03.08.07

3.8.2007: Meldung: NRG Energy Reports Q2 2007 Results

Second Quarter Financial Highlights:

* $533 million of adjusted EBITDA, excluding mark-to-market (MtM) adjustments;
* $459 million of cash flow from operations during the first half of 2007, net of $103 million in posted cash collateral;
* Completed the refinancing and repricing of the Company"s $4.4 billion Senior Credit Facility;
* Repurchased 2.7 million common shares (post-split) for $113 million; and
* Raising adjusted EBITDA guidance to $2.2 billion and cash flow from operations to $1.42 billion.

RepoweringNRG:

* 260 megawatt (MW) Long Beach Emergency Repowering, a gas-fueled combustion turbine project is completed on time and commences operation under a 10-year toll with Southern California Edison;
* 442 MW of wind power projects in Texas and California advance; and
* 550 MW Cedar Bayou Texas, a gas-fueled combined cycle plant, to be owned jointly with PNM Resources Inc./Cascade Investment, LLC, receives permits.

NRG Energy, Inc. (NYSE:NRG - News) today reported income from continuing operations for the three months ended June 30, 2007 of $149 million or $0.51 per diluted common share, as compared to $202 million or $0.63 per diluted common share for the same period last year. These results include 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, while the 2006 period benefited from $15 million in pre-tax settlement agreements. Quarterly operating income improved to $436 million from $410 million in 2006. Second quarter 2007 results included $36 million in net development costs for our RepoweringNRG program. Operating income for the three months ended June 30, 2007 were favorably impacted by increased gas generation and pricing in the Northeast region. Net income from continuing operations for the first half of this year was $214 million or $0.71 per common share, compared to $217 million or $0.72 per diluted common share, for the same period last year. Operating income for the first six months of 2007 improved to $709 million from $619 million in 2006. First half results were favorably impacted by the inclusion of an additional month for NRG Texas as this business was acquired on February 2, 2006 and higher generation and pricing in the Northeast region. First half results in 2007 included $59 million of development expenses for our RepoweringNRG program.

Adjusted cash flow from operations through June 30, 2007, exclusive of collateral movements, increased by $230 million over the first six months of 2006. First half cash flow from operations in 2007 included NRG Texas for the full six months of 2007. Cash flow from operations also included a $245 million benefit from higher contract prices that resulted from last November"s hedge reset transactions. Partially offsetting these improvements was a $153 million working capital build that is expected to partially reverse in the second half of this year. Cash flow from operations for the first six months of 2007 was $459 million, after the posting of $103 million of net collateral outflows, versus adjusted cash flow from operations of $604 million, including the benefit of $272 million of net collateral inflows, during the same period last year.

"Through RepoweringNRG and FORNRG we have our business well positioned for the future, while the strong execution of our commercial and plant operations has put us in a position to exceed the financial goals we had announced at the beginning of the year," commented David Crane, NRG President and Chief Executive Officer. "The quarter also marked the timely completion of construction at Long Beach, our first repowering, and demonstrates how quickly and capably we can act upon a type of project which will become increasingly prevalent as reserve margins tighten in all of our core markets."

Regional Segment Review of Results

Table 1: Three Months Income from Continuing Operations and Adjusted
EBITDA
Income from
Continuing
Operations before
($ in millions) Taxes Adjusted EBITDA
----------------------------------------------------------------------
Three months ending 6/30/07 6/30/06 6/30/07 6/30/06
----------------------------------------------------------------------
Texas 236 292 360 279
Northeast 110 51 148 72
South Central (4) (14) 16 15
West 8 9 9 9
International 23 21 25 22
Thermal 5 3 10 8
Corporate and Eliminations (1) (128) (73) 9 (12)
----------------------------------------------------------------------
Total 250 289 577 393
----------------------------------------------------------------------
Less: MtM forward position
accruals (2) 100 (8) 100 (8)
Add: Prior Period MtM reversals
(3) 35 (20) 35 (20)
Less: Hedge ineffectiveness (4) (21) 53 (21) 53
----------------------------------------------------------------------
Total net of MtM Impacts (5) 206 224 533 328
----------------------------------------------------------------------
(1) Includes interest and refinancing expense of $134 million and $58
million for 2007 and 2006, respectively.
(2) Represents a net domestic MtM gain of $100 million in 2007
(primarily in Texas ($76 million), and the Northeast ($24 million)
region) and a net domestic MtM loss of $8 million in 2006 (primarily
in the Northeast region).
(3) Represents the reversal of $35 million ($23 million in Texas and
$12 million in the Northeast) in 2007 associated with the $172
million net domestic MtM gains recognized in 2006 and reversal of $20
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 1: Six Months Income from Continuing Operations and Adjusted
EBITDA
Income from
Continuing
Operations before
($ in millions) Taxes Adjusted EBITDA
----------------------------------------------------------------------
Six months ending 6/30/07 6/30/06 6/30/07 6/30/06
----------------------------------------------------------------------
Texas 349 285 610 371
Northeast 148 183 226 255
South Central 6 14 55 73
West 13 5 14 5
International 47 52 57 55
Thermal 28 7 19 17
Corporate and Eliminations (1) (220) (243) 13 (15)
----------------------------------------------------------------------
Total 371 303 994 761
----------------------------------------------------------------------
Less: MtM forward position
accruals (2) 21 32 21 32
Add: Prior Period MtM reversals
(3) 92 (65) 92 (65)
Less: Hedge ineffectiveness (4) 23 43 23 43
----------------------------------------------------------------------
Total net of MtM Impacts(5) 419 163 1,042 621
----------------------------------------------------------------------
(1) Includes interest and refinancing expense of $228 million and $285
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 $21 million in 2007
(primarily in Texas) and a net domestic MtM gain of $32 million in
2006, (primarily in the Northeast region).
(3) Represents the reversal of $92 million ($54 million in Texas and
$38 million in the Northeast region) in 2007 associated with the $172
million net domestic MtM gains recognized in 2006 and reversal of $65
million (mainly 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 second quarter 2007, we recorded $100 million of forward domestic net MtM gain representing the increase in fair value of forward sales contracts of electricity and fuel, compared to an $8 million net domestic MtM loss recorded in the second quarter 2006. Hedging management activities included a $21 million ineffectiveness loss in the second quarter of 2007, compared to a $53 million gain in the same period in 2006 due to a change in the correlation between natural gas and power prices. This is primarily related to natural gas contracts sold as a hedge for electricity sales in the Company"s Texas region.

Texas: First-half operating results this year benefited from the inclusion of one extra month of operations when compared to 2006 as NRG Texas operations contributed $51 million of pre-tax operating income and $100 million of EBITDA in January 2007. Current quarter and year-to-date EBITDA and cash flow from operations benefited by $156 million and $245 million, respectively, from the November 2006 hedge reset which increased contracted power prices. Improved operations and lower forced outage rates for the baseload coal fleet in the first half of 2007, led to a net increase in gross margin over the same period in 2006. The timing of the spring refueling outage at the STP nuclear facility contributed to increased STP operating expenses of $16 million, compared to the first half of 2006.

Northeast: Improved results for the Northeast, after adjusting for MtM impacts, were due to higher generation and improved power and capacity pricing. Increased generation resulted from the return of normal weather patterns versus the same period last year and transmission constraints around New York City. Prices improved as a result of increased natural gas prices. Overall this led to a $105 million, or 25%, increase in energy revenues over the first half of 2006. Gas generation at our Arthur Kill plant increased 108% over the second quarter of last year and 52% year-over-year as it was called upon frequently to reduce transmission constraints around New York City. Quarterly generation in 2007 at Huntley and Dunkirk increased by 9% due to higher availability. Capacity revenues for the three and six month periods increased 2%, or $2 million, and 18%, or $27 million respectively, reflecting the higher capacity prices in Western New York and new capacity revenue streams in the Connecticut and PJM markets that did not exist during the first half of 2006. Emission credit revenues, however, declined in comparison to 2006. Higher levels of generation combined with 43% decrease in sulfur dioxide emission credit market prices led to a $50 million decline in revenues from the sale of excess credits this year. Prior year quarterly results also benefited from the reversal of a $15 million reserve.

South Central: Second quarter operating income was $10 million higher than last year as contract, merchant and capacity revenues were all higher than last year. Contract revenues benefited from new contracts and capacity payments rose as a new summer peak demand record was set in 2006 which reset the capacity payments for 2007. Operating income for the first half of 2007 declined by $11 million in comparison to an exceptionally strong first half performance in 2006. Increased demand from the region"s load-serving customers combined with lower planned availability of the Big Cajun II coal plant reduced MWs available for sale to the merchant energy market. Energy sold to contract customers through June 30, 2007 increased by $40 million, while merchant revenues declined by $13 million.

West: Results for the year-to-date 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. Second quarter 2007 results are relatively flat as increased capacity revenues were offset by increased operating expenses, primarily for maintenance work performed at Encina and El Segundo to ensure availability under the new tolling agreements.

Regional operating results for the first half of the year more than doubled due to a full six month"s consolidation in 2007 and favorable capacity revenues from new tolling agreements executed by our Encina and El Segundo units after the acquisition date.

Liquidity and Capital Resources

Table 2: Corporate Liquidity

($ in millions) June 30, 2007 December 31, 2006 June 30, 2006(1)
----------------------------------------------------------------------
Unrestricted Cash 795 795 957
Restricted Cash 52 44 58
----------------------------------------------------------------------
Total Cash 847 839 1,015
Letter of Credit
Availability 78 533 116
Revolver Availability 929 855 846
----------------------------------------------------------------------
Total Current
Liquidity $1,854 $2,227 $1,977
(1) These amounts have not been restated for discontinued operations

Liquidity at June 30, 2007 was approximately $1.9 billion, down $373 million since December 31, 2006 and $123 million since June 30, 2006. The reduction in current liquidity is mainly due to the $200 million reduction in synthetic letter of credit (LC) capacity as part of our recent restructuring of the first lien credit facility. Operating cash flows for the first six months of 2007 were $459 million inclusive of $103 million in collateral outflows and $192 million used to fund accounts receivable increases. Operating cash flows plus $29 million in proceeds from the sale of Red Bluff and Chowchilla were offset by $205 million of capital expenditures, $215 million for common share buybacks, $48 million in scheduled principal debt repayments and $28 million in preferred dividend payments.

Capital Allocation Plan Update

On June 8, 2007, NRG completed its $4.4 billion refinancing of the Company"s Senior Credit Facility previously announced on May 2, 2007. The transaction resulted in a 25 basis point reduction in the pricing grid for the Term B loan and LC facilities. In addition to the pricing reduction, the Company reduced by $200 million the LC facility to $1.3 billion and made various amendments to the Senior Credit facility to provide improved liquidity flexibility, the ability to pay common share dividends, and various amendments to facilitate and support the repowering efforts. The pricing on the Company"s term loan and LC facility is also subject to further reductions upon the achievement of certain financial ratios. The refinancing resulted in a charge of approximately $35 million to the current period"s results of operations primarily related to the write-off of previously deferred financing costs.

On May 2, 2007, the Company announced its intention to form NRG Holdings, Inc., or Holdco to support and facilitate its Comprehensive Capital Allocation Plan. The financing on June 8, 2007, provided the Company with the right to call and convert $1 billion of the Term B loan and place it at Holdco. Doing so would increase the restricted payments (RP) capacity under the Senior Note indentures by a like amount and thereby provide sufficient RP capacity for the Company to initiate a common share annual dividend in the future. The formation of Holdco requires the approval of three regulatory bodies, two of which have since granted approval, with the final approval expected during the second half of 2007.

The Company"s announced plan was to form and fund Holdco during the fourth quarter of 2007 and initiate the common dividend in the first quarter of 2008. If Holdco is formed, it will constitute a change in control under the Senior Note indentures and provide the right for bondholders to put the bonds back to the Company at 101% of par. If the current weakness in the credit markets persists into the fourth quarter and NRG"s Senior Notes trade at levels below par, the Company will likely postpone implementation of the Holdco structure or allow the Holdco credit facility to expire on December 28, 2007. If this occurs, the Company will delay the introduction of an annual dividend and will in all likelihood increase common share repurchases in 2008 from previously stated targets.

The Company completed a 2 for 1 stock split by way of a stock dividend for all common stock issued and outstanding at the close of business on May 22, 2007. The additional shares resulting from the stock split were distributed by the Company"s transfer agent on May 31, 2007. The number of common shares outstanding as of March 31, 2007 was 121,123,008, before the split, compared to 239,829,787 on June 30, 2007, after the split. NRG retired 14,094,962 treasury shares (post-split) during the second quarter. The Company also repurchased 2,669,200 common shares for $113 million during the quarter, bringing the total for 2007 to 5,669,200 shares repurchased for $215 million. These share repurchase amounts reflect the effect of the stock split. The Company expects to complete Phase II of the previously announced share repurchase program with the repurchase of an estimated $53 million of NRG stock by the third quarter of 2007.

RepoweringNRG Update

Long Beach

On August 1, 2007, the Company successfully completed and commissioned the repowering of 260 MW of new gas-fueled generating capacity at its Long Beach Generating Station. This new generation will provide needed support for the summer peak demand on the SCE and California Independent System Operator systems under a 10-year power purchase agreement executed with SCE in November 2006. Capital spending for the project totaled approximately $75 million.

Cedar Bayou Generating Station

NRG and EnergyCo, a joint venture between PNM Resources Inc. (NYSE:PNM - News) and a subsidiary of Cascade Investment, LLC, have entered into a joint operating agreement to form a 50-50 joint venture 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 ("Cedar Bayou 4"). The air permit was received from the Texas Commission on Environmental Air Quality last week. Negotiations with an engineering, procurement, and construction firm are in the advanced stage. Construction should take no more than 24 months and is expected to create approximately 600 construction jobs at its peak.

"Cedar Bayou 4 demonstrates our substantial competitive advantage in terms of cost, schedule, location, interconnect and access to a highly skilled work force," said Crane. "As a result, the Houston area will get the power it needs, when it is needed and at a price which people can afford."

Cedar Bayou 4 will be operated by NRG Texas" Cedar Bayou operating staff supplemented with 16 new positions at the plant. NRG"s equity contribution will consist of $105 million cash, access to onsite infrastructure and services, and some of the major equipment which NRG had been holding in inventory. Plans also call for Cedar Bayou unit 3, which has been inactive for several years, to be permanently retired.

Wind Power Projects

The Company is working through its subsidiary, Padoma Wind Power, LLC, and has reached a stage of advanced development with respect to three wind projects, totaling approximately 442 MW (before partners) and 350 MW (net ownership). Accordingly, the Company has secured wind turbines from General Electric Company and Siemens Power Generation, Inc. (The planned 50% partner is supplying the wind turbines for the third project). Two of the projects are located in Texas--one is scheduled to commence construction this fall, while the other is scheduled to commence construction in the summer of 2008. The remaining project is located in Southern California with construction planned for the early summer of 2009. The total project cost for all three projects, net of third party contributions, is estimated at $682 million. Project level financing is expected to range from approximately 50-80% of project costs, thereby requiring a net cash investment by the Company of approximately $252 million. The expected capital cost for 2007 is $177 million of which $47 million is projected to be funded through non-recourse debt.

Outlook

The Company is raising 2007 adjusted EBITDA guidance to $2,200 million from $2,150 million and cash flow from operations to $1,420 million from $1,398 million to reflect our strong first half performance, our fully hedged baseload position for the balance of the year and the expected reduction in second half operating expenses. Cash flow from operations and free cash flow guidance from the base business (before repowering expenses) also benefit from the higher earnings outlook. Capital expenditures associated with RepoweringNRG projects are primarily for the Long Beach Emergency Repowering, Cedar Bayou 4 and the advances made in the wind power portfolio.

Table 3: 2007 Reconciliation of Adjusted EBITDA Guidance ($ in
millions)
Guidance Guidance
----------------------------------------------------------------------
8/02/07 5/02/07
Adjusted EBITDA Guidance, excluding MtM $2,200 $2,150
Interest payments (624) (624)
Income tax (23) (15)
Collateral payments (71) (71)
Working capital/other changes (62) (42)
------------ ------------
Cash flow from operations $1,420 $1,398
Capital Expenditures:
Maintenance and environmental (350) (370)
Free cash flow - before Repowering/Pfd. Div $1,070 $1,028
------------ ------------
Preferred Dividends (55) (55)
RepoweringNRG (280)(1) (80)
------------ ------------
Free cash flow $735 $893
------------ ------------
(1) The increase from prior guidance is attributable to the Cedar
Bayou 4 and wind power projects.

Earnings Conference Call

On August 2, 2007, NRG will host a conference call at 10:00 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

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 and wind power projects, the formation and funding of Holdco and timing of our Capital Allocation Plan, 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, August 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 Six months ended
June 30 June 30
------------------------------------
(In millions, except for per share
amounts) 2007 2006 2007 2006
----------------------------------------------------------------------
Operating Revenues
Total operating revenues $ 1,548 $ 1,502 $ 2,858 $ 2,537
----------------------------------------------------------------------
Operating Costs and Expenses
Cost of operations 843 832 1,627 1,482
Depreciation and amortization 161 177 322 295
General and administrative 71 83 157 141
Development costs 36 -- 59 --
----------------------------------------------------------------------
Total operating costs and
expenses 1,111 1,092 2,165 1,918
Gain/(loss) on sale of assets (1) -- 16 --
---------------------------------------------------- -----------------
Operating Income 436 410 709 619
----------------------------------------------------------------------
Other Income/(Expense)
Equity in earnings of
unconsolidated affiliates 8 8 21 29
Write downs and gains on sales of
equity method investments 1 14 1 11
Other income, net 14 8 30 88
Refinancing expense (35) -- (35) (178)
Interest expense (174) (151) (355) (266)
----------------------------------------------------------------------
Total other expense (186) (121) (338) (316)
---------------------------------------------------- -----------------
Income From Continuing Operations
Before Income Taxes 250 289 371 303
Income Tax Expense 101 87 157 86
----------------------------------------------------------------------
Income From Continuing Operations 149 202 214 217
Income from discontinued
operations, net of income tax
expense -- 1 -- 12
----------------------------------------------------------------------
Net Income 149 203 214 229
Dividends for Preferred Shares 14 13 28 23
----------------------------------------------------------------------
Income Available for Common
Stockholders $ 135 $ 190 $ 186 $ 206

Weighted Average Number of Common
Shares Outstanding -- Basic 240 274 241 255
Income From Continuing Operations
per Weighted Average Common
Share -- Basic $ 0.56 $ 0.69 $ 0.77 $ 0.75
Income From Discontinued
Operations per Weighted Average
Common Share -- Basic -- -- -- 0.05
----------------------------------------------------------------------
Net Income per Weighted Average
Common Share -- Basic $ 0.56 $ 0.69 $ 0.77 $ 0.80
----------------------------------------------------------------------

Weighted Average Number of Common
Shares Outstanding -- Diluted 288 319 273 295
Income From Continuing Operations
per Weighted Average Common
Share -- Diluted $ 0.51 $ 0.63 $ 0.71 $ 0.72
Income From Discontinued
Operations per Weighted Average
Common Share -- Diluted -- -- -- 0.04
----------------------------------------------------------------------
Net Income per Weighted Average
Common Share -- Diluted $ 0.51 $ 0.63 $ 0.71 $ 0.76
----------------------------------------------------------------------

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2007 2006
------------------------
(In millions, except for share data) (unaudited)
----------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 795 $ 795
Restricted cash 52 44
Accounts receivable, less allowance for
doubtful accounts of $1 and $1 564 372
Inventory 430 421
Derivative instruments valuation 810 1,230
Deferred income taxes 62 --
Prepayments and other current assets 284 221
----------------------------------------------------------------------
Total current assets 2,997 3,083
----------------------------------------------------------------------
Property, plant and equipment, net of
accumulated depreciation of $1,334 and $984 11,454 11,600
----------------------------------------------------------------------
Other Assets
Equity investments in affiliates 371 344
Notes receivable and capital lease, less
current portion 474 479
Goodwill 1,785 1,789
Intangible assets, net of accumulated
amortization of $319 and $259 931 981
Nuclear decommissioning trust fund 377 352
Derivative instruments valuation 203 439
Deferred income taxes 29 27
Other non-current assets 210 262
Intangible assets held-for-sale 105 79
----------------------------------------------------------------------
Total other assets 4,485 4,752
----------------------------------------------------------------------
Total Assets $18,936 $19,435
----------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS" EQUITY
Current Liabilities
Current portion of long-term debt and
capital leases $ 126 $ 130
Accounts payable 383 332
Derivative instruments valuation 687 964
Deferred income taxes -- 164
Accrued expenses and other current
liabilities 449 442
----------------------------------------------------------------------
Total current liabilities 1,645 2,032
----------------------------------------------------------------------
Other Liabilities
Long-term debt and capital leases 8,609 8,647
Nuclear decommissioning reserve 298 289
Nuclear decommissioning trust liability 335 324
Deferred income taxes 713 554
Derivative instruments valuation 562 351
Out-of-market contracts 768 897
Other non-current liabilities 425 435
----------------------------------------------------------------------
Total non-current liabilities 11,710 11,497
----------------------------------------------------------------------
Total Liabilities 13,355 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 4,028 4,476
Retained earnings 925 739
Less treasury stock, at cost -- 21,175,400
and 29,601,162 shares (500) (732)
Accumulated other comprehensive
income/(loss) (15) 282
----------------------------------------------------------------------
Total Stockholders" Equity 5,333 5,658
--------------------------------------------------------- ------------
Total Liabilities and Stockholders" Equity $18,936 $19,435
----------------------------------------------------------------------

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

(In millions)
Six months ended June 30, 2007 2006
----------------------------------------------------------------------
Cash Flows from Operating Activities
Net income $ 214 $ 229
Adjustments to reconcile net income to net cash
provided by operating activities
Distributions less than equity in earnings of
unconsolidated affiliates (7) (13)
Depreciation and amortization of nuclear fuel 348 308
Amortization and write-off of financing costs and
debt discount/premiums 51 63
Amortization of intangibles and out-of-market
contracts (73) (211)
Amortization of unearned equity compensation 14 9
Changes in deferred income taxes 142 96
Changes in derivatives 47 (41)
Changes in nuclear decommissioning trust liability 20 3
Changes in collateral deposits supporting energy
risk management activities (103) 272
Gain on legal settlement -- (67)
Gain on sale of emission allowances (24) (67)
(Gain)/loss on sale of assets (16) 3
Gain on sale of discontinued operations -- (10)
Write down and gains on sale of equity method
investments (1) (11)
Cash provided/(used) by changes in other working
capital, net of acquisition and disposition
affects (153) 114
----------------------------------------------------------------------
Net Cash Provided by Operating Activities 459 677
----------------------------------------------------------------------
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, and WCP, net of
cash acquired -- (4,328)
Capital expenditures (205) (74)
Increase in restricted cash, net (8) (9)
Decrease in notes receivable 17 14
Purchases of emission allowances (135) (78)
Proceeds from sale of emission allowances 131 84
Investments in nuclear decommissioning trust fund
securities (140) (106)
Proceeds from sale of nuclear decommissioning trust
fund securities 120 103
Proceeds from sale of assets 29 1
Proceeds from sale of investments 2 86
Decrease in trust fund balances 13 --
Investments in marketable securities 4 --
Proceeds from sale of discontinued operations -- 15
----------------------------------------------------------------------
Net Cash Used by Investing Activities (172) (4,292)
----------------------------------------------------------------------
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders (28) (23)
Payment of financing element of acquired
derivatives -- (73)
Payment for treasury stock (215) --
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 7,175
Payment of deferred debt issuance costs -- (164)
Payments for short and long-term debt (1,459) (4,662)
----------------------------------------------------------------------
Net Cash Provided/(Used) by Financing Activities (291) 4,075
----------------------------------------------------------------------
Change in Cash from Discontinued Operations -- 2
Effect of Exchange Rate Changes on Cash and Cash
Equivalents 4 3
----------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents -- 465
Cash and Cash Equivalents at Beginning of Period 795 493
----------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 795 $ 958
----------------------------------------------------------------------

Appendix Table A-1: Second 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
----------------------------------------------------------------------
Net Income (Loss) 134 110 (4) 8
======================================================================
Plus:
Income Tax 102 - - -
Interest Expense 48 14 8 -
Amortization of Finance Costs - - - -
Amortization of Debt
(Discount)/Premium - - 1 -
Refinancing Expense - - - -
Depreciation Expense 114 24 17 1
ARO Accretion Expense - - - -
Amortization of Power Contracts (61) - (6) -
Amortization of Fuel Contracts 14 - - -
Amortization of Emission Credits 9 - - -
----------------------------------------------------------------------
EBITDA 360 148 16 9
Gain on Sale of Equity Method
Investments - - - -

----------------------------------------------------------------------
Adjusted EBITDA 360 148 16 9
----------------------------------------------------------------------


(dollars in millions) International Thermal Corporate Total
----------------------------------------------------------------------
Net Income (Loss) 17 5 (121) 149
======================================================================
Plus:
Income Tax 6 - (7) 101
Interest Expense 2 2 92 166
Amortization of Finance Costs - - 7 7
Amortization of Debt
(Discount)/Premium - - - 1
Refinancing Expense - - 35 35
Depreciation Expense - 3 2 161
ARO Accretion Expense - - 2 2
Amortization of Power
Contracts - - - (67)
Amortization of Fuel Contracts - - - 14
Amortization of Emission
Credits - - - 9
----------------------------------------------------------------------
EBITDA 25 10 10 578
Gain on Sale of Equity Method
Investments - - (1) (1)

----------------------------------------------------------------------
Adjusted EBITDA 25 10 9 577
----------------------------------------------------------------------

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


(dollars in millions) Texas Northeast South Central West
----------------------------------------------------------------------
Net Income (Loss) 256 50 (14) 8
======================================================================
Plus:
Income Tax 36 - - -
Interest Expense 60 14 12 -
Amortization of Finance Costs - - - -
Amortization of Debt
(Discount)/Premium - - 2 -
Depreciation Expense 131 22 18 1
Amortization of Power Contracts (222) - (4) -
Amortization of Fuel Contracts 14 - - -
Amortization of Emission Credits 4 1 1 -
----------------------------------------------------------------------
EBITDA 279 87 15 9
(Income)/Loss from Discontinued
Operations - - - -
Station Service Reserve Reversal - (15) - -
Acquisition Integration Costs - - - -
Mirant Legal Defense - - - -
Gain on Sale of Equity Method
Investments - - - -
----------------------------------------------------------------------
Adjusted EBITDA 279 72 15 9
----------------------------------------------------------------------


(dollars in millions) International Thermal Corporate Total
----------------------------------------------------------------------
Net Income (Loss) 15 3 (115) 203
======================================================================
Plus:
Income Tax 5 - 46 87
Interest Expense 3 2 53 144
Amortization of Finance Costs - - 5 5
Amortization of Debt
(Discount)/Premium - - - 2
Depreciation Expense - 3 2 177
Amortization of Power Contracts - - - (226)
Amortization of Fuel Contracts - - - 14
Amortization of Emission
Credits - - - 6
----------------------------------------------------------------------
EBITDA 23 8 (9) 412
(Income)/Loss from Discontinued
Operations 2 - (3) (1)
Station Service Reserve
Reversal - - - (15)
Acquisition Integration Costs - - 5 5
Mirant Legal Defense - - 6 6
Gain on Sale of Equity Method
Investments (3) - (11) (14)
----------------------------------------------------------------------
Adjusted EBITDA 22 8 (12) 393
----------------------------------------------------------------------

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
----------------------------------------------------------------------
Net Income (Loss) 194 148 6 13
======================================================================
Plus:
Income Tax 155 - - -
Interest Expense 95 29 23 -
Amortization of Finance Costs - - - -
Amortization of Debt
(Discount)/Premium - - 3 -
Refinancing Expense - - - -
Depreciation Expense 228 49 34 1
ARO Accretion Expense - - - -
Amortization of Power Contracts (108) - (11) -
Amortization of Fuel Contracts 27 - - -
Amortization of Emission Credits 19 - - -
----------------------------------------------------------------------
EBITDA 610 226 55 14
Gain on Sale of Equity Method
Investments - - - -
Gain on Asset Sale of Red Bluff
& Chowchilla - - - -
----------------------------------------------------------------------
Adjusted EBITDA 610 226 55 14
----------------------------------------------------------------------


(dollars in millions) International Thermal Corporate Total
----------------------------------------------------------------------
Net Income (Loss) 34 28 (209) 214
======================================================================
Plus:
Income Tax 13 - (11) 157
Interest Expense 9 3 179 338
Amortization of Finance Costs - - 14 14
Amortization of Debt
(Discount)/Premium - - - 3
Refinancing Expense - - 35 35
Depreciation Expense 1 6 3 322
ARO Accretion Expense - - 3 3
Amortization of Power Contracts - - - (119)
Amortization of Fuel Contracts - - - 27
Amortization of Emission
Credits - - - 19
----------------------------------------------------------------------
EBITDA 57 37 14 1,013
Gain on Sale of Equity Method
Investments - - (1) (1)
Gain on Asset Sale of Red Bluff
& Chowchilla - (18) - (18)
----------------------------------------------------------------------
Adjusted EBITDA 57 19 13 994
----------------------------------------------------------------------

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
----------------------------------------------------------------------
Net Income (Loss) 274 182 14 6
======================================================================
Plus:
Income Tax 11 - - (2)
Interest Expense 86 34 26 -
Amortization of Finance Costs - - - -
Amortization of Debt
(Discount)/Premium - - 4 -
Refinancing Expense - - - -
Depreciation Expense 205 44 34 1
Amortization of Power Contracts (263) - (8) -
Amortization of Fuel Contracts 41 - - -
Amortization of Emission Credits 17 9 3 -
----------------------------------------------------------------------
EBITDA 371 270 73 5
(Income)/Loss from Discontinued
Operations - - - -
Station Service Reserve Reversal - (15) - -
Acquisition Integration Costs - - - -
Audrain Asset Sale Adjustment - - - -
Mirant Legal Defense - - - -
Legal Settlement - - - -
Write Down (Gains) on Sale of
Equity Method Investments - - - -
----------------------------------------------------------------------
Adjusted EBITDA 371 255 73 5
----------------------------------------------------------------------


(dollars in millions) International Thermal Corporate Total
----------------------------------------------------------------------
Net Income (Loss) 38 7 (292) 229
======================================================================
Plus:
Income Tax 14 - 63 86
Interest Expense 5 4 97 252
Amortization of Finance Costs - - 10 10
Amortization of Debt
(Discount)/Premium - - - 4
Refinancing Expense - - 178 178
Depreciation Expense 1 6 4 295
Amortization of Power Contracts - - - (271)
Amortization of Fuel Contracts - - - 41
Amortization of Emission
Credits - - (2) 27
----------------------------------------------------------------------
EBITDA 57 17 58 851
(Income)/Loss from Discontinued
Operations 1 - (13) (12)
Station Service Reserve
Reversal - - - (15)
Acquisition Integration Costs - - 7 7
Audrain Asset Sale Adjustment - - 2 2
Mirant Legal Defense - - 6 6
Legal Settlement - - (67) (67)
Write Down (Gains) on Sale of
Equity Method Investments (3) - (8) (11)
----------------------------------------------------------------------
Adjusted EBITDA 55 17 (15) 761
----------------------------------------------------------------------

Appendix Table A-5: First Half 2006 Adjusted Cash Flow from Operations
reconciliation
The following table summarizes the calculation of adjusted cash flow
from operations and provides a reconciliation to cash flow from (used
by) operations:

First Half 2006
Cash Flow from Operations $677
Reclassification of payment of financing element
of acquired derivatives (73)
Adjusted Cash Flow from Operations $604

EBITDA, adjusted EBITDA, adjusted cash flow from operations and free cash flow are non-GAAP 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.

Adjusted cash flow from operations is a non-GAAP measure NRG provides to show cash from operations exclusive of the one-time benefit from the financing element of derivatives acquired from Texas Genco. 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 new release.


Contact:
NRG Energy, Inc.
Investors:
Nahla Azmy, 609-524-4526
Kevin Kelly, 609-524-4527
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