02.11.07

2.11.200/: Meldung: NRG EnergyReports Q3 Results

Third Quarter Highlights:

* $719 million of adjusted EBITDA, excluding mark-to-market impacts;
* $517 million of cash flow from operations; and
* $250 million 2009 goal of recurring pre-tax income improvement from FORNRG accelerated to 2008.

Capital Allocation:

* First Lien Collateral Program increased liquidity by over $550 million;
* Share Repurchase Program–completed Phase II with 1,337,500 common shares; and
* Conditional tender offer and concurrent alternative consent solicitation initiated; beginning next step in the holding company structure implementation.

RepoweringNRG/ecoNRG:

* 260 MW Long Beach Emergency Repowering commences operation on schedule;
* 550 MW Cedar Bayou 4 begins construction;
* 125 MW carbon capture initiative entered into with Powerspan; and
* CPS (San Antonio) becomes 50% development partner in South Texas Project (STP) 3&4.

Guidance:

* $100 million increase in adjusted EBITDA guidance to $2.3 billion for 2007; and
* $2.2 billion initial adjusted EBITDA guidance established for 2008.

NRG Energy, Inc. (NYSE:NRG - News) today reported income from continuing operations for the three months ended September 30, 2007 of $268 million, or $0.93 per diluted common share, as compared to $371 million, or $1.16 per diluted common share, for the same period last year. Both quarterly and year-to-date comparisons are impacted by mark-to-market (MtM) movements and expenses incurred to support our RepoweringNRG program. Quarterly operating income from continuing operations before income taxes, excluding MtM impacts, increased from $411 million to $423 million. Third quarter 2007 results include $49 million in RepoweringNRG program net development costs, an increase of $40 million from last year’s third quarter.

Income from continuing operations for the nine months ended September 30, 2007 of $482 million, or $1.66 per diluted common share, declined from $588 million, or $1.92 per diluted common share, for the same period last year. Income from continuing operations before income taxes for the first three quarters of 2007, excluding MtM impacts, increased to $841 million from $602 million in the same period in 2006. Nine-month operating results in 2007 included $108 million of net development expenses for our RepoweringNRG program. Year-to-date results were also favorably affected by higher generation and capacity revenues in the Northeast region, the inclusion of an additional month for NRG Texas because this business was acquired on February 2, 2006, and were partially offset by a $35 million non-cash, pre-tax charge related to the completion of the $4.4 billion refinancing of the Company’s Senior Credit Facility in conjunction with our Comprehensive Capital Allocation Plan announced on May 2, 2007.

Cash flow from operations for the first nine months of 2007 was $976 million, after posting $107 million of collateral, as compared to adjusted cash flow from operations of $1,048 million, after collecting $397 million of collateral during the same period last year. Adjusted cash flow from operations through September 30, 2007, exclusive of collateral movements, increased by $432 million or 66% over the comparable period in 2006. Cash flow in 2007 included NRG Texas for the full nine months of 2007. Cash flow from operations also included $425 million from higher contract prices resulting from last November’s hedge reset transactions. Partially offsetting these improvements was a $115 million seasonal working capital increase that is expected to decline in the fourth quarter of this year.

“The Company’s strong financial performance was achieved notwithstanding the mild and wet summer weather in Texas, our largest market,” commented David Crane, NRG President and Chief Executive Officer. “As such, these results speak to the strength of our geographically diversified portfolio as well as the skill of our operating personnel across the Company.”

Regional Segment Review of Results

Table 1: Three Months Income from Continuing Operations and Adjusted EBITDA
($ in millions)

Income from Continuing
Operations before Taxes
Adjusted EBITDA
Three months ending 9/30/07 9/30/06 9/30/07 9/30/06
Texas 275 480 395 410
Northeast 171 152 210 181
South Central 18 18 44 43
West 13 12 14 12
International 30 27 34 30
Thermal 4 6 9 11
Corporate and Eliminations (1) (96 ) (86 ) 5 30
Total 415 609 711 717
Less: MtM forward position accruals (2) 1 83 1 83
Add: Prior period MtM reversals (3) 18 (37 ) 18 (37 )
Less: Hedge ineffectiveness (4) 9 78 9 78
Total Excluding MtM Impacts (5) 423 411 719 519
(1) Includes interest expense of $100 million and $110 million for 2007 and 2006, respectively.

(2) Represents a net domestic MtM gain of $1 million in 2007 ($8 million loss in Texas and $9 million gain in the Northeast region) and a net domestic MtM gain of $83 million in 2006, (primarily in Texas ($49 million gain) and the Northeast region ($36 million gain)).

(3) Represents the reversal of $18 million (primarily in Texas) in 2007 associated with the $172 million net domestic MtM gains recognized in 2006 and reversal of $37 million (primarily in the Northeast region) in 2006 associated with the $119 million net domestic MtM losses recognized in 2005.

(4) NRG also hedges power prices using natural gas contracts and, to the extent gas and power prices are not correlated, the ineffective portion is included in our MtM results (mainly in Texas).

(5) Total net MtM impacts associated with asset backed hedges.

Table 2: Nine Months Income from Continuing Operations and Adjusted EBITDA
($ in millions)

Income from Continuing
Operations before Taxes
Adjusted EBITDA
Nine months ending 9/30/07 9/30/06 9/30/07 9/30/06
Texas 624 765 1,006 778
Northeast 319 335 438 436
South Central 24 32 97 116
West 26 17 29 18
International 77 80 91 84
Thermal 32 12 28 26
Corporate and Eliminations (1) (316 ) (329 ) 17 17
Total 786 912 1,706 1,475
Less: MtM forward position accruals (2) 23 87 23 87
Add: Prior period MtM reversals (3) 109 (102 ) 109 (102 )
Less: Hedge ineffectiveness (4) 31 121 31 121
Total Excluding MtM Impacts(5) 841 602 1,761 1,165
(1) Includes interest and refinancing expense of $330 million and $397 million for 2007 and 2006, respectively. Results in 2006 also included a $67 million gain related to a settlement agreement.

(2) Represents a net domestic MtM gain of $23 million in 2007 (primarily $15 million in Texas and $8 million in the Northeast region) and a net domestic MtM gain of $87 million in 2006 (primarily $57 million in Texas and $33 million in the Northeast).

(3) Represents the reversal of $109 million ($69 million in Texas and $40 million in the Northeast region) in 2007 associated with the $172 million net domestic MtM gains recognized in 2006 and reversal of $102 million (mainly in the Northeast region) in 2006 associated with the $119 million net domestic MtM losses recognized in 2005.

(4) NRG also hedges power prices using natural gas contracts and, to the extent gas and power prices are not correlated, the ineffective portion is included in our MtM results (mainly in Texas).

(5) Total net MtM impacts associated with asset backed hedges.

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. Although these transactions are predominantly economic hedges of our baseload portfolio, a portion of these forward sales are not afforded hedge accounting treatment and the MtM change in value of these transactions is recorded to current period earnings. For the third quarter 2007, we recorded a $10 million forward domestic net MtM gain representing the increase in fair value of forward sales contracts of electricity and fuel, compared to $161 million of net domestic MtM gains recorded in the third quarter 2006. Prior year gains were mainly due to low energy prices and a $78 million ineffectiveness gain in our Texas region.

Texas: Income from continuing operations before income taxes decreased by $205 million, principally resulting from a $142 million impact from MtM movements and $34 million of development expenses. MtM gains recorded in the third quarter of 2006 were $128 million, including the $78 million ineffectiveness gain, compared to a $14 million net MtM loss experienced this quarter. NRG Texas incurred $34 million in costs to prepare the STP units 3&4 Combined Construction and Operating License Application (COLA) submitted in September.

Adjusted EBITDA, excluding MtM impacts, increased $127 million over the third quarter of last year. Current quarter EBITDA benefited by $180 million from the increase in contract prices from the November 2006 hedge reset transaction. Offsetting this increase, in addition to higher development spending, generation at the Texas gas plants declined 1.1 million MWh as mild weather reduced demand for our peaking units. This decline, combined with marginally lower coal plant availability and lower market prices, partly offset by favorable hedging positions, led to a $31 million energy margin decline versus the same period in 2006.

Adjusted EBITDA for the first nine months of this year included an additional month of operating results and the $425 million hedge reset benefit. The financial impact of the year-to-date 2.1 million megawatt-hour (MWh) reduction in output from our gas-fired units was largely offset by the commercial hedging activities of our Commercial Operations group. Development costs increased $75 million over the comparable period in 2006, primarily for the STP COLA submission.

Northeast: Regional results for the quarter increased as compared to the same quarter last year due to improved capacity pricing and reduced fuel costs. Capacity revenues increased $28 million over the third quarter of last year, as plants in the NEPOOL and PJM service areas benefited from new capacity revenue streams. Northeast generation was slightly lower than the third quarter of last year, however an increase in natural gas-fueled generation, accompanied by a decline in oil-fueled generation, led to a $12 million net decrease in fuel expense. Generation at our Arthur Kill plant increased 31% over the third quarter of last year as the plant responded reliably to frequent dispatch orders intended to reduce transmission constraints around New York City.

Nine-month adjusted EBITDA, excluding the MtM impact, increased $161 million over the comparable 2006 period. Contributing to the increase was $55 million in higher capacity revenues, $30 million of which was from the region’s NEPOOL assets and $22 million from our PJM assets. Higher generation in western New York and New York City, accompanied by favorable hedge positions, primarily account for the remainder of the improved performance versus 2006.

South Central: Third quarter operating income and adjusted EBITDA for 2007 are almost unchanged from the strong summer performance delivered by this region in 2006. South Central operations continued to perform well as the region’s plants generated 5% more MWh than the third quarter of last year to meet increased demand from electric cooperative customers. Contract revenues also benefited from new contracts and increased 2007 capacity payments reflecting a summer peak demand record set in 2006. Gains in contracts and capacity revenues were offset by a $4 million increase in transmission costs and a $3 million increase in operating and maintenance expenses, mainly in preparation for a fall outage. On a year-to-date basis compared to 2006, increased energy revenues from new contracts and higher capacity payments are more than offset by a $12 million increase in transmission expenses.

West: Quarter-over-quarter improved results are due to new tolling agreements at Encina and Long Beach. Recommissioned on August 1, 2007 as part of our RepoweringNRG program, the Long Beach Generating Station contributed $5 million in capacity revenues. This was partly offset by a reduction in equity earnings on our Saguaro investment in 2007. Results for the nine months ended September 30, 2007 reflect the increased ownership following our acquisition of Dynegy Inc.’s 50 percent interest in WCP (Generation) Holdings LLC (WCP), which closed March 31, 2006. In terms of post-reporting period events, our California assets sustained no apparent harm during the recent wildfires in Southern California and, indeed, played an important role in keeping the lights on in the San Diego area during the crisis.

FORNRG

FORNRG is the companywide, multi-year improvement initiative introduced in 2005. Its objective is to increase the return on invested capital (ROIC) through operational performance improvements to our generating assets and a range of additional initiatives at plants and across the Company aimed either at reducing costs or generating additional revenues. The overall program goal is $250 million per year of recurring, cumulative pre-tax earnings improvement by 2009.

FORNRG contributed $39 million to pre-tax earnings in 2005 and $144 million in 2006. For 2007, we now expect to achieve $220 million, which exceeds by $20 million our previously announced 2007 FORNRG target. The better than expected 2007 results are being driven by:

* Exceeding overall plant performance targets, including recapturing plant generating capacity;
* Expanding the FORNRG program further into the Texas region;
* Implementing a centralized procurement structure to leverage purchase price power throughout the Company; and
* Higher corporate headquarters contributions to the initiative.

These results, combined with additional FORNRG opportunities identified this year, particularly in the procurement area, allow us to accelerate the $250 million overall program target by a full year to 2008. We have begun a review of the potential to launch a second phase of FORNRG covering 2009 and beyond.

Liquidity and Capital Resources

Table 3: Corporate Liquidity
($ in millions) Sept. 30, 2007 June 30, 2007 December 31, 2006
Unrestricted Cash 1,171 795 795
Restricted Cash 62 52 44
Total Cash 1,233 847 839
Letter of Credit Availability 68 78 533
Revolver Availability 997 929 855
Total Current Liquidity $2,298 $1,854 $2,227

Liquidity at September 30, 2007 was approximately $2.3 billion, $71 million higher than December 31, 2006. The current quarter total cash increase of $386 million is mainly due to the strong quarterly cash from operations of $517 million. Capital expenditures of $104 million and common share purchases of $53 million partially offset the quarter’s cash flow.

Capital Allocation

In May 2007, NRG announced a Comprehensive Capital Allocation Plan (CCAP) which, among other things, projected an allocation of the Company’s free cash flow over the forward planning period, reaffirmed NRG’s commitment to the regular return of capital to shareholders and contemplated the introduction of a common share dividend in 2008. The CCAP contemplated several steps to be taken and approvals to be obtained over the following several months.

First Lien Collateral Program and Senior Credit Facility

As part of the Company’s $4.4 billion refinancing of its Senior Credit Facility during the second quarter 2007, NRG received approval from its secured lenders to grant the Company’s hedging counterparties first lien claims against certain NRG assets, which are currently pledged to those lenders, as collateral for its strategic hedging program. NRG recently reached agreement with several hedging counterparties to migrate their collateral positions from the existing second lien collateral program, which includes a combination of letters of credit and second lien claims on the assets of the Company, to a first lien collateral position. As a result, these counterparties have returned approximately $557 million in letters of credit previously provided to them under the Company’s $1.3 billion synthetic letter of credit facility.

Prior to year end 2007, the Company intends to use cash on hand to prepay, without penalty, up to $300 million of its existing first lien Term B loan. Under NRG’s existing Senior Credit Facility, the interest rate applicable to both the $3.1 billion Term B loan and $1.3 billion synthetic letter of credit facility are reduced by 25 basis points when the Company’s corporate Debt/EBITDA ratio, as defined in the agreement, is below 3.5x. With the anticipated prepayment, NRG expects this ratio requirement to be met at year-end 2007, resulting in approximately $10 million in pre-tax interest savings during 2008. Any prepayments made as part of this initiative will be credited against the mandatory annual Excess Cash Flow offer and mandatory take which is required under the Company’s Credit Agreement in March 2008.

Share Repurchases and Holdco Transaction

During the third quarter, NRG completed Phase II of its previously announced Capital Allocation Program with the repurchase of 1,337,500 shares of common stock for approximately $53 million. These purchases, combined with those previously made under both Phase I and Phase II of the program, bring total repurchases over the past 12 months to 36,607,862 shares for a total of $1 billion (15% of outstanding shares repurchased by the Company at an average cost of $27.31 per share).

As part of NRG’s CCAP, the Company has taken a number of steps to prepare for the creation of a new holding company (NRG Holdings, Inc. or Holdco) which include:

1) forming the corporate entities required for the Holdco,

2) closing on a $1 billion Holdco delayed draw term loan facility in the 2nd quarter of 2007, and

3) filing for all necessary regulatory approvals to move forward.

With the recent recovery in financial markets and NRG bond prices, NRG is announcing today its intention to exercise its right to provide its bondholders with a conditional change of control notice, and related offer to purchase bonds at 101% of par, prior to the actual consummation of the intercompany merger which will result in the creation of Holdco. Concurrent with this change of control offer, NRG will seek consent from the same bondholders to waive the change of control in exchange for a 12.5 basis points fee. Under the terms of the Company’s bond indenture, bondholders will have thirty (30) calendar days to respond to the change of control offer/consent solicitation.

Based on the outcome of this change of control offer/consent solicitation, NRG will determine whether or not to move forward with the Holdco formation and draw on the Holdco term loan facility prior to year end. If the Holdco facility is drawn, the net proceeds will be contributed to NRG Energy as an equity infusion, and NRG Energy will use these proceeds to repay a portion of its outstanding Term loans. In this event, the Company’s restricted payments capacity, under its bond indentures, will expand by the amount of the capital contribution, or approximately $1 billion.

Additionally, NRG retains the right, but not the obligation, to purchase any or all of the bonds tendered by investors during this process whether or not NRG decides to move forward and form Holdco.

“By using a conditional change of control notice we remain in complete control of our capital structure throughout the process,” commented Robert Flexon, NRG’s Executive Vice President and Chief Financial Officer. “Furthermore, with our increased liquidity we expect to have an opportunity to replace a portion of our non-callable bonds at a cost of 1% above par for bonds redeemed.”

RepoweringNRG

RepoweringNRG is a program launched by NRG in June 2006 to develop, finance, construct and operate approximately 10,000 MW of new, highly efficient, environmentally responsible capacity over the next decade, principally through the expansion or repowering of units at our existing sites.

ecoNRG

ecoNRG is a complementary program to RepoweringNRG in that it seeks to reduce the Company’s carbon intensity through the implementation of low and no carbon repowering projects and, through the investment in and demonstration of carbon capture and other environmentally advanced technologies. ecoNRG is also focused on increasing environmental awareness, the advocacy of sound environmental policy and reducing the environmental footprint of the Company, its assets and its employees.

Both RepoweringNRG and ecoNRG consist of numerous individual projects and programs which are being advanced continuously. Some of the more significant recent advances resulting from these two initiatives are described in greater detail below.

STP Units 3 & 4

NRG and South Texas Project Nuclear Operating Company (STPNOC) filed a COLA on September 24, 2007 with the Nuclear Regulatory Commission (NRC) to build and operate two new nuclear units at the South Texas Project (STP) nuclear power station site. The total rated capacity of the new units, STP 3 and 4, will equal or exceed 2,700 megawatts using advanced boiler water reactors. This license submittal continues NRG"s leadership role in moving U.S. electrical generation to new, cost-effective baseload power that does not contribute to global climate change and is the first license application submitted to the NRC for a new nuclear plant in 29 years. The NRC is in the process of reviewing our application for completeness. The official COLA review process will begin when the NRC adds our application to their docket, which is anticipated to occur in 2007.

On October 29, 2007, NRG and the City of San Antonio, acting through the City Public Service Board of San Antonio, entered into an agreement whereby the parties agreed to be equal partners in the development of STP 3 and 4 and, 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.

Cedar Bayou Generating Station

NRG and EnergyCo, a joint venture between PNM Resources Inc. (NYSE:PNM - News) and a subsidiary of Cascade Investment, LLC, announced on August 2, 2007 the formation of a 50-50 partnership to construct, own and operate a new 550 MW natural gas-fueled combined cycle generating plant at NRG’s Cedar Bayou Generating Station in Chambers County, Texas. Given that the project was permitted by NRG and is being built at an existing NRG site utilizing certain common facilities, EnergyCo “bought in” to the project by making a “catch up” payment to NRG. Going forward, the parties share equally the obligations to fund plant construction and purchase additional equipment. NRG will also provide various ongoing services related to construction management, plant operations and maintenance and use of NRG facilities in return for a fixed fee plus reimbursement of its costs.

Construction began during the third quarter upon receipt of the air permit and is currently on schedule. As construction is expected to take no more than 24 months, the new unit is scheduled to commence operations during summer 2009.

Commercial Scale Carbon Capture and Sequestration at Parish

NRG has signed a memorandum of understanding with Powerspan Corp. to jointly design, construct, and operate a demonstration facility that will be among the largest carbon capture and sequestration projects in the world and may be the first to achieve commercial scale from an existing coal-fueled power plant. The project will be constructed at the Company’s WA Parish plant near Sugar Land, Texas, and is designed to capture and sequester 90% percent of the carbon dioxide from flue gas equal in quantity to that from a 125-megawatt unit using Powerspan’s proprietary ECO2™ technology.

Capital costs for the project, which is expected to be operational in 2012, are estimated to be between $150 and $200 million. We anticipate that funding for the project will be provided by NRG, Powerspan, other potential outside investors, along with expected grants from government and non-governmental entities.

“As part of our effort to ‘get the carbon out of coal,’ it is essential that we develop and deploy post-combustion carbon capture technologies which can be retrofitted to existing coal plants. This demonstration project with Powerspan at one of the largest baseload coal facilities in the country has the potential to be a breakthrough in post-combustion carbon capture,” said David Crane.

2007 and 2008 Outlook

The Company is raising 2007 adjusted EBITDA guidance to $2,300 million from $2,200 million and cash flow from operations to $1,500 million from $1,420 million to reflect our plant and commercial operations performance year-to-date and our fully hedged baseload position for the balance of the year. Free cash flow increased $141 million due to the increased EBITDA and a decline in total projected 2007 capital expenditures from $630 million to $569 million resulting from a deferral of certain environmental and wind capital expenditures into 2008.

Table 4: 2007 Reconciliation of Adjusted EBITDA Guidance ($ in millions)
2007 Guidance 2007 Guidance
11/02/07 8/02/07
Adjusted EBITDA guidance, excluding MtM $2,300 $2,200
Interest payments (625 ) (624 )
Income tax (23 ) (23 )
Collateral payments (88 ) (71 )
Working capital/other changes (64 ) (62 )
Cash flow from operations $1,500 $1,420
Maintenance and capital expenditures (231 ) (250 )
Preferred dividends (55 ) (55 )
Free Cash Flow – before environmental and growth capital expenditures $1,214 $1,115
Environmental capital expenditure (80 ) (100 )
RepoweringNRG(1) (258 ) (280 )
Free Cash Flow $876 $735

(1) Primarily Long Beach emergency repowering, Cedar Bayou 4 and wind power projects.

Our 2008 adjusted EBITDA and cash flow guidance are $2.2 billion and $1.5 billion, respectively. The projected gross margin decline as compared to 2007 reflects the impact of forward hedges at lower prices, offset by increases from capacity payments and repowering projects. The net development expense decline is due to the reduction in STP development costs. Table 5 reconciles our 2007 guidance to the 2008 outlook:



Table 5: 2008 Reconciliation of Adjusted EBITDA Guidance ($ in millions):
2008 Guidance
11/02/07
2007 Adjusted EBITDA guidance, excluding MtM $2,300
Gross margin impacts, net (100 )
Development expense reduction 75
Property tax increase in Texas (25 )
Major maintenance (STP dual refueling outage) (20 )
Other (30 )
2008 Adjusted EBITDA guidance, excluding MtM $2,200
Interest payments (617 )
Income tax (15 )
Collateral payments 3
Working capital/other changes (71 )
Cash flow from operations $1,500
Maintenance Capital Expenditures (251 )
Preferred Dividends (55 )
Free cash flow – before environmental and growth capital Expenditures $1,194
Environmental Capital Expenditure (323 )
RepoweringNRG(1) (626 )
Free cash flow $245

(1) Primarily STP Units 3&4, Cedar Bayou 4 and wind power projects prior to project level financing. Project level financing is expected to be approximately 50% of project costs, thereby requiring a net cash investment by the Company of approximately $326 million.

Earnings Conference Call

On November 2, 2007, 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 of the conference call and presentation materials by logging on to NRG’s website at http://www.nrgenergy.com and clicking on “Investors.” The webcast will be archived on the site for those unable to listen in real time.

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 and thermal energy production facilities. NRG also has ownership interests in generating facilities in Australia, Germany and Brazil.

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, cash flow from operations, and free cash flow guidance, expected earnings, future growth and financial performance, the timing, completion and expected benefits of RepoweringNRG, the formation and funding of Holdco the timing of our Capital Allocation Plan, and our carbon capture and sequestration project, 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, and our ability to achieve the expected benefits and timing of our RepoweringNRG projects, Holdco 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, cash flow from operations and free cash flow are estimates as of today’s date, November 2, 2007 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 at www.sec.gov.

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



Three months ended
September 30


Nine months ended
September 30
(In millions, except for per share amounts) 2007 2006 2007 2006
Operating Revenues
Total operating revenues $ 1,786 $ 1,942 $ 4,644 $ 4,479
Operating Costs and Expenses
Cost of operations 943 996 2,570 2,478
Depreciation and amortization 161 148 483 443
General and administrative 79 70 236 205
Development costs 49 9 108 15
Total operating costs and expenses 1,232 1,223 3,397 3,141
Gain on sale of assets — — 16 —
Operating Income 554 719 1,263 1,338
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates 19 17 40 46
Write downs and gains/(losses) on sales of equity method investments — (3 ) 1 8
Other income, net 15 30 45 118
Refinancing expense — — (35 ) (178 )
Interest expense (173 ) (154 ) (528 ) (420 )
Total other expense (139 ) (110 ) (477 ) (426 )
Income From Continuing Operations Before Income Taxes 415 609 786 912
Income Tax Expense 147 238 304 324
Income From Continuing Operations 268 371 482 588
Income from discontinued operations, net of income tax expense — 51 — 63
Net Income 268 422 482 651
Dividends for Preferred Shares 13 14 41 37
Income Available for Common Stockholders $ 255 $ 408 $ 441 $ 614
Weighted Average Number of Common Shares Outstanding — Basic 239 272 241 261
Income From Continuing Operations per Weighted Average Common Share — Basic $ 1.07 $ 1.31 $ 1.83 $ 2.11
Income From Discontinued Operations per Weighted Average Common Share — Basic — 0.19 — 0.24
Net Income per Weighted Average Common Share — Basic $ 1.07 $ 1.50 $ 1.83 $ 2.35
Weighted Average Number of Common Shares Outstanding — Diluted 285 317 287 303
Income From Continuing Operations per Weighted Average Common Share — Diluted $ 0.93 $ 1.16 $ 1.66 $ 1.92
Income From Discontinued Operations per Weighted Average Common Share — Diluted — 0.16 — 0.21
Net Income per Weighted Average Common Share — Diluted $ 0.93 $ 1.32 $ 1.66 $ 2.13

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

Sept. 30, 2007 December 31, 2006
(in millions, except for share data) (unaudited)
ASSETS
Current Assets
Cash and cash equivalents $ 1,171 $ 795
Restricted cash 62 44
Accounts receivable, less allowance for doubtful accounts of $1 and $1 536 372
Inventory 424 421
Derivative instruments valuation 827 1,230
Deferred income taxes 45 —
Prepayments and other current assets 284 221
Total current assets 3,349 3,083
Property, plant and equipment, net of accumulated depreciation of $1,515 and $984 11,413 11,600
Other Assets
Equity investments in affiliates 409 344
Notes receivable and capital lease, less current portion 490 479
Goodwill 1,785 1,789
Intangible assets, net of accumulated amortization of $351 and $259 898 981
Nuclear decommissioning trust fund 373 352
Derivative instruments valuation 214 439
Deferred income taxes 30 27
Other non-current assets 152 262
Intangible assets held-for-sale 91 79
Total other assets 4,442 4,752
Total Assets $ 19,204 $ 19,435
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases $ 129 $ 130
Accounts payable 356 332
Derivative instruments valuation 696 964
Deferred income taxes — 164
Accrued expenses and other current liabilities 429 442
Total current liabilities 1,610 2,032
Other Liabilities
Long-term debt and capital leases 8,619 8,647
Nuclear decommissioning reserve 302 289
Nuclear decommissioning trust liability 323 324
Deferred income taxes 824 554
Derivative instruments valuation 486 351
Out-of-market contracts 697 897
Other non-current liabilities 471 435
Total non-current liabilities 11,722 11,497
Total Liabilities 13,332 13,529
Minority Interest 1 1
3.625% Redeemable perpetual preferred stock (at liquidation value, net of issuance costs) 247 247
Commitments and Contingencies
Stockholders’ Equity
Preferred stock (at liquidation value, net of issuance costs) 892 892
Common stock 3 1
Additional paid-in capital 4,032 4,476
Retained earnings 1,180 739
Less treasury stock, at cost — 22,512,900 and 29,601,162 shares (553 ) (732 )
Accumulated other comprehensive income 70 282
Total Stockholders’ Equity 5,624 5,658
Total Liabilities and Stockholders’ Equity $ 19,204 $ 19,435

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)

Nine months ended September 30,


2007


2006

Cash Flows from Operating Activities
Net income $ 482 $ 651
Adjustments to reconcile net income to net cash provided by operating activities
Distributions less than equity in earnings of unconsolidated affiliates (23 ) (27 )
Depreciation and amortization of nuclear fuel 525 490
Amortization and write-off of financing costs and debt discount/premiums 59 71
Amortization of intangibles and out-of-market contracts (112 ) (393 )
Amortization of stock-based compensation 19 13
Changes in deferred income taxes 232 309
Changes in derivatives 41 (183 )
Changes in nuclear decommissioning trust liability 23 9
Changes in collateral deposits supporting energy risk management activities (107 ) 397
Gain on legal settlement — (67 )
Gain on sale of emission allowances (31 ) (68 )
(Gain)/loss on sale of assets (16 ) 3
Gain on sale of discontinued operations — (71 )
Write down and gains on sale of equity method investments (1 ) (8 )
Cash provided/(used) by changes in other working capital, net of acquisition and disposition affects (115 ) 40
Net Cash Provided by Operating Activities 976 1,166
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, WCP and Padoma, net of cash acquired — (4,336 )
Capital expenditures (309 ) (159 )
Increase in restricted cash, net (18 ) (24 )
Decrease in notes receivable 26 22
Purchases of emission allowances (152 ) (76 )
Proceeds from sale of emission allowances 170 97
Investments in nuclear decommissioning trust fund securities (193 ) (158 )
Proceeds from sale of nuclear decommissioning trust fund securities 170 149
Proceeds from sale of assets 57 1
Proceeds from sale of investments 2 86
Decrease in trust fund balances 19 —
Investments in marketable securities (4 ) —
Proceeds from sale of discontinued operations — 239
Net Cash Used in Investing Activities (232 ) (4,159 )
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders (41 ) (37 )
Payment of financing element of acquired derivatives — (118 )
Payment for treasury stock (268 ) (297 )
Funded letter of credit — 350
Proceeds from issuance of common stock, net of issuance costs — 986
Proceeds from issuance of preferred shares, net of issuance costs — 486
Proceeds from issuance of long-term debt 1,411 7,373
Payment of deferred debt issuance costs (5 ) (174 )
Payments for short and long-term debt (1,472 ) (4,697 )
Net Cash Provided/(Used) by Financing Activities (375 ) 3,872
Change in Cash from Discontinued Operations — 14
Effect of Exchange Rate Changes on Cash and Cash Equivalents 7 2
Net Increase in Cash and Cash Equivalents 376 895
Cash and Cash Equivalents at Beginning of Period 795 493
Cash and Cash Equivalents at End of Period $ 1,171 $ 1,388

Appendix Table A-1: Third 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) 161 171 17 13 54 4 (152) 268
Plus:
Income Tax 114 - 1 - (24) - 56 147
Interest Expense 38 14 14 - 3 2 94 165
Amortization of Finance Costs - - - - - - 6 6
Amortization of Debt (Discount)/Premium - - 2 - - - - 2
Depreciation Expense 113 25 17 1 1 3 1 161
ARO Accretion Expense 1 - - - - - - 1
Amortization of Power Contracts (59) - (7) - - - - (66)
Amortization of Fuel Contracts 17 - - - - - - 17
Amortization of Emission Credits 10 - - - - - - 10
EBITDA & Adjusted EBITDA 395 210 44 14 34 9 5 711

Appendix Table A-2: Third 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) 445 153 18 13 74 6 (287) 422
Plus:
Income Tax 35 (1) - (1) 4 - 201 238
Interest Expense 12 14 13 - 2 2 103 146
Amortization of Finance Costs - - - - - - 5 5
Amortization of Debt (Discount)/Premium - - - - - - 2 2
Depreciation Expense 104 22 17 - 1 3 1 148
Amortization of Power Contracts (219) - (5) - - - - (224)
Amortization of Fuel Contracts 22 - - - - - - 22
Amortization of Emission Credits 11 - - - - - - 11
EBITDA 410 188 43 12 81 11 25 770
(Income) from Discontinued Operations - - - - (51) - - (51)
Legal Settlement - (7) - - - - - (7)
Acquisition Integration Costs - - - - - - 4 4
Audrain Asset Sale Adjustment - - - - - - (2) (2)
Write Down on Sale of Equity Method Investment - - - - - - 3 3
Adjusted EBITDA 410 181 43 12 30 11 30 717

Appendix Table A-3: Year-to-date 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) 355 319 23 26 88 32 (361) 482
Plus:
Income Tax 269 - 1 - (11) - 45 304
Interest Expense 133 43 40 - 12 5 270 503
Amortization of Finance Costs - - - - - - 20 20
Amortization of Debt (Discount)/Premium - - - - - - 5 5
Refinancing Expense - - - - - - 35 35
Depreciation Expense 341 74 51 2 2 9 4 483
ARO Accretion Expense 2 2 - 1 - - - 5
Amortization of Power Contracts (167) - (18) - - - - (185)
Amortization of Fuel Contracts 43 - - - - - - 43
Amortization of Emission Credits 30 - - - - - - 30
EBITDA 1,006 438 97 29 91 46 18 1,725
Gain on Sale of Equity Method Investment - - - - - - (1) (1)
Gain on Asset Sale of Red Bluff & Chowchilla - - - - - (18) - (18)
Adjusted EBITDA 1,006 438 97 29 91 28 17 1,706

Appendix Table A-4: Year-to-date 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) 719 335 32 19 113 12 (579) 651
Plus:
Income Tax 46 - - (2) 17 - 263 324
Interest Expense 98 48 43 - 7 5 199 400
Amortization of Finance Costs - - - - - - 15 15
Amortization of Debt (Discount)/Premium - - - - - - 5 5
Refinancing Expense - - - - - - 178 178
Depreciation Expense 309 66 51 1 2 9 5 443
Amortization of Power Contracts (481) - (13) - (2) - - (496)
Amortization of Fuel Contracts 59 - - - - - - 59
Amortization of Emission Credits 28 9 3 - - - (1) 39
EBITDA 778 458 116 18 137 26 85 1,618
(Income) from Discontinued Operations - - - - (50) - (13) (63)
In Station Service Recovery - (15) - - - - - (15)
Acquisition Integration Costs - - - - - - 11 11
Mirant Legal Defense - - - - - - 6 6
Legal Settlements - (7) - - - - (67) (74)
Gain on Sale of Equity Method Investment - - - - (3) - (5) (8)
Adjusted EBITDA 778 436 116 18 84 26 17 1,475

Appendix Table A-5: First Nine Months 2006 Free Cash Flow reconciliation

The following table summarizes the calculation of adjusted free cash flow and provides a reconciliation to cash flow from (used by) operations.

First Nine Months 2006
Cash Flow from Operations $1,166
Reclassification of payment of financing element of acquired derivatives (118)
Adjusted Cash Flow from Operations $ 1,048

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

EBITDA represents net income before interest, taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believes debt-holders frequently use EBITDA to analyze operating performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are:

* EBITDA does not reflect cash expenditures, or future requirements for capital expenditures, or contractual commitments;
* EBITDA does not reflect changes in, or cash requirements for, working capital needs;
* EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debts;
* Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and
* Other companies in this industry may calculate EBITDA differently than NRG does, limiting its usefulness as a comparative measure.

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

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

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. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. Because we have mandatory debt service requirements (and other non-discretionary expenditures) investors should not rely on free cash flow as a measure of cash available for discretionary expenditures. 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.


Contact:
NRG Energy, Inc.
Media:
Meredith Moore, 609-524-4522
Lori Neuman, 609-524-4525
or
Investors:
Nahla Azmy, 609-524-4526
Kevin Kelly, 609-524-4527
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