NRG Energy (NRG) 8-K NRG Energy, Inc. Reports 2007 Fourth Quarter and Full-Year Results; Announces Management Changes

FOR IMMEDIATE RELEASE

NRG Energy, Inc. Reports 2007 Fourth Quarter and Full-Year Results;
Announces Management Changes

Fourth Quarter Highlights:

• $541 million of cash flow from operations;

• $518 million of adjusted EBITDA, excluding mark-to-market (MtM) impacts, including discontinued operations; and

• $300 million Term Loan B repayment and $85 million in common share repurchases to initiate 2008 Capital Allocation Plan.

Full-Year 2007 Highlights:

• $1,517 million of cash flow from operations;

• $2,279 million of adjusted EBITDA, excluding MtM impacts, including discontinued operations;

• $408 million in debt repayments and $353 million of common share repurchases;

• $220 million target achieved in cumulativeFORNRG improvements; and

• 1.57 US OSHA safety rate (top quartile).

2008 Outlook:

• $1,500 million of cash flow from operations;

• $2,160 million of adjusted EBITDA (adjusted for sale of ITISA); and

• $300 million share repurchase program approved by Board of Directors, $100 million completed.

Management Changes (effective March 1, 2008):

• Robert Flexon, CFO, to assume newly created position of Chief Operating Officer;

• Kevin Howell, EVP Commercial Operations, to fill vacant position of Chief Administrative Officer;

• Clint Freeland, Treasurer, to become Chief Financial Officer; and

• Mauricio Gutierrez, VP Trading, to become SVP, Commercial Operations.

PRINCETON, NJ (February 28, 2008)—NRG Energy, Inc. (NYSE: NRG) today reported net income from continuing operations for the quarter ended December 31, 2007 of $100 million, or $0.34 per diluted common share, compared to a net loss of $35 million, or $0.19 per diluted common share, for fourth quarter of 2006. The fourth quarter of 2006 included an $85 million after-tax charge on the net settlement of hedges from resetting certain legacy Texas hedges to market (Hedge Reset). Fourth quarter 2007 results include the after-tax impacts of a $24 million reimbursement for development costs for South Texas Project (STP) units 3&4 and a $7 million after-tax impairment charge related to commercial paper investments.

For the year ended December 31, 2007, the Company reported $569 million in net income from continuing operations, or $1.95 per diluted common share, compared to 2006 net income from continuing operations of $543 million, or $1.78 per share. Net after-tax development costs incurred for ourRepoweringNRG program were $61 million in 2007, an after-tax increase of $39 million over

2006 mainly for STP units 3&4. Annual operating results for 2007 were favorably impacted by higher generation and capacity revenues in the Northeast region and the inclusion of an additional month for NRG Texas since this business was acquired on February 2, 2006. This year’s operating results included $21 million of after-tax refinancing expenses, while net income for 2006 was unfavorably impacted by $112 million in after-tax refinancing expenses incurred as part of the NRG Texas acquisition, partially offset by $44 million in after-tax, one-time gains related to the resolution of disputes and litigation.

Net cash flow from operations for the 12 months ended December 31, 2007 was $1,517 million, after posting $125 million of collateral, as compared to adjusted cash flow from operations in 2006 of $1,473 million, after collecting $454 million of collateral. Accordingly, if you adjust both years’ results to disregard movements of cash for purposes of collateral, adjusted cash flow from operations increased by $623 million year on year. Operating cash flows in 2007 benefited by $594 million from higher contract prices resulting from the November 2006 hedge reset transaction.

On December 18, 2007, NRG entered into a sale and purchase agreement to sell its 100% interest in Tosli Acquisition BV, the parent of our Brazilian operating subsidiary Itiquira Energetica S.A. or ITISA, to Brookfield Power, a wholly owned subsidiary of Brookfield Asset Management Inc., for a purchase price of approximately $288 million plus the assumption of ITISA’s net debt, subject to the receipt of regulatory approval and other customary closing conditions. NRG anticipates completing the sale transaction in the first half of 2008. ITISA has been classified as discontinued operations in the fourth quarter of 2007. ITISA’s 2007 annual reported net income of $17 million and EBITDA of $39 million are included within discontinued operations in the following tables, financial statements and Appendix A.

“Our 2007 results demonstrate our ability to stay focused on delivering strong operating results while moving aggressively to position NRG for the future,” commented David Crane, NRG President and Chief Executive Officer. “Particularly gratifying to me was the top quartile safety performance achieved across our entire fleet.”

Regional Segment Review of Results

Table 1: Income (Loss) from Continuing Operations before Income Taxes

($ in millions)	Three Months Ended						Twelve Months Ended
Segment	12/31/07			12/31/06			12/31/07			12/31/06
Texas		188			(13	)		812			752
Northeast		82			69			401			404
South Central		(20	)		16			4			48
West		10			(7	)		36			10
International		28			23			88			91
Thermal		4			1			36			13
Corporate(1)		(115	)		(124	)		(431	)		(453	)
Total		177			(35	)		946			865
Less: MtM forward position accruals(2)		(2	)		58			20			143
Add: Prior period MtM reversals(3)		19			(14	)		128			(116	)
Less: Hedge ineffectiveness(4)		(18	)		(94	)		13			28
Total, net of MtM Impacts		216			(13	)		1,041			578

⁽¹⁾ Includes net interest expense of $439 million and $511 million for 12 months ended 2007 and 2006, respectively, and $109 million and $114 million for the fourth quarter of 2007 and 2006, respectively. Operating income in 2006 also included a $67 million gain related to a settlement agreement.

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(2)	Represents the net domestic mark-to-market (MtM) gains (losses) on economic hedges that do not qualify for hedge accounting treatment.
(3)	Represents the reversal of MtM gains (losses) previously recognized on economic hedges that do not qualify for hedge accounting treatment.
(4)	Represents the ineffectiveness gains (losses) due to a change in correlation predominately between natural gas and power prices on economic hedges that qualify for hedge accounting treatment.

Table 2: Adjusted EBITDA from Continuing Operations, Excluding MtM Impacts

($ in millions)	Three Months Ended						Twelve Months Ended
Segment	12/31/07			12/31/06			12/31/07		12/31/06
Texas		347			191			1,384		788
Northeast		113			62			574		366
South Central		4			39			101		157
West		13			(6	)		41		13
International		29			22			93		89
Thermal		7			6			35		31
Corporate		(6	)		16			12		32
Adjusted EBITDA, net of MtM(1)		507			330			2,240		1,476

⁽¹⁾ Excludes net domestic forward MtM gains (losses), reversals of prior periods net MtM gains (losses) and hedge ineffectiveness gains (losses) on economic hedges as shown in Table 1 above. Detailed adjustments by region are shown in Appendix A.

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 and risk management activities. Although these transactions are predominantly economic hedges of our 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. NRG also hedges power prices using natural gas contracts and, to the extent gas and power prices are not correlated, this ineffectiveness is also reflected in our MtM results. For the fourth quarter of 2007, NRG incurred $2 million of forward domestic net MtM losses accompanied by an $18 million loss on hedge ineffectiveness compared to the fourth quarter of 2006 when we recorded a $58 million forward net MtM gain offset by a $94 million loss on ineffectiveness. For the full year 2007, we recognized $20 million of net forward MtM gains and a $13 million ineffectiveness gain versus the 2006 full year when we recorded $143 million of MtM gains along with a $28 million ineffectiveness gain. Driving the forward MtM gains in 2006 were the lower energy prices mainly due to mild weather for much of the year in the Northeast and the downward trend in natural gas prices during 2006.

Texas:Quarterly 2007 adjusted EBITDA increased $156 million over the fourth quarter of the prior year, largely driven by a $169 million increase in contract prices from the November 2006 hedge reset transaction. Lower prices from other bi-lateral contracts and merchant energy sales reduced fourth quarter energy revenues by $25 million in comparison to 2006. Outstanding performance at STP in the fourth quarter of 2007—of 577,000 megawatt-hours of higher generation—added approximately $27 million in energy margin (energy revenues less fuel costs). Slightly lower fossil generation due to unplanned outages at the Limestone and WA Parish power stations in October and December 2007, respectively, reduced EBITDA by an estimated $14 million. Reduced gas plant dispatch of 18% and a decrease in physical gas sales had a $15 million negative impact on the last quarter of 2007 energy margin.

Quarterly income from continuing operations in 2006 includes a $129 million pre-tax net charge from the hedge reset along with a $94 million loss on hedge ineffectiveness. During 2007, NRG Texas

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incurred $91 million in development costs to prepare the STP units 3&4 Combined Construction and Operating License Application (COLA) submitted in September 2007. These costs were partly offset by a $39 million pre-tax reimbursement from our development partner, City Public Service Board of San Antonio (CPS).

Annual adjusted EBITDA for 2007 increased $596 million over 2006 due in large part to $594 million higher contract revenues from the hedge reset transaction and from the inclusion of a full year of Texas results. Income from continuing operations and EBITDA included 11 months in 2006. January 2007 NRG Texas results contributed $51 million of pre-tax operating income and $123 million of adjusted EBITDA. Baseload generation increased 4%; however, gas generation declined by 2.7 million MWh or 35% versus 2006 due to the cool 2007 summer season. The financial impact of the year-to date reduction in gas generation was partly offset by our commercial hedging activities. The net impact of reduced generation accompanied by lower contract and market prices was a $17 million reduction in 2007 energy margins. Current year results were also reduced by a $30 million increase in plant operations and maintenance expenses at the WA Parish and gas plants as well as increased property taxes.

Northeast:Fourth quarter 2007 regional adjusted EBITDA increased $51 million as compared to the same quarter last year due to favorable realized market pricing, increased generation and new capacity revenue streams. Energy margins improved by $26 million as realized prices increased 26% primarily due to higher power prices. Generation increased at Arthur Kill by 96% due to transmission constraints around New York City and 23% at Indian River due to improved reliability. Capacity revenues increased $26 million as plants in the NEPOOL and PJM service areas benefited from new capacity revenue streams and greater volumes were sold in the New York capacity merchant markets.

Full-year 2007 adjusted EBITDA increased $208 million over the prior year again due to favorable realized market pricing, increased generation, and new capacity revenue streams. Energy margins increased $170 million due to a 6% increase in generation, primarily at Arthur Kill, Oswego and Indian River, accompanied by a 9% increase in average realized prices. Capacity Revenues increased $81 million as plants in NEPOOL and PJM service areas benefited from new capacity revenue streams and New York Rest of State capacity prices increased 75% due to increased demand. These increases were partially offset by a $48 million decrease in emission sales as reduced activity in the trading of emission allowances was driven by an increase in generation and a 36% decrease in market prices. In addition, operating and maintenance spending increased $15 million due to an increase in plant staffing and benefit costs and increased maintenance and environmental remediation costs.

South Central:Fourth quarter South Central operating income and adjusted EBITDA were lower than the same period in 2006 mainly resulting from a planned major outage at Big Cajun II unit 3, which reduced coal-fired generation by 9% and led to increased maintenance and purchased power. Energy and capacity revenues increased by $14 million for the last quarter of 2007 due to an increase in contracted generation and capacity sales; however, operating and fuel expenses increased by $47 million due to higher purchased power and maintenance expenses.

A comparison of 2007 annual regional adjusted EBITDA to the prior year’s strong performance shows a $56 million decline. Increased energy revenue of $70 million, principally due to a new contract, and increased contract capacity revenue of $16 million, mainly from a new system peak generation set in August 2007, were more than offset by higher operating and fuel expenses. Planned outages at the Big Cajun II facility in 2007 were longer and greater in scope than in 2006 and were the primary cause of a $28 million increase in operating expenses. Despite the increase in planned outages, Big Cajun generation was down only 1% comparing 2007 to 2006. Generation sold, however, increased 5%, which drove a $69 million increase in purchased energy costs. A $17 million increase in

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coal and transportation prices and a $16 million increase in transmission costs also contributed to the increase in 2007 operating expenses.

West:Quarterly and annual improved financial performance resulted from new tolling agreements at Encina and Long Beach. The Encina tolling agreement contributed $15 million in capacity revenues for the year ended December 31, 2007. Recommissioned on August 1, 2007, under ourRepoweringNRG program, the Long Beach Generating Station contributed $13 million in capacity revenues. Annual results for 2007 reflect the acquisition of Dynegy’s 50% interest in WCP (Generation) Holdings LLC (WCP), which closed March 31, 2006.

International: With the reclassification of ITISA to discontinued operations, our German and Australian investments comprise this segment. These businesses are largely contracted and the improvements in 2007 results were principally due to weaker U.S. dollar exchange rates used to translate financial results.

Thermal:The Thermal business is also largely contracted resulting in relatively consistent performance between the periods presented. Improved annual results in 2007 were mainly due to increased PJM capacity payments for Thermal’s Dover facility. Current year income from continuing operations also includes an $18 million pre-tax gain from the January 2007 sale of our Red Bluff and Chowchilla, California generation assets.

Corporate:Fourth quarter 2007 results included an $11 million pre-tax impairment charge related to two commercial paper investments. Annual results in 2006 included a pre-tax benefit of $67 million related to a settlement agreement reached with an equipment manufacturer associated with turbine purchase agreements from 1999 and 2001.

Liquidity and Capital Resources

Table 3: Corporate Liquidity

($ in millions)	December 31,		September 30,		December 31,
	2007		2007(1)		2006(1)
Unrestricted Cash	$	1,132	$	1,171	$	795
Restricted Cash		29		62		44
Total Cash		1,161		1,233		839
Letter of Credit Availability		557		68		533
Revolver Availability		997		997		855
Total Current Liquidity	$	2,715	$	2,298	$	2,227

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

Liquidity at December 31, 2007 was approximately $2.7 billion, up $417 million since September 30, 2007 and up approximately $488 million since the end of 2006. Letter of credit (LC) availability increased during the fourth quarter 2007 as counterparties on trading hedges that previously required a combination of LCs and a second lien position against the Company’s assets as collateral were provided a first lien position in exchange for the return of the posted LCs. During February 2008, the Company moved an additional counterparty to the first lien position that resulted in an additional return of $65 million in LCs. As part of NRG’s amended and restated credit agreement executed on June 8, 2007, the Company obtained the ability to move its existing second lien counterparty exposure to a first lien position.

The $72 million net cash decrease during the fourth quarter of 2007 resulted from cash used to pay down debt, repurchase shares and fund capital expenditures, which more than offset strong cash

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flow from operations. Cash used for financing activities during the fourth quarter amounted to $439 million and included $347 million of debt repayments, $85 million for the repurchase of 2,037,700 shares of common stock and $14 million in preferred dividends. Quarterly net cash provided by operating activities of $541 million primarily resulted from $507 million of quarterly adjusted EBITDA accompanied by a $123 million seasonal reduction in working capital, partly offset by an $18 million increase in cash collateral. Capital expenditures for the last quarter of 2007 were $172 million and included $71 million to supportRepoweringNRG, mainly for wind turbines, and $101 million in maintenance and environmental capital expenditures.

Cash increased $322 million from December 31, 2006 to December 31, 2007. Strong cash flow from operations of $1,517 million in 2007 was driven by $764 million higher adjusted EBITDA primarily resulting from the Texas hedge reset transaction in the fourth quarter of 2006. Cash used for capital expenditures for the full year of 2007 was $481 million. Major maintenance capital spending of $210 million was largely unchanged year over year. Capital spending for environmental controls was $74 million due to the beginning of the installation of the multi-year air quality control system projects at Huntley and Dunkirk.RepoweringNRG capital expenditures for the year were $197 million primarily for Long Beach ($76 million), Padoma wind projects ($69 million) and the development of Cedar Bayou unit 4 ($45 million). In 2007, as part of the Company’s ongoing capital allocation program $408 million of net debt repayments were made and $353 million (including the $85 million purchased in December 2007) was used to repurchase 9,044,400 shares of common stock.

2008 Capital Allocation Plan

During December 2007, the Company initiated its 2008 Capital Allocation Plan with the early repayment of a portion of its Term Loan B and the repurchase of common shares. On December 31, 2007, the Company used $300 million of cash on hand to prepay, without penalty, a portion of its Term Loan B. Upon filing of the Company’s 2007 annual financial statements, the Term Loan B Credit Agreement will require the Company to offer a portion of its 2007 excess cash flows, as defined within the credit agreement, to its lenders of which 50% must be accepted. Based on defined leverage ratios contained in the Credit Agreement, the Company will be required to offer its lenders 50% of its 2007 excess cash flows or $446 million upon the filing of the annual financial statements. The $300 million payment made on December 31, 2007 satisfies the $223 million mandatory take requirement while the offer amount in excess of the $300 million remains available for the lenders to accept. The December 31, 2007 Term Loan B prepayment resulted in the Company achieving a 3.5 to 1 threshold for the corporate leverage ratio, as defined in the Credit Agreement, which resulted in an interest rate step down from LIBOR +175 basis point to LIBOR +150 basis point for the $4.1 billion in Term Loan B and Letter of Credit facilities.

During December 2007, the Company initiated its 2008 common share repurchase program. From December 2007 through January 2008, the Company repurchased, in the open market, $100 million or 2,381,700 of its common shares. In February 2008, the Company’s Board of Directors authorized an additional $200 million for 2008 common share repurchases that would bring the 2008 Capital Allocation program to $300 million in total common share repurchases.

The Company’s Credit Agreement and Senior Notes Indentures contain provisions (“restricted payments” or RP) limiting the use of funds for transactions such as common share repurchases. To provide sufficient RP capacity under the Senior Notes Indentures, the Company has entered into an arrangement with Credit Suisse whereby, at the Company’s option, the Company can extend the $220 million notes and preferred interest maturities of NRG Common Stock Finance I, LLC (CSF I) from October 2008 to June 2010. In addition, the previous settlement date for any share price appreciation beyond a 20% compound annual growth rate since the original date of purchase by CSF I, may be

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extended 30 days to early December 2008. As part of this extension arrangement, the Company intends to contribute to CSF I additional collateral in the form of treasury shares to maintain a blended interest rate on the CSF I facility of approximately 7.5%. The Company expects to implement this extension arrangement by March 17, 2008.

FORNRG — Achieved 2007 Targets

The Company’s Focus on ROIC@NRG (FORNRG) program, a companywide effort introduced in 2005, is designed to increase the return on invested capital, or ROIC, through operational performance improvements to the Company’s asset fleet, along with a range of initiatives at plants and the corporate office to reduce costs or, in some cases, increase revenue. TheFORNRG accomplishments include both recurring and one-time improvements measured from a 2004 baseline, with the exception of the Texas region where benefits are measured using 2005 as the base year.FORNRG contributed $39 million to pre-tax earnings in 2005 and $144 million were achieved through the end of 2006.

For 2007, we attained our previously announced target of $220 million which includes $11 million of one-time benefits. The 2007 results were largely driven by corporate initiatives and improved performance of the generating fleet particularly in the area of generating capacity, heat rate and station service. During 2007, we announced the acceleration and planned conclusion of theFORNRG 1.0 program by bringing forward the previously announced 2009 target of $250 million in pre-tax income improvements to 2008. During 2008, we will launch the next phase of the program under the banner “FORNRG 2.0.”

RepoweringNRG Update

RepoweringNRG is a comprehensive portfolio redevelopment program designed to develop, construct and operate, new multi-fuel, multi-technology and highly efficient, environmentally responsible generation capacity over the next decade. Through this initiative, the Company anticipates retiring certain existing units and adding new generation to meet growing demand in the Company’s core markets, with an emphasis on new baseload capacity that is expected to be supported by long-term power purchase agreements, or PPAs, and financed with limited or non-recourse project financing. Recent advances in this program include:

• On October 29, 2007 NRG and the City of San Antonio, acting through CPS, entered into an agreement with NRG whereby the parties agreed to be equal partners in the development of STP units 3&4. In the event either party chooses at any time not to proceed, gives the other party the right to proceed with the project on its own. CPS reimbursed NRG $39 million for development costs related to STP. As a result, NRG’s net consolidated development costs for the fourth quarter of 2007 showed a net recovery of $7 million.

• On February 1, 2008, NRG, through its wholly owned subsidiary, Padoma Wind Power LLC, entered into a 50% partnership with BP Alternative Energy North America Inc. to build the first phase of the Sherbino Wind Farm, a 150 MW wind project. The Sherbino I Wind Farm is located on a more than 9,000 acre mesa with an elevation of approximately 3,000 feet above sea level, approximately 40 miles east of Fort Stockton in Pecos County, Texas. Initial construction of the Sherbino I Wind Farm commenced in November 2007 and will utilize 50 Vestas V90 3 MW wind turbine generators. The project is scheduled to reach commercial operations by end of 2008 with NRG’s 50% ownership providing a net capacity of 75 MW or the equivalent of 25 generators. The company expects to contribute $83 million to the partnership for the construction of the project.

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Executive Management Developments

Having experienced significant financial, organizational and operational growth since emerging from bankruptcy in 2003, the Company is implementing several enhancements to the Company’s management structure to position the Company for further gains through initiatives such asRepoweringNRG andFORNRG while supporting future growth. These developments, effective March 1, are as follows:

Robert Flexon has been promoted to the newly created position of Chief Operating Officer (COO). Flexon will now oversee NRG’s Plant Operations, Commercial Operations, Environmental Compliance and Risk teams, as well as the Engineering, Procurement and Construction division. Since March 2004, he has served as the Company’s Chief Financial Officer.

In addition, Kevin Howell has been promoted to Chief Administrative Officer. In this position, he will be focused on developing the Company’s capabilities to ensure continued success both in short-term performance and long-term strategic positioning. In this role, Howell will oversee several critical corporate functions including Communications, Investor Relations, Human Resources and Information Technology. Previously, Howell led NRG’s Commercial Operations group, a position he held since August 2005.

Clint Freeland, currently the Company’s Treasurer, will be promoted and will succeed Flexon as NRG’s Chief Financial Officer. Freeland will now manage the Company’s corporate financial and control functions including Treasury, Accounting, Tax and Insurance. Freeland joined NRG in July 2004.

Mauricio Gutierrez will be promoted and succeed Howell as Senior Vice President, Commercial Operations. Gutierrez, currently responsible for NRG’s trading operations, will now be responsible for real-time operations, origination and structuring functions. Gutierrez joined NRG in August 2004.

“Four years ago we engaged in revolutionary management change at NRG; today we announce an evolutionary change intended to focus our top management team on the extraordinary opportunities available to NRG,” said David Crane, NRG’s President and CEO. “We are dedicated to achieving a new wave of value creation for our shareholders.”

Outlook for 2008

Our 2008 adjusted EBITDA and cash flow guidance has been adjusted to reflect the pending sale of ITISA and the return of collateral paid in 2007. Repowering capital expenditures are primarily for STP units 3&4, Cedar Bayou 4 and wind projects prior to financing proceeds. Project level financing and third party equity contributions are expected to approximate $240 million of total project costs, thereby requiring a net cash repowering investment by NRG of approximately $360 million.

Table 4: 2008 Reconciliation of Adjusted EBITDA Guidance ($ in millions)

	2/28/08			11/02/07
Adjusted EBITDA, excluding MTM	$	2,160		$	2,200
Interest payments		(587	)		(617	)
Income tax		(27	)		(15	)
Collateral returned		42			3
Working capital/other changes		(88	)		(71	)
Adjusted cash flow from operations	$	1,500		$	1,500

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	2/28/08			11/02/07
Maintenance capital expenditures		(234	)		(251	)
Preferred dividends		(55	)		(55	)
Free cash flow before environmental and repowering	$	1,211		$	1,194
Environmental capital expenditures		(359	)		(323	)
Repowering NRG		(603	)		(626	)
Free cash flow	$	249		$	245

Earnings Conference Call
On February 28, 2008, NRG will host a conference call at 9:00 a.m. eastern to discuss these results. Investors, the news media and others may access the live webcast and presentation materials by logging on to NRG’s website at http://www.nrgenergy.com and click on “Investors.” Later that day, the call will be available for replay from the “Investors” section of the NRG website.

About NRG

A Fortune 500 Company, NRG Energy, Inc. owns and operates a diverse portfolio of power-generating facilities, primarily in Texas and the Northeast, South Central and West regions of the United States. Its operations include baseload, intermediate, peaking, and cogeneration facilities and thermal energy production. NRG also has ownership interests in generating facilities in Australia, Germany and Brazil. NRG is a member of USCAP, a diverse group of business and environmental organizations calling for mandatory legislation to achieve significant reductions of greenhouse gas emissions. NRG is also a founding member of “3C—Combat Climate Change,” a global initiative with companies calling on the global business community to take a leadership role in designing the road map to a low carbon society.

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, the timing and completion ofRepowering NRG projects,FORNRG targets, and expected earnings, future growth and financial performance, 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, 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 expected benefits and timing of ourRepoweringNRG projects,FORNRG initiatives and Capital Allocation Plan.

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, February 28, 2008 and are 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 atwww.sec.gov.

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# # #

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

Contacts:

Media:	Investors:
Meredith Moore	Nahla Azmy
609.524.4522	609.524.4526
Lori Neuman	Kevin Kelly
609.524.4525	609.524.4527

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NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

	(Unaudited)
	Three months ended						Twelve Months ended
	December 31						December 31
(In millions, except for per share amounts)	2007			2006			2007			2006
Operating Revenues
Total operating revenues	$	1,382		$	1,135		$	5,989		$	5,585
Operating Costs and Expenses
Cost of operations		818			795			3,378			3,265
Depreciation and amortization		177			149			658			590
General and administrative		75			74			309			276
Development costs		(7	)		21			101			36
Total operating costs and expenses		1,063			1,039			4,446			4,167
Gain on sale of assets		1			—			17			—
Operating Income		320			96			1,560			1,418
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		14			14			54			60
Write downs and gains/(losses) on sales of equity method investments		—			—			1			8
Other income, net		12			41			55			156
Refinancing expenses		—			(9	)		(35	)		(187	)
Interest expense		(169	)		(177	)		(689	)		(590	)
Total other expenses		(143	)		(131	)		(614	)		(553	)
Income From Continuing Operations Before Income Taxes		177			(35	)		946			865
Income tax expense		77			—			377			322
Income From Continuing Operations		100			(35	)		569			543
Income from discontinued operations, net of income taxes		4			5			17			78
Net Income		104			(30	)		586			621
Preference stock dividends		14			13			55			50
Income Available for Common Stockholders	$	90		$	(43	)	$	531		$	571
Weighted average number of common shares outstanding — basic		239			250			240			258
Income from continuing operations per weighted average common share — basic	$	0.36		$	(0.19	)	$	2.14		$	1.90
Income from discontinued operations per weighted average common share — basic		0.02			0.02			0.07			0.31
Net Income per Weighted Average Common Share — Basic	$	0.38		$	(0.17	)	$	2.21		$	2.21
Weighted average number of common shares outstanding — diluted		270			250			288			301
Income from continuing operations per weighted average common share — diluted	$	0.34		$	(0.19	)	$	1.95		$	1.78
Income from discontinued operations per weighted average common share — diluted		0.01			0.02			0.06			0.26
Net Income per Weighted Average Common Share — Diluted	$	0.35		$	(0.17	)	$	2.01		$	2.04

11

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2007			2006
(in millions, except shares and par value)
ASSETS
Current Assets
Cash and cash equivalents	$	1,132		$	777
Restricted cash		29			41
Accounts receivable — trade, less allowance for doubtful accounts of $1 and $1		482			369
Current portion of capital lease		30			27
Taxes receivable		58			63
Inventory		451			420
Derivative instruments valuation		1,034			1,230
Deferred income taxes		124			—
Collateral on deposits in support of energy risk management activities		85			27
Prepayments and other current assets		86			105
Current assets — discontinued operations		51			24
Total current assets		3,562			3,083
Property, Plant and Equipment
In service		12,678			12,433
Under construction		337			87
Total property, plant and equipment		13,015			12,520
Less accumulated depreciation		(1,695	)		(974	)
Net property, plant and equipment		11,320			11,546
Other Assets
Equity investments in affiliates		425			344
Note receivable — affiliates		126			114
Capital lease, less current portion		365			365
Goodwill		1,786			1,789
Intangible assets, net of accumulated amortization of $372 and $259		873			981
Nuclear decommissioning trust fund		384			352
Derivative instruments valuation		150			439
Other non-current assets		176			262
Intangible assets held-for-sale		14			79
Non-current assets — discontinued operations		93			82
Total other assets		4,392			4,807
Total Assets	$	19,274		$	19,436

12

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2007			2006
(in millions, except shares and par value)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	466		$	123
Accounts payable — trade		381			327
Accounts payable — affiliates		3			2
Derivative instruments valuation		917			964
Deferred income taxes		—			164
Accrued interest expense		185			131
Other accrued expenses		189			130
Other current liabilities		99			163
Current liabilities — discontinued operations		37			28
Total current liabilities		2,277			2,032
Other Liabilities
Long-term debt and capital leases		7,895			8,603
Nuclear decommissioning reserve		307			289
Nuclear decommissioning trust liability		326			324
Postretirement and other benefit obligations		263			301
Deferred income taxes		843			554
Derivative instruments valuation		759			351
Out-of-market contracts		628			897
Other non-current liabilities		149			116
Non-current liabilities — discontinued operations		76			64
Total non-current liabilities		11,246			11,499
Total Liabilities		13,523			13,531
3.625% convertible perpetual preferred stock, $0.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs)		247			247
Commitments and Contingencies
Stockholders’ Equity
4% convertible perpetual preferred stock; $0.01 par value; 420,000 shares issued and outstanding at December 31, 2007 and 2006 (at liquidation value of $420, net of issuance costs)		406			406
5.75% convertible perpetual preferred stock; $0.01 par value, 2,000,000 shares issued and outstanding at December 31, 2007 and 2006 (at liquidation value of $500, net of issuance costs)		486			486
Common Stock; $0.01 par value; 500,000,000 shares authorized; 261,285,529 and 274,248,264 shares issued and 236,734,929 and 244,647,102 outstanding		3			3
Additional paid-in capital		4,092			4,474
Retained earnings		1,270			739
Less treasury stock, at cost — 24,550,600 and 29,601,162 shares		(638	)		(732	)
Accumulated other comprehensive (loss)/income		(115	)		282
Total Stockholders’ Equity		5,504			5,658
Total Liabilities and Stockholders’ Equity	$	19,274		$	19,436

13

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

(in millions)
Year ended December 31,	2007			2006
Cash Flows from Operating Activities
Net income	$	586		$	621
Adjustments to reconcile net income to net cash provided by operating activities Distributions less than equity in earnings of unconsolidated affiliates		(33	)		(33	)
Depreciation and amortization of nuclear fuel		719			654
Amortization and write-off of deferred financing costs and debt discount/premiums		66			79
Amortization of intangibles and out-of-market contracts		(156	)		(490	)
Amortization of equity-based compensation		19			14
Write down and (gains)/losses on sale of equity method investments		(1	)		(8	)
(Gain)/Loss on sale and disposal of equipment		(17	)		10
Impairment charges and asset write-downs		20			—
Changes in derivatives		77			(149	)
Changes in deferred income taxes		352			327
Gain on legal settlement		—			(67	)
Gain on sale of discontinued operations		—			(76	)
Gain on sale of emission allowances		(31	)		(64	)
Change in nuclear decommissioning trust liability		32			12
Changes in collateral deposits supporting energy risk management activities		(125	)		454
Settlement of out-of-market power contracts		—			(1,073	)
Cash provided by changes in other working capital, net of acquisition and disposition effects Accounts receivable, net		(102	)		87
Inventory		(38	)		(50	)
Prepayments and other current assets		22			43
Accounts payable		49			(73	)
Accrued expenses and other current liabilities		106			133
Other assets and liabilities		(28	)		57
Net Cash Provided by Operating Activities		1,517			408
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, WCP and Padoma , net of cash acquired		—			(4,333	)
Capital expenditures		(481	)		(221	)
Decrease in restricted cash, net		12			6
Decrease in notes receivable		34			27
Decrease in trust fund balances		19			—
Purchases of emission allowances		(161	)		(135	)
Proceeds from sale of emission allowances		272			146
Investments in nuclear decommissioning trust fund securities		(265	)		(227	)
Proceeds from sales of nuclear decommissioning trust fund securities		233			214
Proceeds from sale of investments and equipment		2			86
Purchases of securities		(49	)		—
Proceeds from sale of discontinued operations and assets		57			260
Return of capital from equity method investments		—			1
Net Cash Provided/(Used) by Investing Activities		(327	)		(4,176	)
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders		(55	)		(50	)
Payment of financing element of acquired derivatives		—			(296	)
Payment for treasury stock		(353	)		(732	)
Funded letter of credit		—			350
Proceeds from issuance of common stock, net of issuance costs		7			986
Proceeds from issuance of preferred shares, net of issuance costs		—			486
Proceeds from issuance of long-term debt		1,411			8,619
Payment of deferred debt issuance costs		(5	)		(199	)
Payments for short and long-term debt		(1,819	)		(5,111	)
Net Cash Provided/(Used) by Financing Activities		(814	)		4,053
Change in cash from discontinued operations		(25	)		2
Effect of exchange rate changes on cash and cash equivalents		4			4
Net Increase/(Decrease) in Cash and Cash Equivalents		355			291
Cash and Cash Equivalents at Beginning of Period		777			486
Cash and Cash Equivalents at End of Period	$	1,132		$	777

14

Appendix Table A-1: Fourth Quarter 2007 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			West		International			Thermal		Corporate			Total
Net Income (Loss)		130			82			(19	)		10		29			4		(132	)		104
Plus:
Income Tax		58			—			(1	)		—		3			—		17			77
Interest Expense		31			15			13			—		1			1		100			161
Amortization of Finance Costs		—			—			—			—		—			—		6			6
Amortization of Debt (Discount)/Premium		—			—			—			—		—			—		2			2
Depreciation Expense		128			28			17			2		—			2		—			177
Accretion of Asset Retirement Obligation		—			1			—			1		—			—		—			2
Amortization of Power Contracts		(51	)		—			(6	)		—		—			—		—			(57	)
Amortization of Fuel Contracts		4			—			—			—		—			—		—			4
Amortization of Emission Credits		10			—			—			—		—			—		—			10
EBITDA		310			126			4			13		33			7		(7	)		486
Net (Income) Loss from Discontinued Operations		—			—			—			—		(4	)		—		—			(4	)
Loss (Gain) on Sale of Assets		—			—			—			—		—			—		1			1
Station Service Reserve Reversal		—			(18	)		—			—		—			—		—			(18	)
Fixed Asset Write-off		3			—			—			—		—			—		—			3
Adjusted EBITDA		313			108			4			13		29			7		(6	)		468
Less: MtM forward position accruals		(7	)		5			—			—		—			—		—			(2	)
Add: Prior period MtM reversals		14			5			—			—		—			—		—			19
Less: Hedge Ineffectiveness		(13	)		(5	)		—			—		—			—		—			(18	)
Adjusted EBITDA, excluding MtM		347			113			4			13		29			7		(6	)		507

15

Appendix Table A-2: Fourth 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			West			International			Thermal			Corporate			Total
Net Income (Loss)		10			69			16			(7	)		15			1			(134	)		(30	)
Plus:
Income Tax		(23	)		—			—			—			7			—			16			-
Interest Expense		40			15			12			—			1			3			96			167
Amortization of Finance Costs		—			—			—			—			—			—			9			9
Amortization of Debt (Discount)/Premium		—			—			2			—			—			(1	)		—			1
Refinancing Expense		—			—			—			—			—			—			9			9
Depreciation Expense		104			23			17			2			—			3			—			149
ARO		—			—			—			—			—			—			—			-
Amortization of Power Contracts		(1,200	)		—			(6	)		—			—			—			—			(1,206	)
Amortization of Fuel Contracts		26			—			—			—			—			—			—			26
Amortization of Emission Credits		12			(4	)		—			—			—			—			—			8
EBITDA		(1,031	)		103			41			(5	)		23			6			(4	)		(867	)
Net (Income) Loss from Discontinued Operations		—			—			—			—			(1	)		—			(4	)		(5	)
Acquisition Integration Costs		—			—			—			—			—			—			3			3
Audrain Asset Sale Adjust		—			—			—			—			—			—			(3	)		(3	)
Gain on Dissolution of Pike		—			—			—			—			—			—			(13	)		(13	)
Property Tax refund Prior Years		—			(9	)		—			—			—			—			—			(9	)
Reclassify Emission Credit Sale		(37	)		—			—			—			—			—			37			-
Hedge Reset		1,202			—			—			—			—			—			—			1,202
Adjusted EBITDA		134			94			41			(5	)		22			6			16			308
Less: MtM forward position accruals		37			18			2			1			—			—			—			58
Add: Prior period MtM reversals		—			(14	)		—			—			—			—			—			(14	)
Less: Hedge Ineffectiveness		(94	)		—			—			—			—			—			—			(94	)
Adjusted EBITDA, excluding MtM		191			62			39			(6	)		22			6			16			330

16

Appendix Table A-3: Full-Year 2007 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			West		International			Thermal			Corporate			Total
Net Income (Loss)		485			401			4			36		117			36			(493	)		586
Plus:
Income Tax		327			—			—			—		(12	)		—			62			377
Interest Expense		164			57			53			—		5			6			371			656
Amortization of Finance Costs		—			—			—			—		—			—			25			25
Amortization of Debt (Discount)/Premium		—			—			—			—		—			—			7			7
Refinancing Expense		—			—			—			—		—			—			35			35
Depreciation Expense		469			102			68			3		—			11			5			658
Accretion of Asset Retirement Obligation		2			2						2											6
Amortization of Power Contracts		(218	)		—			(24	)		—		—			—			—			(242	)
Amortization of Fuel Contracts		47			—			—			—		—			—			—			47
Amortization of Emission Credits		40			—			—			—		—			—			—			40
EBITDA		1,316			562			101			41		110			53			12			2,195
Net (Income) Loss from Discontinued Operations		—			—			—			—		(17	)		—			—			(17	)
Write-Down and (Gain)/Losses on Sales of Equity Method Investments		—			—			—			—		—			—			(1	)		(1	)
Loss (Gain) on Sale of Assets — Red Bluff and Chowchilla		—			—			—			—		—			(18	)		1			(17	)
Station Service Reserve Reversal		—			(18	)		—			—		—			—			—			(18	)
Fixed Asset Write-off		3			—			—			—		—			—			—			3
Adjusted EBITDA		1,319			544			101			41		93			35			12			2,145
Less: MtM forward position accruals		7			13			—			—		—			—			—			20
Add: Prior period MtM reversals		83			45			—			—		—			—			—			128
Less: Hedge Ineffectiveness		11			2			—			—		—			—			—			13
Adjusted EBITDA, excluding MtM		1,384			574			101			41		93			35			12			2,240

17

Appendix Table A-4: Full Year 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			West			International			Thermal			Corporate			Total
Net Income (Loss)		729			404			48			12			129			13			(714	)		621
Plus:
Income Tax		23			—			—			(2	)		23			—			278			322
Interest Expense		138			63			51			—			1			7			300			560
Amortization of Finance Costs		—			—			—			—			—			—			24			24
Amortization of Debt (Discount)/Premium		—			—			7			—			—			(1	)		—			6
Refinancing Expense		—			—			—			—			—			—			187			187
Depreciation Expense		413			89			68			3			—			12			5			590
Amortization of Power Contracts		(1,682	)		—			(19	)		—			—			—			—			(1,701	)
Amortization of Fuel Contracts		85			—			—			—			—			—			—			85
Amortization of Emission Credits		39			5			3			—			—			—			—			47
EBITDA		(255	)		561			158			13			153			31			80			741
Net (Income) Loss from Discontinued Operations		—			—			—			—			(61	)		—			(17	)		(78	)
Write-Down and (Gain)/Losses on Sales of Equity Method Investments		—			—			—			—			(3	)		—			(5	)		(8	)
Legal Settlement		—			(7	)		—			—			—			—			(67	)		(74	)
Acquisition Integration Costs		—			—			—			—			—			—			14			14
Audrain Asset Sale Adjust		—			—			—			—			—			—			(3	)		(3	)
Station Service Reserve Reversal		—			(15	)		—			—			—			—			—			(15	)
Gain on Dissolution of Pike		—			—			—			—			—			—			(13	)		(13	)
Property Tax refund Prior Years		—			(9	)		—			—			—			—			—			(9	)
Reclassify Emission Credit Sale		(37	)		—			—			—			—			—			37			-
Hedge Reset		1,202			—			—			—			—			—			—			1,202
Mirant Defense		—			—			—			—			—			—			6			6
Adjusted EBITDA		910			530			158			13			89			31			32			1,763
Less: MtM forward position accruals		94			49			—			—			—			—			—			143
Add: Prior period MtM reversals		—			(115	)		(1	)		—			—			—			—			(116	)
Less: Hedge Ineffectiveness		28			—			—			—			—			—			—			28
Adjusted EBITDA, excluding MtM		788			366			157			13			89			31			32			1,476

Appendix Table A-5: Adjusted Cash Flow from Operations
The following table summarizes the calculation of adjusted cash flow from operations and provides a reconciliation to cash flow from (used by) operations.

	Full Year
($ in millions)	2006
Cash Flow from Operations	$	408
Hedge Reset		1,361
Reclassification of payment of financing element of acquired derivatives		(296	)
Adjusted Cash Flow from Operations	$	1,473

18

EBITDA, adjusted EBITDA, free cash flow and adjusted cash flow from operations 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 cash flow from operations 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 the hedge reset, integration, impairment and corporate relocation charges, discontinued operations, legal settlements and write downs and gains or losses on the sales of equity method investments and other assets; 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. Adjusted EBITDA, excluding mark-to-market (MtM) adjustments, is provided to further supplement adjusted EBITDA by excluding the impact of unrealized MtM adjustments included in EBITDA for hedge contracts that are economic hedges but do not qualify for hedge accounting treatment in accordance with SFAS No. 133Accounting for Derivative Instruments and Hedging Activities,as well as the ineffectiveness impact of economic hedge contracts that qualify for hedge accounting treatment. Adjusted EBITDA, excluding MtM adjustments, is a supplemental measure provided to illustrate the impact of MtM movements on adjusted EBITDA resulting from commodity price movements for economic hedge contracts while the underlying hedged commodity has not been subject to MtM adjustments.

Free cash flow is cash flow from operations less capital expenditures and preferred stock dividends and is used by NRG predominantly as a forecasting tool to estimate cash available for debt reduction and other capital allocation alternatives. Adjusted cash flow from operations is provided to show cash flows from operations without the impact of the Hedge Reset and the financing element of derivatives acquired in conjunction with the acquisition of NRG Texas. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. In addition, in evaluating free cash flow, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.

19