2004	Northeast		Central			Western		Other NA			Australia			Int'l		Other			Total
Net Income (Loss):	$	91	$	7		$	22	$	-		$	(2	)	$	10	$	(109	)	$	19
Plus:
Income Tax Expense/(Benefit)		—		—			—		(6	)		(3	)		1		8			—
Interest Expense		—		2			—		7			4			8		47			68
Amortization of Finance Costs		—		—			—		—			—			—		2			2
Amortization of Debt Discount/Premium		—		1			—		3			—			—		(1	)		3
Refinancing Expenses		—		—			—		—			—			—		41			41
Depreciation Expense		19		15			—		2			7			1		6			50
WCP CDWR Contract Amortization		—		—			26		—			—			—		—			26
Amortization of Power Contracts		—		(3	)		1		3			5			—		—			6
Amortization of Emission Credits		2		1			—		—			—			—		—			3
EBITDA	$	112	$	23		$	49	$	9		$	11		$	20	$	(6	)	$	218
Income from Discontinued Operations		—		—			—		5			—			—		(4	)		1
Corporate Relocation charges		—		—			—		—			—			—		4			4
Reorganization items		—		—			—		—			—			—		(12	)		(12	)
Impairment charges		—		—			—		2			—			—		—			2
Write Downs and (Gain)/Loss on Sales of Equity Investments		—		—			—		2			—			—		—			2
Adjusted EBITDA	$	112	$	23		$	49	$	18		$	11		$	20	$	(18	)	$	215

9

Appendix Table A-5: Full-year 2005 Regional EBITDA Reconciliation

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

				South												Other
Twelve Months ending December 31, 2005	Northeast			Central			Western			Other NA			Australia			Int'l			Other			Total
Net Income (Loss):	$	222		$	11		$	(10	)	$	(39	)	$	15		$	89		$	(204	)	$	84
Plus:
Income Tax Expense		—			—			—			4			2			18			19			43
Interest Expense		—			7			—			13			13			8			134			175
Amortization of Finance Costs		—			—			—			—			—			—			17			17
Amortization of Debt Discount/(Premium)		—			2			—			5			—			—			(2	)		5
Refinancing Expense		—			—			—			—			(10	)		—			66			56
Depreciation Expense		74			61			1			7			27			4			20			194
Amortization of Power Contracts		—			(14	)		—			5			14			—			—			5
Amortization of Emission Credits		10			4			—			—			—			—			(1	)		13
EBITDA	$	306		$	71		$	(9	)	$	(5	)	$	61		$	119		$	49		$	592
Income from Discontinued Operations		—			—			—			(1	)		—			—			(6	)		(7	)
Corporate Relocation charges								—			—			—			—			6			6
Impairment charges		—			—			—			6			—			—						6
Gain on settlement		(7	)		—			—			—			—			—			—			(7	)
Gain on sale of land		—			—			—			(4	)		—			—			—			(4	)
TermoRio legal matters		—			—			—			—			—			(11	)		—			(11	)
Gain on Crockett contingency		—			—			—			(3	)		—			—			—			(3	)
Write Down and (Gains)/Losses on Sales of Equity Method Investments		—			—			27			16			—			(12	)		—			31
Adjusted EBITDA	$	299		$	71		$	18		$	9		$	61		$	96		$	49		$	603

10

Appendix Table A-6: Full-year 2004 Regional EBITDA Reconciliation

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

			South											Other
Twelve months ending December 31, 2004	Northeast		Central			Western		Other NA			Australia			Int'l			Other			Total
Net Income (Loss):	$	322	$	49		$	65	$	(18	)	$	10		$	78		$	(320	)	$	186
Plus:
Income Tax Expense/(Benefit)		—		—					(10	)		(5	)		13			67			65
Interest Expense		1		6					30			12			11			184			244
Amortization of Finance Costs		—		—			—		—			—			—			9			9
Amortization of Debt Discount/(Premium)		—		3			—		15			(1	)		—			(4	)		13
Refinancing expense		—		—			—		—			—			—			72			72
Depreciation Expense		73		62			1		21			24			3			24			208
WCP CDWR contract amortization		—		—			116		—			—			—			—			116
Amortization of power contracts		6		(14	)		3		10			29			—			1			35
Amortization of emission credits		13		5			—		—			—			—			—			18
EBITDA	$	415	$	111		$	185	$	48		$	69		$	105		$	33		$	966
(Income)/ Loss from discontinued operations		—		—			—		(14	)		—			(12	)		1			(25	)
Corporate Relocation Charges							—		—			—			—			16			16
Reorganization Items				1			—					—			—			(14	)		(13	)
Impairment charges		—		3			—		27			—			—			15			45
Write down of notes receivable		—		—			—		5			—			—			—			5
FERC-authorized settlement with CL&P		—		—			—		—			—			—			(39	)		(39	)
Write Downs, (Gain)/Loss on Sales of Equity Investments		—		—			—		11			1			—			4			16
Adjusted EBITDA	$	415	$	115		$	185	$	77		$	70		$	93		$	16		$	971

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

11

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.

12

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

	Reorganized NRG
	December 31,		December 31,
	2005		2004
	(In millions, except shares and
	par value)
ASSETS
Current Assets
Cash and cash equivalents	$	506	$	1,104
Restricted cash		64		110
Accounts receivable-trade, less allowance for doubtful accounts of $2 and $1		280		270
Accounts receivable-affiliate		4		—
Current portion of notes receivable and capital lease		25		85
Property taxes receivable		43		37
Inventory		260		247
Derivative instruments valuation		404		80
Collateral on deposit in support of energy risk management activities		438		33
Deferred income taxes		4		—
Prepayments and other current assets		125		136
Current assets — held for sale		43		—
Current assets — discontinued operations		1		17
Total current assets		2,197		2,119
Property, Plant and Equipment, net		3,039		3,158
Other Assets
Equity investments in affiliates		603		735
Notes receivable, less current portion — affiliates, net		103		124
Notes receivable and capital lease, less current portion, net		355		440
Intangible assets, net of accumulated amortization of $79 and $55		257		294
Derivative instruments valuation		22		42
Funded letter of credit		350		350
Deferred income tax		26		34
Other assets		125		111
Non-current assets — discontinued operations		354		457
Total other assets		2,195		2,587
Total Assets	$	7,431	$	7,864

13

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS — (Continued)

	Reorganized NRG
	December 31,			December 31,
	2005			2004
	(In millions, except shares and
	par value)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	101		$	511
Accounts payable — trade		268			209
Accounts payable — affiliates		—			5
Derivative instruments valuation		692			17
Other bankruptcy settlement		3			6
Accrued expenses		82			57
Other current liabilities		95			109
Current liabilities — discontinued operations		115			173
Total current liabilities		1,356			1,087
Other Liabilities
Long-term debt and capital leases		2,581			2,973
Deferred income taxes		135			169
Postretirement and other benefit obligations		125			116
Derivative instruments valuation		137			148
Out of market contracts		298			319
Other long-term obligations		81			71
Non-current liabilities — discontinued operations		240			288
Total non-current liabilities		3,597			4,084
Total liabilities		4,953			5,171
Minority interest		1			1
3.625% Convertible Perpetual Preferred Stock; $.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs)		246			—
Commitments and Contingencies
Stockholders’ Equity
4% Convertible Perpetual Preferred Stock; $.01 par value; 420,000 shares issued and outstanding at December 31, 2005 and 2004 (at liquidation value of $420, net of issuance costs)		406			406
Common stock; $.01 par value; 100,048,676 and 100,041,935 shares issued and 80,701,888 and 87,041,935 outstanding at December 31, 2005 and 2004, respectively		1			1
Additional paid-in capital		2,431			2,417
Retained earnings		261			197
Less treasury stock, at cost; 19,346,788 and 13,000,000 shares as of December 31, 2005 and 2004, respectively		(663	)		(405	)
Accumulated other comprehensive income/(loss)		(205	)		76
Total stockholders’ equity		2,231			2,692
Total Liabilities and Stockholders’ Equity	$	7,431		$	7,864

14

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

	Reorganized NRG
	Quarter Ended			Quarter Ended			Year Ended			Year Ended
	December 31, 2005			December 31, 2004			December 31, 2005			December 31, 2004
	(In millions, except per share amounts)
Operating Revenues
Revenues from majority-owned operations	$	770		$	577		$	2,708		$	2,348
Operating Costs and Expenses
Cost of majority-owned operations		516			377			2,067			1,489
Depreciation and amortization		50			49			194			208
General, administrative and development		47			74			197			210
Other charges (credits)		—
Corporate relocation charges		—			4			6			16
Reorganization items		—			(11	)		—			(13	)
Restructuring and impairment charges		—			3			6			45
Fresh start reporting adjustments		—			—			—			—
Legal settlement		—			—			—			—
Total operating costs and expenses		613			496			2,470			1,955
Operating Income/(Loss)		157			81			238			393
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		21			43			104			160
Write downs and losses on sales of equity method investments		(47	)		(2	)		(31	)		(16	)
Other income, net		19			10			62			27
Refinancing expenses		(12	)		(42	)		(56	)		(72	)
Interest expense		(46	)		(73	)		(197	)		(266	)
Total other expense		(65	)		(64	)		(118	)		(167	)
Income/(Loss) From Continuing Operations Before Income Taxes		92			17			120			226
Income Tax Expense/(Benefit)		22						43			65
Income/(Loss) From Continuing Operations		70			17			77			161
Income/(Loss) on Discontinued Operations, net of Income Taxes		(6	)		2			7			25
Net Income/(Loss)		64			19			84			186

15

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Reorganized NRG
	Year Ended			Year Ended
	December 31,			December 31,
	2005			2004
Cash Flows from Operating Activities
Net income/(loss)	$	84		$	186
Adjustments to reconcile net income/(loss) to net cash provided by operating activities
Distributions in excess of (less than) equity earnings of unconsolidated affiliates		(8	)		(1	)
Depreciation and amortization		195			215
Reserve for note and interest receivable		—			12
Amortization of financing costs and debt discount/(premium)		22			28
Write-off of deferred financing costs due to refinancings		(8	)		42
Write downs and losses on sales of equity method investments		31			16
Deferred income taxes and investment tax credits		2			57
Unrealized (gains)/losses on derivatives		143			(74	)
Minority interest		1			1
Amortization of intangible assets		17			52
Amortization of unearned equity compensations		12			14
Restructuring and impairment charges		6			45
Fresh start reporting adjustments		—			—
Loss on sale and disposal of assets		4			1
Gain on sale of discontinued operations		(6	)		(23	)
Gain on TermoRio settlement		(14	)		—
Collateral deposit payments in support of energy risk management activities		(405	)		(7	)
Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions
Accounts receivable, net		(8	)		(52	)
Xcel Energy settlement receivable		—			640
Inventory		(14	)		(56	)
Prepayments and other current assets		(35	)		126
Accounts payable		57			50
Accrued expenses		(8	)		(21	)
Creditor pool obligation payments		—			(540	)
Other current liabilities		(8	)		(106	)
Other assets and liabilities		(8	)		40
Net Cash Provided (Used) by Operating Activities		68			645
Cash Flows from Investing Activities
Proceeds from sale of discontinued operations		36			253
Proceeds from sale of investments		70			51
Proceeds from sale of turbines and other property, plant and equipment		9			4
Decrease/(increase) in restricted cash and trust funds		45			(27	)
Decrease/(increase) in notes receivable		107			25
Deferred acquisition costs		(5	)		—
Capital expenditures		(106	)		(119	)
Return of capital/(Investments) in projects		2			(3	)
Net Cash Provided (Used) by Investing Activities		158			184
Cash Flows from Financing Activities
Payment of dividends to preferred shareholders		(20	)		—
Repayment of minority interest obligations		(4	)		—
Accelerated share repurchase payment, net		(250	)		—
Purchase of treasury stock		—			(405	)
Issuance of 4% Preferred Stock, net		—			406
Issuance of 3.625% Preferred Stock, net		246			—
Proceeds from issuance of long-term debt, net		249			1,333
Deferred debt issuance costs		(46	)		(26	)
Funded letter of credit		—			(100	)
Principal payments on short and long-term debt		(1,005	)		(1,492	)
Net Cash Provided (Used) by Financing Activities		(830	)		(284	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		(2	)		3
Change in Cash from Discontinued Operations		8			6
Net Increase/(Decrease) in Cash and Cash Equivalents		(598	)		554
Cash and Cash Equivalents at Beginning of Period		1,104			550
Cash and Cash Equivalents at End of Period	$	506		$	1,104

16