UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported)		November 3, 2006

NRG Energy, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

(State or Other Jurisdiction of Incorporation)

001-15891		41-1724239
(Commission File Number)		(IRS Employer Identification No.)
211 Carnegie Center		Princeton, NJ 08540
(Address of Principal Executive Offices)		(Zip Code)

609-524-4500

(Registrant’s Telephone Number, Including Area Code)

 

(Former Name or Former Address, if Changed Since Last Report)

     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

	o		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
	o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
	o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
	o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

Item 2.02 Results of Operations and Financial Condition

     On November 3, 2006, NRG Energy, Inc. issued a press release announcing its financial results for the quarter ended September 30, 2006. A copy of the press release is furnished as Exhibit 99.1 to this report on Form 8-K and is hereby incorporated by reference.

Item 9.01 Financial Statements and Exhibits

     (d) Exhibits.

Exhibit
Number		Document
99.1		Press Release, dated November 3, 2006

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Dated: November 3, 2006

Exhibit Index

Exhibit
Number		Document
99.1		Press Release, November 3, 2006

Exhibit 99.1

		NEWS RELEASE

FOR IMMEDIATE RELEASE

NRG Energy, Inc. Reports Third Quarter 2006 Results,
Expands Hedging Program, and Plans to Enhance Capital Allocation Program

Third Quarter 2006 Financial Highlights:

•

$444 million of cash flow from operations

•

$519 million of adjusted EBITDA, excluding mark-to-market (MtM) impacts

•

$2.4 billion of total liquidity at September 30, 2006

Hedge Reset and Enhanced Capital Allocation Program:
NRG today announces a coordinated series of initiatives designed to both extend and strengthen our baseload hedging position and to enable further optimization of the Company’s ongoing capital allocation program. These initiatives include:

•

Resetting Legacy NRG Texas out-of-the-money power-related hedges to current market price levels (Hedge Reset) and adding incremental hedges through 2011;

•

Amending our Credit Agreement and launching a debt financing to fund the Hedge Reset;

•

Increasing Phase II of the 2007 share buyback program from $250 million to $500 million and accelerating initiation to the fourth quarter of 2006; and

•

Increasing planned debt reduction from $400 million to $650 million.

As a result of the Hedge Reset, 2007 cash flow from operations and adjusted EBITDA guidance has been raised to $1.5 billion and $2.1 billion, respectively, from previous 2007 guidance provided in January 2006.

Princeton, NJ; (November 3, 2006)—NRG Energy, Inc. (NYSE: NRG) today reported net income before discontinued operations for the three and nine months ended September 30, 2006 of $373 million and $588 million, respectively—as compared to a net loss of $37 million and $4 million for the same periods last year. The quarter and year-to-date improvements primarily resulted from the February acquisition of Texas Genco LLC (now known as NRG Texas) and mark-to-market (MtM) gains in 2006 versus MtM losses in 2005. Net income for the nine months ended September 30, 2006 was impacted by $105 million in after tax refinancing expenses incurred as part of the NRG Texas acquisition, partially offset by $54 million in after-tax one-time gains related to dispute and litigation resolutions.

Cash flow from operations for the quarter was $444 million, including a $77 million benefit from returned cash collateral versus cash used by operations of $205 million during the same period last year. Third quarter 2005 results included a cash collateral outflow of $419 million. Cash flow from operations year-to-date was $1 billion for 2006, an increase of $1.1 billion over 2005. The 2005 results included a cash collateral outflow of $598 million. In addition to returned collateral, 2006 cash flow from operations reflect the contributions from NRG Texas.

Lower generation and energy prices in the Northeast region during the third quarter 2006 were partially offset by $30 million of improved South Central margins achieved mainly through higher plant operating rates. Third quarter 2005 results benefited from $25 million of emission credit revenues versus no sales in the current quarter. Year-to-date results benefited from $68 million in

improved South Central margins largely driven by improved reliability versus the same period last year. Quarterly and year-to-date results included higher levels of general and administrative expenses associated with the NRG Texas integration ($4 million and $11 million, respectively) and development costs ($9 million and $15 million, respectively) incurred in support of Repowering NRG initiatives.

“Our much improved third quarter operating performance helped compensate for soft summer demand for our peaking units and a falling gas price environment,” said David Crane, NRG’s President and Chief Executive Officer. “The relentless strengthening of our liquidity, driven by our free cash flow generation, enables us to grow the value of the business. Today, through our hedge reset and extension program, we provide for increased near-term free cash flow, greater future hedging flexibility and more efficiency in our ability to return capital to shareholders—all while reducing the commodity volatility to our business and improving the Company’s credit profile.”

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		9/30/06				9/30/05				9/30/06				9/30/05
Texas			480				—				431				—
Northeast			150				4				180				28
South Central			24				(8	)			43				8
Australia (1)			6				6				6				6
West			13				6				13				6
Other North America			(7	)			(2	)			1				1
Other International			21				23				24				24
Alternative Energy, Non-generation, Corporate and Other (2)			(79	)			(56	)			19				(18	)
Total			608				(27	)			717				55
Less: MtM forward position accruals (3)			(161	)			172				(161	)			172
Add: Prior Period MtM reversals (4)			(37	)			5				(37	)			5
Total net of MtM Impacts			410				150				519				232

		(1) Includes only Gladstone equity earnings; Flinders is reported as a Discontinued Operation.
		(2) Includes interest expense of $112 million and $54 million for 2006 and 2005, respectively.
		(3) Represents a net domestic MtM gain of $161 million in 2006 (primarily in the Northeast and Texas regions) and a net domestic MtM loss of $172 million in 2005, primarily in the Northeast region.
		(4) Represents the reversal of $37 million in 2006 associated with the $119 million net domestic MtM losses recognized in 2005 and reversal of $5 million in 2005 associated with the $59 million net domestic MtM gain recognized in 2004, primarily in the Northeast region.

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

		Income from Continuing
		Operations before Taxes								Adjusted EBITDA
Nine months ending		9/30/06				9/30/05				9/30/06				9/30/05
Texas			765				—				776				—
Northeast			333				76				435				140
South Central			53				(6	)			117				42
Australia (1)			17				18				18				18
West			17				15				18				15
Other North America (2)			53				(14	)			—				2
Other International			61				92				66				73
Alternative Energy, Non-generation, Corporate and Other (3)			(387	)			(161	)			45				26
Total			912				20				1,475				316
Less: MtM forward position accruals (4)			(208	)			207				(208	)			207
Add: Prior Period MtM reversals (5)			(102	)			55				(102	)			55
Total net of MtM Impacts			602				282				1,165				578

		(1) Includes only Gladstone equity earnings; Flinders is reported as a Discontinued Operation.
		(2) Includes $67 million pre-tax gain for settlement with equipment manufacturer in 2006.
		(3) Includes interest and refinancing expenses of $402 million and $168 million for 2006 and 2005, respectively.
		(4) Represents a net domestic MtM gain of $208 million in 2006 (primarily in the Northeast and Texas regions) and a net domestic MtM loss of $207 million in 2005, primarily in the Northeast region.
		(5) Represents the reversal of $102 million in 2006 associated with the $119 million net domestic MtM losses recognized in 2005 and reversal of $55 million in 2005 associated with the $59 million net domestic MtM gain recognized in 2004, primarily the Northeast region.

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 2006, we recorded $161 million of forward domestic net MtM gains, compared to a $172 million net domestic MtM loss recorded in the third quarter 2005. In addition to this forward gain in the quarter, of the $119 million MtM loss recognized in 2005, $37 million reversed to income during the third quarter in 2006 and $102 million year-to-date. Driving the forward MtM gains in 2006 were the lower energy prices for the first nine months of this year mainly due to unseasonably mild winter weather in the Northeast and the high levels of natural gas inventories in 2006. Another contributing factor is the expansion of heat rates in ERCOT, resulting in a $78 million quarterly MtM gain in our Texas region. In 2005, the MtM losses primarily resulted from the run up in natural gas prices which occurred as a result of the impact hurricanes Katrina and Rita had on natural gas production in the Gulf of Mexico.

Texas: Continued strong operating performances from our baseload fleet, and higher generation from our Texas gas plants, were partially offset by lower power prices realized on merchant energy sales and the unhedged portion of our baseload fleet. Amortization associated with net out-of-market contracts increased pre-tax operating results by $219 million and $482 million for the quarter and year-to-date, respectively. The NRG Texas integration of key financial and operating systems and processes was completed during the quarter, as scheduled.

Northeast: Lower quarterly results for the Northeast, after adjusting for MtM impacts, were due to weaker power prices and lower generation. Reduced demand for our peaking assets resulted in lower generation hours from oil-fired and intermediate gas-fired assets. Also, 2005 third quarter results for the Northeast included revenues from the sale of emission credits, versus no recorded sales in the current quarter. Partially offsetting the lower demand and emission sales were improved capacity revenues and improved operating performance from our baseload fleet. Year-to-date, mild weather in the first two quarters, along with continuing weak power prices, were partially offset by surplus emission allowance sales in the first quarter, improved operating performance and higher capacity prices.

South Central: Improved quarterly and year-to-date results reflect higher net merchant energy sales at levels above contracted energy prices. Improved unit availability reduced the need to purchase power to service our long-term co-op contracts. Summer capacity revenues were also higher than last year due to new summer peak levels set in 2005. A new summer peak demand record was set in 2006 which will reset the capacity payments and benefit 2007 earnings.

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

Australia: In June 2006, NRG entered into a purchase and sale agreement to sell its Flinders and Gladstone investments in Australia to Babcock & Brown and Transfield Services, respectively. While Flinders has been reclassified as discontinued operations and excluded from income from continuing operations, Gladstone results continue to be reported as part of equity earnings of unconsolidated affiliates. On August 30, 2006, the Company completed the Flinders sale — receiving $242 million in proceeds resulting in a $61 million after-tax gain on the sale, which is included in discontinued operations. As a result of this sale, NRG also removed $183 million of non-recourse debt obligations from our balance sheet. We continue our efforts to close the Gladstone transaction; however, the sale is subject to significant conditions precedent which will likely prevent us from closing the transaction this year.

Other North America: Year-to-date results include other income of $67 million related to a settlement agreement associated with turbine purchase agreements from 1999 and 2001. This increase was partially offset by the March 31, 2006 sale of our 50 percent interest in the Rocky Road project.

Other International: Year-on-year results are lower largely due to the impact of the sale of Enfield on April 1, 2005, which contributed $16 million to equity earnings and a $12 million pre-tax gain from the sale of this investment.

Liquidity and Capital Resources

Table 2: Corporate Liquidity
($ in millions)

										December 31,
		September 30, 2006				June 30, 2006(1)				2005(1)
Unrestricted Cash			1,388				957			$	506
Restricted Cash			74				58				64
Total Cash			1,462				1,015			$	570
Letter of Credit Availability			142				116				38
Revolver Availability			843				846				150
Total Current Liquidity			2,447				1,977			$	758

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

Liquidity at September 30, 2006 was approximately $2.4 billion, up $470 million since June 30, 2006 and up approximately $1.7 billion since December 31, 2005. The $447 million cash increase during the quarter resulted from $444 million of cash from operations and $242 million in proceeds from the sale of Flinders. These improvements were partially offset by $99 million in cash used for treasury stock purchases under Phase I of the capital allocation program, $62 million in capital expenditures, $35 million in principal debt repayments and $14 million in preferred dividend payments. Posted cash collateral supporting hedging and trading activities at September 30, 2006 totaled $132 million.

Recent Developments
The Company is in the process of implementing a series of transactions that are designed to reduce the earnings impact of commodity volatility, increase capital structure efficiency and flexibility, and expand the capacity for the return of capital to shareholders, while committing to debt reduction. These transactions include:

•

Resetting existing out-of-the-money hedges (acquired as part of the NRG Texas acquisition) primarily for years 2006 through 2010 to current market price levels;

•

Placing new hedges on baseload power generation for the years 2010 and 2011 (increasing the baseload hedge positions to 48% and 53%, respectively), and opening up counterparty capacity for additional hedges in 2010 through 2012;

•

Amending the senior secured credit facility; and

•

Incurring $1.1 billion of unsecured debt and use of cash on hand to fund the reset of existing hedges.

Under the amended agreements, NRG has reset the pricing of these hedges to current market prices and has agreed to a negotiated cash settlement with hedge counterparties. The total amount to be paid to the counterparties is approximately $1.3 billion. NRG’s obligations under the new and amended hedges are or will be secured by second liens on substantially all of the assets of NRG and its subsidiaries, pursuant to NRG’s existing second lien structure. Already, with the additional hedge capacity made available as a result of the Hedge Reset, NRG has increased its baseload hedged profile from 41 percent to 48 percent in 2010 and from 19 percent to 53 percent in 2011 at prices above those assumed in the valuation of NRG Texas.

Resetting existing hedges also improves the Company’s near term earnings, cash flows, and credit profile which contribute to the Company’s ability to amend the existing senior secured credit facilities. The main amendments, among other things:

•

Permit the incurrence of debt to fund the Hedge Reset;

•

Increase the amount of the synthetic letter of credit facility by $500 million, from $1.0 billion to $1.5 billion to support incremental hedging activity; and

•

Increase and reset the restricted payments basket to $500 million along with a more appropriate annual adder calculation.

The transactions are expected to close by November 21, 2006. The primary financial statement impacts will be a $1.1 billion increase in long-term debt and $1.3 billion in higher cash flows from operations in 2007 through 2010. Partially offsetting the debt increase will be the previously announced $400 million pay down of the Term B debt and the use of approximately $250 million of cash to fund the Hedge Reset.

In connection with the Hedge Reset, the Company expects to record a noncash after-tax loss of approximately $60 million in the fourth quarter 2006. The loss is due primarily to the assumptions used for the purchase price accounting at the NRG Texas acquisition date.

“These transactions will have an immediate and positive impact on the Company’s financial profile and provide the capacity and flexibility to allocate capital to investment opportunities, debt reduction, and a continuing return of capital to shareholders,” stated Robert Flexon, NRG Executive Vice President and Chief Financial Officer. “The transactions will also significantly improve our 2007 credit statistics, in particular the leverage and coverage ratios as well as operating cash flows.”

Capital Allocation — Share Repurchase Program — Phase I Completed and Phase II Upsized
During the third quarter 2006, NRG initiated our third share repurchase program since 2004—a capital allocation program to repurchase approximately $750 million of its common stock in two phases. On October 13, 2006, the Company completed Phase I, which included $500 million, or 10.6 million shares in stock repurchases. Phase II—originally an additional $250 million common stock buyback to be initiated and completed in the first half of 2007—has been upsized to $500 million with a fourth quarter 2006 accelerated start date. The Company expects to fund Phase II with cash on hand and 2007 cash from operations and anticipates completion by the end of the second quarter next year. Consistent with our approach in managing the debt and equity balance, the Company is utilizing $250 million of cash on hand to fund the Hedge Reset.

“A balanced capital allocation program is a fundamental component of our financial philosophy,” commented Crane. “Since 2004, the Company has paid down or removed, in connection with asset sales, more than $2.0 billion of consolidated debt, and now—with the upsized Phase II share buyback—we will be on track to bringing the total amount of capital returned to NRG shareholders to over $1.6 billion.”

Outlook for 2006 and 2007
The Company is maintaining its existing 2006 adjusted EBITDA guidance of $1.5 billion and updating the cash flow from operations guidance to $1.29 billion reflecting increased interest cash costs associated with higher interest rates and from the borrowings incurred in Phase I of the capital allocation program. Although commodity prices declined during the quarter and generation hours were slightly below expectations, hedges on the portfolio mitigated the impact of these factors. (See Table 3.)

Our 2007 adjusted EBITDA and cash flow guidance has been updated to $2.1 billion and $1.5 billion, respectively, reflecting the impact of the Hedge Reset and the interest costs associated with the incremental debt. Table 4 reconciles our previous 2007 guidance with our updated outlook.

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

		08/01/06				11/03/06
Adjusted EBITDA, including MTM		$1,616				$1,810
MtM adjustment			116				310
Adjusted EBITDA Guidance			1,500				1,500
Interest payments			(439	)			(459	)
Income tax			(13	)			(15	)
Refinancing payments			(127	)			(127	)
Collateral received			407				400
Working capital/other changes			(4	)			(9	)
Cash flow from operations		$	1,324			$	1,290

Table 4: 2007 Reconciliation of Adjusted EBITDA Guidance ($ in millions)

Adjusted EBITDA Guidance — 01/05/06 (excluding MtM)		$	1,558
Portfolio Changes:
Sale of Australia businesses			(70	)
Other portfolio changes			(19	)
Development expenses(1)			(36	)
Hedge Reset			650
Other, net			(33	)
Updated Adjusted EBITDA Guidance — 11/03/06 (excluding MtM)			2,050
Interest payments			(634	)
Income taxes			(15	)
Collateral received			42
Working capital/other charges			7
Cash flow from operations		$	1,450
Capital Expenditures			(352	)
Preferred dividends			(53	)
Free cash flow		$	1,045

		(1) Assumes $63 million of cost reimbursement for STP development expenses.

Earnings Conference Call
On November 3, 2006, NRG will host a conference call at 9:00 a.m. eastern to discuss these results. To access the live web cast and accompanying slide presentation, log on to NRG’s website at http://www.nrgenergy.com and click on “Investors.” To participate in the call, dial 866.585.6398. International callers should dial 416.849.9626. Participants should dial in or log on approximately five minutes prior to the scheduled start time.

The call will be available for replay shortly after completion of the live event on the “Investors” section of the NRG website.

About NRG
NRG Energy, Inc. owns and operates a diverse portfolio of power-generating facilities, primarily in Texas and the Northeast, South Central and West regions of the United States. Its operations include baseload, intermediate, peaking, and cogeneration facilities and thermal energy production. NRG also has ownership interests in generating facilities in Australia, Germany and Brazil.

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, the timing and completion of announced transactions (including the hedge resets, incurrence of unsecured debt and credit amendments), the expected benefits and timing of the announced capital allocation program, expected earnings, future growth and financial performance, and the expected timing of sales of our assets in Australia, 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 of our hedging and capital allocation programs

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 guidance are estimates as of today’s date, November 3, 2006 and is based on assumptions believed to be reasonable as of this date. NRG expressly disclaims any current intention to update such guidance. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in the forward-looking statements included in this news release should be considered in connection with information regarding risks and uncertainties that may affect NRG’s future results included in NRG’s filings with the Securities and Exchange Commission at www.sec.gov.

This news release shall not be deemed to constitute an offer to sell or offer for sale of any security.

# # #

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

Contacts:

		Media:				Investors:
		Meredith Moore				Nahla Azmy
			609.524.4522				609.524.4526
		Lori Neuman				Kevin Kelly
			609.524.4525				609.524.4527
						Jon Baylor
							609.524.4528

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)		2006				2005				2006				2005
Operating Revenues
Revenues from majority-owned operations		$	2,000			$	687			$	4,479			$	1,723
Operating Costs and Expenses
Cost of majority-owned operations			1,055				604				2,478				1,378
Depreciation and amortization			148				41				443				121
General, administrative and development			79				42				220				136
Impairment charges			—				6				—				6
Corporate relocation charges			—				2				—				6
Total operating costs and expenses			1,282				695				3,141				1,647
Operating Income/(Loss)			718				(8	)			1,338				76
Other Income (Expense)
Equity in earnings of unconsolidated affiliates			17				29				46				82
Write downs and gains/(losses) on sales of equity method investments			(3	)			4				8				16
Other income, net			30				10				118				41
Refinancing expense			—				(19	)			(178	)			(54	)
Interest expense			(154	)			(43	)			(420	)			(141	)
Total other expense			(110	)			(19	)			(426	)			(56	)
Income/(Loss) From Continuing Operations Before Income Taxes			608				(27	)			912				20
Income Tax Expense			235				10				324				24
Income/(Loss) From Continuing Operations			373				(37	)			588				(4	)
Income from discontinued operations, net of income tax expense			49				10				63				24
Net Income/(Loss)			422				(27	)			651				20
Dividends for Preferred Shares			14				4				37				12
Income/(Loss) Available for Common Stockholders		$	408			$	(31	)		$	614			$	8
Weighted Average Number of Common Shares Outstanding — Basic			136				84				130				86
Income/(Loss) From Continuing Operations per Weighted Average Common Share — Basic		$	2.64			$	(0.51	)		$	4.22			$	(0.21	)
Income From Discontinued Operations per Weighted Average Common Share — Basic			0.36				0.12				0.48				0.28
Net Income/(Loss) per Weighted Average Common Share — Basic		$	3.00			$	(0.39	)		$	4.70			$	0.07
Weighted Average Number of Common Shares Outstanding — Diluted			159				84				151				86
Income/(Loss) From Continuing Operations per Weighted Average Common Share — Diluted		$	2.34			$	(0.51	)		$	3.85			$	(0.21	)
Income From Discontinued Operations per Weighted Average Common Share — Diluted			0.31				0.12				0.41				0.28
Net Income/(Loss) per Weighted Average Common Share — Diluted		$	2.65			$	(0.39	)		$	4.26			$	0.07

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

		September 30,				December 31,
		2006				2005
(in millions, except shares and par value)		(unaudited)
ASSETS
Current Assets
Cash and cash equivalents		$	1,388			$	493
Restricted cash			74				49
Accounts receivable, less allowance for doubtful accounts of $3 and $2			433				249
Inventory			397				240
Deferred income taxes			59				—
Derivative instruments valuation			961				387
Collateral on deposits in support of energy risk management activities			132				438
Prepayments and other current assets			214				187
Current assets — held-for-sale			—				43
Current assets — discontinued operations			13				110
Total current assets			3,671				2,196
Property, plant and equipment, net of accumulated depreciation of $814 and $343			11,686				2,609
Other Assets
Equity investments in affiliates			319				602
Notes receivable, less current portion			468				457
Goodwill			1,547				—
Intangible assets, net of accumulated amortization of $169 and $79			1,001				257
Intangible assets held-for-sale			53				—
Nuclear decommissioning trust fund			331				—
Derivative instruments valuation			360				18
Funded letter of credit			—				350
Deferred income taxes			27				26
Other non-current assets			244				124
Non-current assets — discontinued operations			14				827
Total other assets			4,364				2,661
Total Assets		$	19,721			$	7,466
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases		$	123			$	95
Accounts payable			278				241
Derivative instruments valuation			901				679
Accrued expenses and other current liabilities			485				172
Current liabilities — discontinued operations			8				170
Total current liabilities			1,795				1,357
Other Liabilities
Long-term debt and capital leases			7,826				2,410
Nuclear decommissioning reserve			278				—
Nuclear decommissioning trust liability			319				—
Deferred income taxes			362				128
Derivative instruments valuation			369				56
Out-of-market contracts			2,128				298
Other non-current liabilities			386				170
Non-current liabilities — discontinued operations			5				569
Total non-current liabilities			11,673				3,631
Total Liabilities			13,468				4,988
Minority Interest			1				1
3.625% Convertible perpetual preferred stock (at liquidation value, net of issuance costs)			247				246
Commitments and Contingencies
Stockholders’ Equity
Preferred stock (at liquidation value, net of issuance costs)			892				406
Common Stock; $.01 par value; 500,000,000 shares authorized; 137,030,642 and 80,701,888 outstanding			1				1
Additional paid-in capital			4,458				2,431
Retained earnings			782				261
Less treasury stock, at cost — 6,113,000 and 19,346,788 shares			(297	)			(663	)
Accumulated other comprehensive income/(loss)			169				(205	)
Total stockholders’ equity			6,005				2,231
Total Liabilities and Stockholders’ Equity		$	19,721			$	7,466

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

		Nine months ended September 30
(In millions)		2006				2005
Cash Flows from Operating Activities
Net income		$	651			$	20
Adjustments to reconcile net income to net cash provided by operating activities
Distributions in excess of equity in earnings of unconsolidated affiliates			(27	)			1
Depreciation and amortization			490				145
Amortization of financing costs and debt discount			24				8
Amortization of intangibles and out-of-market contracts			(393	)			16
Amortization of unearned equity compensation			13				8
Write-off of deferred financing costs and debt premium			47				(7	)
Write down and (gains) on sale of equity method investments			(8	)			(16	)
Asset impairment			—				6
Changes in deferred income taxes			309				(54	)
Nuclear decommissioning trust liability			9				—
Minority interest			—				1
Loss on sale of equipment			3				—
Changes in derivatives			(301	)			252
Gain on legal settlement			(67	)			(14	)
Gain on sale of discontinued operations			(71	)			(11	)
Gain on sale of emission allowances			(68	)			—
Collateral deposit payments in support of energy risk management activities			349				(598	)
Cash provided by changes in other working capital, net of acquisition and disposition affects			88				129
Net Cash Provided/(Used) by Operating Activities			1,048				(114	)
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, net of cash acquired			(4,304	)			—
Acquisition of WCP and Padoma, net of cash acquired			(32	)			—
Decrease/(Increase) in restricted cash, net			(24	)			18
Decrease in notes receivable			22				100
Purchases of emission allowances			(76	)			—
Sales of emission allowances			97				—
Investments in nuclear decommissioning trust fund securities			(158	)			—
Proceeds from sales of nuclear decommissioning trust fund securities			149				—
Proceeds from sale of equipment			1				—
Proceeds from sale of investments			86				70
Proceeds from sale of discontinued operations			239				36
Return of capital from equity method investments and projects			—				1
Capital expenditures			(159	)			(46	)
Net Cash Provided/(Used) by Investing Activities			(4,159	)			179
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders			(37	)			(12	)
Payment for treasury stock			(297	)			(251	)
Repayment of minority interest obligations			—				(4	)
Borrowing under revolving credit facility, net			—				80
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				246
Payment of deferred debt issuance costs			(174	)			(2	)
Proceeds from issuance of long-term debt, net			7,373				249
Payments for short and long-term debt			(4,697	)			(979	)
Net Cash Provided/(Used) by Financing Activities			3,990				(673	)
Change in Cash from Discontinued Operations			14				17
Effect of Exchange Rate Changes on Cash and Cash Equivalents			2				(1	)
Net Increase in Cash and Cash Equivalents			895				592
Cash and Cash Equivalents at Beginning of Period			493				1,069
Cash and Cash Equivalents at End of Period		$	1,388			$	477

Appendix Table A-1: 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				Western				Other NA				Australia				Other Int’l				Other				Total
Net Income/(Loss)			445				150				24				13				(6	)			(5	)			78				(277	)			422
Plus:
Income Tax			34				—				—				—				(1	)			1				4				197				235
Interest Expense			34				14				9				—				3				—				2				85				147
Amortization of Finance Costs			—				—				—				—				—				—				—				5				5
Amortization of Debt (Discount)/Premium			—				—				1				—				1				—				—				—				2
Depreciation Expense			104				22				15				—				3				—				1				3				148
Amortization of Power Contracts			(219	)			—				(6	)			—				—				—				—				—				(225	)
Amortization of Fuel Contracts			22				—				—				—				—				—				—				—				22
Amortization of Emission Credits			11				1				—				—				—				—				—				—				12
EBITDA			431				187				43				13				—				(4	)			85				13				768
(Income)/Loss from Discontinued Operations			—				—				—				—				—				10				(61	)			2				(49	)
Write-Down and (Gain)/Losses on Sales of Equity Method Investments			—				—				—				—				3				—				—				—				3
Acquisition Integration Costs			—				—				—				—				—				—				—				4				4
Audrain bad debt reversal			—				—				—				—				(2	)			—				—				—				(2	)
Legal Settlement			—				(7	)			—				—				—				—				—				—				(7	)
Adjusted EBITDA			431				180				43				13				1				6				24				19				717

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

(dollars in millions)		Northeast				South Central				Western				Other NA				Australia				Other Int’l				Other				Total
Net Income/(Loss)			4				(8	)			6				(4	)			3				17				(45	)			(27	)
Plus:
Income Tax			—				—				—				1				2				5				2				10
Interest Expense			—				2				—				3				—				1				34				40
Amortization of Finance Costs			—				—				—				—				—				—				1				1
Amortization of Debt (Discount)/Premium			—				1				—				2				—				—				(1	)			2
Depreciation Expense			19				16				—				2				—				1				3				41
Amortization of Power Contracts			—				(4	)			—				—				—				—				—				(4	)
Amortization of Emission Credits			5				1				—				—				—				—				—				6
EBITDA			28				8				6				4				5				24				(6	)			69
(Income)/Loss from Discontinued Operations			—				—				—				1				1				—				(12	)			(10	)
Write-Down and (Gain)/Losses on Sales of Equity Method Investments			—				—				—				(4	)			—				—				—				(4	)
Adjusted EBITDA			28				8				6				1				6				24				(18	)			55

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

(dollars in millions)		Texas				Northeast				South Central				Western				Other NA				Australia				Other Int’l				Other				Total
Net Income/(Loss)			719				333				53				19				62				3				108				(646	)			651
Plus:
Income Tax			45				—				—				(2	)			—				4				14				263				324
Interest Expense			98				48				28				—				10				—				6				210				400
Amortization of Finance Costs			—				—				—				—				—				—				—				15				15
Amortization of Debt (Discount)/Premium			—				—				2				—				3				—				—				—				5
Refinancing Expense			—				—				—				—				—				—				—				178				178
Depreciation Expense			309				66				45				1				6				—				2				14				443
Amortization of Power Contracts			(482	)			—				(14	)			—				—				—				—				—				(496	)
Amortization of Fuel Contracts			59				—				—				—				—				—				—				—				59
Amortization of Emission Credits			28				10				3				—				—				—				—				(2	)			39
EBITDA			776				457				117				18				81				7				130				32				1,618
(Income)/Loss from Discontinued Operations			—				—				—				—				(9	)			11				(61	)			(4	)			(63	)
Write-Down and (Gain)/Losses on Sales of Equity Method Investments			—				—				—				—				(5	)			—				(3	)			—				(8	)
Bourbonnais Legal Settlement			—				—				—				—				(67	)			—				—				—				(67	)
Acquisition Integration Costs			—				—				—				—				—				—				—				11				11
Legal Settlement			—				(7	)			—				—				—				—				—				—				(7	)
Station Service Reserve Reversal			—				(15	)			—				—				—				—				—				—				(15	)
Mirant Defense			—				—				—				—				—				—				—				6				6
Adjusted EBITDA			776				435				117				18				—				18				66				45				1,475

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

(dollars in millions)		Northeast				South Central				Western				Other NA				Australia				Other Int’l				Other				Total
Net Income/(Loss)			76				(6	)			15				(14	)			17				78				(146	)			20
Plus:
Income Tax			—				—				—				2				5				13				4				24
Interest Expense			—				5				—				10				—				5				113				133
Amortization of Finance Costs			—				—				—				—				—				—				4				4
Amortization of Debt (Discount)/Premium			—				2				—				4				—				—				(2	)			4
Refinancing Expense			—				—				—				—				—				—				54				54
Depreciation Expense			56				46				—				5				—				3				11				121
Amortization of Power Contracts			—				(10	)			—				5				—				—				—				(5	)
Amortization of Emission Credits			8				5				—				—				—				—				—				13
EBITDA			140				42				15				12				22				99				38				368
(Income)/Loss from Discontinued Operations			—				—				—				(2	)			(4	)			—				(18	)			(24	)
Corporate Relocation charges			—				—				—				—				—				—				6				6
Write-Down and (Gain)/Losses on Sales of Equity Method Investments			—				—				—				(4	)			—				(12	)			—				(16	)
Proceeds Received from Crockett Contingency			—				—				—				(4	)			—				—				—				(4	)
Gain on TermoRio Settlement			—				—				—				—				—				(14	)			—				(14	)
Adjusted EBITDA			140				42				15				2				18				73				26				316

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 free cash flow 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 or other nonrecurring events; 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 investments. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. In addition, in evaluating free cash flow, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.