FORM 10-Q
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
 
 
     
þ
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the quarterly period ended: September 30, 2008
 
 
Commission File Number: 001-15891
 
NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)
 
 
     
Delaware
  41-1724239
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
     
211 Carnegie Center Princeton,
New Jersey
(Address of principal executive offices)
  08540
(Zip Code)
 
 
(609) 524-4500
(Registrant’s telephone number, including area code)
 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ     No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
    (Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o      No þ
 
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities and Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
Yes þ     No o
 
As of October 23, 2008, there were 233,047,222 shares of common stock outstanding, par value $0.01 per share.
 


 

 
TABLE OF CONTENTS
 
Index
 
 
                 
            Page
            No.
 
    3  
    4  
PART I
    FINANCIAL INFORMATION     7  
    CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES     7  
    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS     42  
    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK     80  
    CONTROLS AND PROCEDURES     84  
    OTHER INFORMATION     85  
    LEGAL PROCEEDINGS     85  
    RISK FACTORS     85  
    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS     85  
    DEFAULTS UPON SENIOR SECURITIES     85  
    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS     85  
    OTHER INFORMATION     85  
    EXHIBITS     86  
    87  
 EX-3.1: SECOND CERTIFICATE OF AMENDMENT TO CERTIFICATE OF DESIGNATIONS
 EX-10.1: NOTE PURCHASE AMENDMENT AGREEMENT
 EX-10.2: PREFERRED INTEREST AMENDMENT AGREEMENT
 EX-31.1: CERTIFICATION
 EX-31.2: CERTIFICATION
 EX-31.3: CERTIFICATION
 EX-32: CERTIFICATION


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CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
 
This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The words “believes”, “projects”, “anticipates”, “plans”, “expects”, “intends”, “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause NRG’s actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risks Related to NRG in Part I, Item 1A, of the Company’s Annual Report on Form 10-K, for the year ended December 31, 2007, including the following:
 
  •  General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;
 
  •  Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;
 
  •  The effectiveness of NRG’s risk management policies and procedures, and the ability of NRG’s counterparties to satisfy their financial commitments;
 
  •  Counterparties’ collateral demands and other factors affecting NRG’s liquidity position and financial condition;
 
  •  NRG’s ability to operate its businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
 
  •  NRG’s ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;
 
  •  The liquidity and competitiveness of wholesale markets for energy commodities;
 
  •  Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other greenhouse gas emissions;
 
  •  Price mitigation strategies and other market structures employed by independent system operators, or ISOs, or regional transmission organizations, or RTOs, that result in a failure to adequately compensate NRG’s generation units for all of its costs;
 
  •  NRG’s ability to borrow additional funds and access capital markets, as well as NRG’s substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;
 
  •  Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG’s outstanding notes, in NRG’s Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;
 
  •  NRG’s ability to implement its RepoweringNRG strategy of developing and building new power generation facilities, including new nuclear units and wind projects;
 
  •  NRG’s ability to implement its econrg strategy of finding ways to meet the challenges of climate change, clean air and protecting our natural resources while taking advantage of business opportunities; and
 
  •  NRG’s ability to achieve its strategy of regularly returning capital to shareholders.
 
Forward-looking statements speak only as of the date they were made, and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.


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GLOSSARY OF TERMS
 
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
 
Acquisition February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Company’s Texas region
ABWR Advanced Boiling Water Reactor
ANPR Advanced Notice of Proposed Rulemaking
ARO Asset Retirement Obligation
BACT Best Available Control Technology
Baseload Capacity Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
BP BP Alternative Energy North America Inc.
BTU British Thermal Unit
CAA Clean Air Act
CAIR Clean Air Interstate Rule
CAMR Clean Air Mercury Rule
CDWR California Department of Water Resources
CL&P Connecticut Light & Power
CO2 Carbon dioxide
COLA Combined Operating License Application
CS Credit Suisse Group
CSF I NRG Common Stock Finance I LLC
CSF II NRG Common Stock Finance II LLC
DNREC Delaware Department of Natural Resources
DPUC Connecticut Department of Public Utility Control
EFOR Equivalent Forced Outage Rates — considers the equivalent impact that forced de-ratings have in addition to full forced outages
EPC Engineering, Procurement and Construction
ERCOT Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESPP Employee Stock Purchase Plan
Exchange Act The Securities Exchange Act of 1934, as amended
FASB Financial Accounting Standards Board, the designated organization for establishing standards for financial accounting and reporting
FCM Forward Capacity Market
FERC Federal Energy Regulatory Commission
FIN FASB Interpretation
FIN 48 FIN 48, Accounting for Uncertainty in Income Taxes
FSP FASB Staff Position
GHG Greenhouse Gases
IGCC Integrated Gasification Combined Cycle
ISO Independent System Operator, also referred to as Regional Transmission Organization, or RTO
ISO-NE ISO New England, Inc.
ITISA Itiquira Energetica S.A.
kW Kilowatts
kWh Kilowatt-hours
LFRM Locational Forward Reserve Market
LIBOR London Inter-Bank Offer Rate
LMP Locational Marginal Prices
LTIP Long-Term Incentive Plan
MACT Maximum Achievable Control Technology
Merit Order A term used for the ranking of power stations in terms of increasing order of fuel costs
MMBtu Million British Thermal Units
MOU Memorandum of Understanding


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GLOSSARY OF TERMS (cont’d)
 
MRTU Market Redesign and Technology Upgrade
MW Megawatts
MWh Saleable megawatt hours net of internal/parasitic load megawatt-hours
NAAQS National Ambient Air Quality Standard
NEPOOL New England Power Pool
Net Exposure Counterparty credit exposure to NRG, net of collateral
NiMo Niagara Mohawk Power Corporation
NINA Nuclear Innovation North America LLC
NOx Nitrogen oxide
NOL Net Operating Loss
NOV Notice of Violation
NPNS Normal Purchase Normal Sale
NRC Nuclear Regulatory Commission
NYISO New York Independent System Operator
NYPA New York Power Authority
OCI Other Comprehensive Income
Phase II 316(b) Rule A section of the Clean Water Act regulating cooling water intake structures
PJM PJM Interconnection LLC
PJM Market The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia
PMI NRG Power Marketing LLC, a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manages all commodity trading and hedging for NRG
PPA Power Purchase Agreement
PPM Parts per Million
PSD Prevention of Significant Deterioration
PUCT The Public Utility Commission of Texas
Repowering Replacing, rebuilding, or redeveloping major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency
RepoweringNRG NRG’s program designed to develop, finance, construct and operate new, highly efficient, environmentally responsible capacity over the next decade
Revolving Credit Facility NRG’s $1 billion senior secured credit facility which matures on February 2, 2011
RGGI Regional Greenhouse Gas Initiative
RMR Reliability Must-Run
RPM Reliability Pricing Model — term for capacity market in PJM market
RTO Regional Transmission Organization, also referred to as an Independent System Operator, or ISO
Sarbanes-Oxley Sarbanes-Oxley Act of 2002
SEC United States Securities and Exchange Commission
Securities Act The Securities Act of 1933, as amended
Senior Credit Facility NRG’s senior secured facility, which is comprised of a Term B loan facility and a $1.3 billion Letter of Credit Facility which mature on February 1, 2013, and a $1 billion Revolving Credit Facility, which matures on February 2, 2011
Senior Notes The Company’s $4.7 billion outstanding unsecured senior notes consisting of $1.2 billion of 7.25% senior notes due 2014, $2.4 billion of 7.375% senior notes due 2016 and $1.1 billion of 7.375% senior notes due 2017
SFAS Statement of Financial Accounting Standards issued by the FASB
SFAS 109 SFAS No. 109, “Accounting for Income Taxes”
SFAS 133 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141R SFAS No. 141 (revised 2007), “Business Combinations”
SFAS 157 SFAS No. 157, “Fair Value Measurements


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GLOSSARY OF TERMS (cont’d)
 
SFAS 160 SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements”
SFAS 161 SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133
Sherbino Sherbino I Wind Farm LLC
SO2 Sulfur dioxide
SOP Statement of Position issued by the American Institute of Certified Public Accountants
STP South Texas Project — Nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC South Texas Project Nuclear Operating Company
Synthetic Letter of Credit Facility NRG’s $1.3 billion senior secured synthetic letter of credit facility which matures on February 1, 2013
Term B loan A senior first priority secured term loan which matures on February 1, 2013, and is included as part of NRG’s Senior Credit Facility
Texas Genco Texas Genco LLC, now referred to as the Company’s Texas region
Texas West The West Zone of Texas’ ERCOT power market
Tosli Tosli Acquisition B.V.
US United States of America
USEPA United States Environmental Protection Agency
US GAAP Accounting principles generally accepted in the United States
VAR Value at Risk
WCP WCP (Generation) Holdings, LLC


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PART I — FINANCIAL INFORMATION
 
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
 
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)       2008     2007     2008     2007      
 
Operating Revenues
                                       
Total operating revenues
      $   2,690     $   1,772     $   5,308     $   4,607      
 
 
Operating Costs and Expenses
                                       
Cost of operations
        997       939       2,812       2,560      
Depreciation and amortization
        156       160       478       481      
General and administrative
        75       78       233       234      
Development costs
        13       49       29       108      
 
 
Total operating costs and expenses
        1,241       1,226       3,552       3,383      
Gain on sale of assets
                          16      
 
 
Operating Income
        1,449       546       1,756       1,240      
 
 
Other Income/(Expense)
                                       
Equity in earnings of unconsolidated affiliates
        58       19       35       40      
Other (loss)/income, net
        (7 )     14       14       44      
Refinancing expense
                          (35 )    
Interest expense
        (186 )     (169 )     (481 )     (520 )    
 
 
Total other expense
        (135 )     (136 )     (432 )     (471 )    
 
 
Income From Continuing Operations Before Income Taxes
        1,314       410       1,324       769      
Income tax expense
        530       145       531       300      
 
 
Income From Continuing Operations
        784       265       793       469      
Income from discontinued operations, net of income tax expense
              3       172       13      
 
 
Net Income
        784       268       965       482      
Dividends for preferred shares
        13       13       41       41      
 
 
Income Available for Common Stockholders
      $ 771     $ 255     $ 924     $ 441      
Weighted average number of common shares outstanding — basic
        235       239       236       241      
Income from continuing operations per weighted average common share — basic
      $ 3.28     $ 1.05     $ 3.19     $ 1.78      
Income from discontinued operations per weighted average common share — basic
              0.02       0.73       0.05      
 
 
Net Income per Weighted Average Common Share — Basic
      $ 3.28     $ 1.07     $ 3.92     $ 1.83      
 
 
Weighted average number of common shares outstanding — diluted
        277       285       278       287      
Income from continuing operations per weighted average common share — diluted
      $ 2.83     $ 0.92     $ 2.83     $ 1.61      
Income from discontinued operations per weighted average common share — diluted
              0.01       0.62       0.05      
 
 
Net Income per Weighted Average Common Share — Diluted
      $ 2.83     $ 0.93     $ 3.45     $ 1.66      
 
 
 
See notes to condensed consolidated financial statements.


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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    September 30, 2008     December 31, 2007  
       
 (In millions, except shares)   (unaudited)        
   
ASSETS
               
Current Assets
               
Cash and cash equivalents
  $      1,483     $      1,132  
Restricted cash
    32       29  
Accounts receivable, less allowance for doubtful accounts of $3 and $1, respectively
    531       482  
Inventory
    456       451  
Derivative instruments valuation
    4,190       1,034  
Deferred income taxes
          124  
Cash collateral paid in support of energy risk management activities
    544       85  
Prepayments and other current assets
    203       174  
Current assets — discontinued operations
          51  
 
 
Total current assets
    7,439       3,562  
 
 
Property, plant and equipment, net of accumulated depreciation of $2,184 and $1,695, respectively
    11,472       11,320  
 
 
Other Assets
               
Equity investments in affiliates
    428       425  
Notes receivable and capital lease, less current portion
    450       491  
Goodwill
    1,786       1,786  
Intangible assets, net of accumulated amortization of $425 and $372, respectively
    822       873  
Nuclear decommissioning trust fund
    333       384  
Derivative instruments valuation
    816       150  
Other non-current assets
    134       176  
Intangible assets held-for-sale
    3       14  
Non-current assets — discontinued operations
          93  
 
 
Total other assets
    4,772       4,392  
 
 
Total Assets
  $ 23,683     $ 19,274  
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current Liabilities
               
Current portion of long-term debt and capital leases
  $ 122     $ 466  
Accounts payable
    367       384  
Derivative instruments valuation
    4,022       917  
Deferred income taxes
    16        
Cash collateral received in support of energy risk management activities
    154       14  
Accrued expenses and other current liabilities
    629       459  
Current liabilities — discontinued operations
          37  
 
 
Total current liabilities
    5,310       2,277  
 
 
Other Liabilities
               
Long-term debt and capital leases
    8,059       7,895  
Nuclear decommissioning reserve
    320       307  
Nuclear decommissioning trust liability
    252       326  
Deferred income taxes
    1,083       843  
Derivative instruments valuation
    1,158       759  
Out-of-market contracts
    336       628  
Other non-current liabilities
    568       412  
Non-current liabilities — discontinued operations
          76  
 
 
Total non-current liabilities
    11,776       11,246  
 
 
Total Liabilities
    17,086       13,523  
 
 
Minority interest
    7        
3.625% convertible 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       3  
Additional paid-in capital
    4,135       4,092  
Retained earnings
    2,194       1,270  
Less treasury stock, at cost — 29,242,483 and 24,550,600 shares, respectively
    (823 )     (638 )
Accumulated other comprehensive loss
    (58 )     (115 )
 
 
Total Stockholders’ Equity
    6,343       5,504  
 
 
Total Liabilities and Stockholders’ Equity
  $ 23,683     $ 19,274  
 
 
 
See notes to condensed consolidated financial statements.


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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
                 
  (In millions)
           
 Nine Months Ended September 30,   2008     2007  
   
Cash Flows from Operating Activities
               
Net income
  $ 965     $ 482  
Adjustments to reconcile net income to net cash provided by operating activities Distributions and equity in (earnings) of unconsolidated affiliates
    (24 )     (23 )
Depreciation and amortization
    478       483  
Amortization of nuclear fuel
    31       42  
Amortization and write-off of financing costs and debt discount/premiums
    22       59  
Amortization of intangibles and out-of-market contracts
    (226 )     (112 )
Changes in deferred income taxes and liability for unrecognized tax benefits
    427       232  
Changes in nuclear decommissioning trust liability
    8       23  
Changes in derivatives
    (110 )     41  
Changes in collateral deposits supporting energy risk management activities
    (320 )     (107 )
Loss/(gain) on disposals and sales of assets
    13       (16 )
Gain on sale of discontinued operations
    (273 )      
Gain on sale of emission allowances
    (52 )     (31 )
Amortization of unearned equity compensation
    21       19  
Cash provided/(used) by changes in other working capital
    81       (116 )
 
 
Net Cash Provided by Operating Activities
    1,041       976  
 
 
Cash Flows from Investing Activities
               
Capital expenditures
    (649 )     (309 )
Increase in restricted cash, net
    (3 )     (18 )
Decrease in notes receivable
    20       26  
Purchases of emission allowances
    (6 )     (152 )
Proceeds from sale of emission allowances
    75       170  
Investments in nuclear decommissioning trust fund securities
    (441 )     (193 )
Proceeds from sales of nuclear decommissioning trust fund securities
    434       170  
Proceeds from sale of discontinued operations, net of cash divested
    241        
Proceeds from sale of assets
    14       57  
Decrease in trust fund balances
          19  
Equity investment in unconsolidated affiliate
    (17 )      
Other
          (2 )
 
 
Net Cash Used by Investing Activities
    (332 )     (232 )
 
 
Cash Flows from Financing Activities
               
Payment of dividends to preferred stockholders
    (41 )     (41 )
Payment of financing element of acquired derivatives
    (49 )      
Payment for treasury stock
    (185 )     (268 )
Proceeds from issuance of common stock, net of issuance costs
    8        
Proceeds from sale of minority interest in subsidiary
    50        
Proceeds from issuance of long-term debt
    20       1,411  
Payment of deferred debt issuance costs
    (2 )     (5 )
Payments for short and long-term debt
    (202 )     (1,472 )
 
 
Net Cash Used by Financing Activities
    (401 )     (375 )
 
 
Change in cash from discontinued operations
    43       (16 )
Effect of exchange rate changes on cash and cash equivalents
          7  
 
 
Net Increase in Cash and Cash Equivalents
    351       360  
Cash and Cash Equivalents at Beginning of Period
    1,132       777  
 
 
Cash and Cash Equivalents at End of Period
  $      1,483     $      1,137  
 
 
 
See notes to condensed consolidated financial statements.


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NRG ENERGY, INC.
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 
Note 1 —  Basis of Presentation
 
NRG Energy, Inc., or NRG, or the Company, is a wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the United States and select international markets.
 
The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC’s regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The accounting policies NRG follows are set forth in Note 2, Summary of Significant Accounting Policies, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2007. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K. Interim results are not necessarily indicative of results for a full year.
 
In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company’s consolidated financial position as of September 30, 2008, the results of operations for the three and nine months ended September 30, 2008 and 2007, and cash flows for the nine months ended September 30, 2008 and 2007. Certain prior-year amounts have been reclassified for comparative purposes.
 
Use of Estimates
 
The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions impact the reported amount of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the consolidated financial statements. They also impact the reported amount of net earnings during the reporting period. Actual results could be different from these estimates.
 
Cash and Cash Equivalents
 
Cash and cash equivalents at September 30, 2008 are predominantly held in money market funds invested in treasury securities or treasury repurchase agreements.
 
Investment Accounted for by the Equity Method
 
In February 2008, a wholly-owned subsidiary of NRG entered into a 50/50 joint venture with a subsidiary of BP Alternative Energy North America Inc., or BP, to build and own the Sherbino I Wind Farm LLC, or Sherbino. This is a 150 MW wind project consisting of 50 Vestas 3 MW wind turbine generators, located in the West Zone of Texas’ ERCOT power market, or Texas West. The project will be funded through a combination of equity contributions from the owners and non-recourse project-level debt. NRG delivered a $59 million promissory note to Sherbino to support its initial capital contribution, payable no later than December 1, 2008, made an additional $17 million cash contribution in April 2008, and expects to contribute another $11 million by year end, bringing its total expected equity contribution to approximately $87 million. NRG has posted a letter of credit in this amount. NRG’s maximum exposure to loss is limited to its expected equity investments. Sherbino commenced commercial operations in October 2008.
 
Sherbino has entered into a long-term natural gas swap to mitigate a portion of power price risk for its expected power generation. As the changes in natural gas prices and in Texas West power prices do not meet the required correlation for cash flow hedge accounting, Sherbino will account for the natural gas swap hedge under mark-to-market accounting.
 
NRG accounts for its investment in Sherbino under the equity method of accounting. NRG’s share of mark-to-market results of the natural gas swap, a loss of $9 million for the nine months ended September 30, 2008, is included in NRG’s equity in earnings of Sherbino. NRG’s investment at September 30, 2008, net of its promissory note commitment, is $7 million, which is included in “Equity Investments in Affiliates” on the condensed consolidated balance sheet.


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Other Cash Flow Information
 
NRG’s non-cash investing activities for the nine months ended September 30, 2008 included capital expenditures of $60 million for which the associated liability is reflected within accrued expenses.
 
Recent Accounting Developments
 
The Company partially adopted SFAS No. 157, Fair Value Measurements, or SFAS 157, on January 1, 2008, delaying application for non-financial assets and non-financial liabilities as permitted. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. In February 2008, the Financial Accounting Standards Board, or FASB, issued FASB Staff Position, or FSP, No. FAS 157-1, Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13, which amends SFAS 157 to exclude SFAS Statement No. 13, Accounting for Leases, or SFAS 13, and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13. In February 2008, the FASB also issued FSP No. FAS 157-2, Effective Date of FASB Statement No. 157, which permitted delayed application of this statement for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The partial adoption of SFAS 157 did not have a material impact on the Company’s consolidated financial position, statement of operations, and cash flows. The Company is currently evaluating the impact of the deferred portion of SFAS 157 on the Company’s consolidated financial position, statement of operations, and cash flows.
 
The Company adopted SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115, or SFAS 159, on January 1, 2008. This statement provides entities with an option to measure and report selected financial assets and liabilities at fair value. The Company does not intend to apply this standard to any of its eligible assets or liabilities; therefore, there was no impact on NRG’s consolidated financial position, results of operations, or cash flows.
 
The Company adopted FSP FIN 39-1, Amendment of FASB Interpretation No. 39, or FSP FIN 39-1, which amends FIN 39, Offsetting of Amounts Related to Certain Contracts, on January 1, 2008. FSP FIN 39-1 impacts entities that enter into master netting arrangements as part of their derivative transactions. Under the guidance in this FSP, entities may choose to offset derivative positions in the financial statements against the fair value of amounts recognized as cash collateral paid or received under those arrangements. The Company chose not to offset positions as defined in this FSP; therefore there was no impact on NRG’s consolidated financial position, results of operations, or cash flows.
 
NRG has non-qualified stock options for which it has insufficient historical exercise data and therefore estimates the expected term using the simplified method, as allowed under Staff Accounting Bulletin, or SAB, No. 107, Share Based Payment, or SAB 107. In December 2007, the SEC issued SAB No. 110, Certain Assumptions Used in Valuation Methods, which eliminates the December 31, 2007 expiration of SAB 107’s permission to use this simplified method. NRG will therefore continue to use this simplified method, for as long as the Company deems it to be the most appropriate method.
 
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations, or SFAS 141R. This statement applies prospectively to all business combinations for which the acquisition date is on or after the beginning of an entity’s first annual reporting period beginning on or after December 15, 2008. The statement requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. As discussed further in Note 12, Income Taxes, SFAS 141R will change the application of fresh start accounting to certain of the Company’s unrecognized tax benefits. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows.
 
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, Consolidated Financial Statements, or SFAS 160. This Statement amends ARB No. 51 to establish accounting and reporting standards for the minority interest in a subsidiary and for the deconsolidation of a subsidiary. It also amends certain of ARB No. 51’s consolidation procedures for consistency with the requirements of SFAS 141R. This Statement shall be effective and applied prospectively for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008, except for the presentation and disclosure requirements, which shall be applied retrospectively. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows.


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In March 2008, the FASB issued SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities, or SFAS 161. SFAS 161 requires entities to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended or SFAS 133, and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The enhanced disclosures regarding derivative and hedging instruments required by SFAS 161 are relevant to NRG, but will not have an impact on the Company’s results of operations, financial position, or cash flows.
 
In April 2008, the FASB issued FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets, or FSP FAS 142-3. FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years, with early adoption prohibited. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows.
 
In May 2008, the FASB issued FSP No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), or FSP APB 14-1. FSP APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) do not fall within the scope of paragraph 12 of Accounting Principles Board Opinion No. 14, Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants, and specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB 14-1 does not apply to embedded conversion options that must be separately accounted for as derivatives under SFAS 133. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years and is to be applied retrospectively. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows.
 
In June 2008, the Emerging Issues Task Force, or EITF, issued EITF No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock, or EITF 07-5. EITF 07-5 clarifies that contingent and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables. EITF 07-5 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. NRG is currently evaluating the impact of this statement upon its adoption on the Company’s results of operations, financial position and cash flows.
 
In September 2008, the FASB issued FSP FAS 133-1 and FIN 45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161, or FSP FAS 133-1 and FIN 45-4. This FSP amends FAS 133, and FIN 45 Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others to require additional disclosures about credit derivatives, credit derivatives embedded in a hybrid instrument, and the current status of the payment/performance risk of a guarantee. FSP FAS 133-1 and FIN 45-4 is effective for the financial statements of reporting periods (annual or interim) ending after November 15, 2008. NRG currently has no credit derivative contracts so there will be no impact on NRG related to credit derivatives. The clarification to SFAS 161 is not applicable to NRG as it only affects non-calendar year filers. The enhanced disclosures regarding the current status of the payment/performance risk of guarantees are relevant to NRG, but will not have an impact on the Company’s results of operations, financial position, or cash flows.
 
In September 2008, the EITF issued EITF 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement, or EITF 08-5. EITF 08-5 requires issuers of liability instruments with third-party credit enhancements to exclude the effect of the credit enhancement when measuring the liability’s fair value. The effect of initially applying the requirements is included in the change in the instrument’s fair value in the period of adoption. Entities are required to disclose the valuation technique used to measure the liabilities and to discuss any changes in the valuation techniques used to measure those liabilities in earlier periods. Entities will also need to disclose the existence of a third-party credit enhancement on the entity’s issued debt. EITF 08-5 is effective on a prospective basis in the first reporting period beginning on or after December 15, 2008, with earlier application permitted. The fair value measurement requirements and enhanced disclosures regarding existence of third-party credit enhancements on the entity’s issued debt and valuation techniques will not have an impact on the Company’s results of operations, financial position, or cash flows.


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On October 10, 2008, the FASB issued FSP No. FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active, or FSP 157-3. This FSP clarifies the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP 157-3 is effective upon issuance, including prior periods for which financial statements have not been issued. Revisions resulting from a change in the valuation technique or its application shall be accounted for as a change in accounting estimate SFAS No. 154, Accounting Changes and Error Corrections, or SFAS 154. The disclosure provisions of SFAS 154 for a change in accounting estimate are not required for revisions resulting from a change in valuation technique or its application. Although effective for the period ended September 30, 2008, FSP 157-3 did not have an impact on the Company’s results of operations, financial position, or cash flows.
 
Note 2 —  Comprehensive Income/(Loss)
 
The following table summarizes the components of the Company’s comprehensive income, net of tax.
 
                                     
    Three Months Ended September 30,     Nine Months Ended September 30,      
     
 (In millions)   2008     2007     2008     2007      
 
Net income
  $ 784     $ 268     $ 965     $ 482      
 
 
Changes in derivative activity
    1,112       46       112       (278 )    
Foreign currency translation adjustment
    (104 )     39       (54 )     65      
Unrealized gain/(loss) on available-for-sale securities
    (4 )           (1 )     1      
 
 
Other comprehensive income/(loss), net of tax
  $ 1,004     $ 85     $ 57     $ (212 )    
 
 
Comprehensive income
  $ 1,788     $ 353     $ 1,022     $ 270      
 
 
 
The following table summarizes the changes in the Company’s accumulated other comprehensive loss, net of tax.
 
         
 (In millions)
     
 As of September 30,   2008  
   
Accumulated other comprehensive loss as of December 31, 2007
  $   (115 )
Changes in derivative activity
    112  
Foreign currency translation adjustments
    (54 )
Unrealized loss on available-for-sale securities
    (1 )
 
 
Accumulated other comprehensive loss as of September 30, 2008
  $ (58 )
 
 


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Note 3 —  Discontinued Operations
 
NRG has classified material business operations and gains/losses recognized on sale as discontinued operations for projects that were sold or have met the required criteria for such classification. The financial results for the affected businesses have been accounted for as discontinued operations.
 
The assets and liabilities reported in the balance sheet as of December 31, 2007 as discontinued operations represent those of Itiquira Energetica S.A., or ITISA. On April 28, 2008, NRG completed the sale of its 100% interest in Tosli Acquisition B.V., or Tosli, which held all NRG’s interest in ITISA, to Brookfield Renewable Power Inc. (previously Brookfield Power Inc.), a wholly-owned subsidiary of Brookfield Asset Management Inc. In addition, the purchase price adjustment contingency under the sale agreement was resolved on August 7, 2008. In connection with the sale, NRG received $300 million of cash proceeds from Brookfield, and removed $163 million of assets, including $59 million of cash, $122 million of liabilities, including $63 million of debt, and $15 million in foreign currency translation adjustment from its 2008 condensed consolidated balance sheet.
 
Summarized operating results for the Company’s discontinued operations, consisting of ITISA’s activities, were as follows:
 
                                     
    Three months ended September 30,     Nine months ended September 30,      
     
 (In millions)   2008     2007     2008     2007      
 
Operating revenues
  $   —     $  13     $   20     $   36      
Operating costs and other expenses
          7       9       18      
 
 
Pre-tax income from operations of discontinued components
          6       11       18      
Income tax expense
          3       3       5      
 
 
Income from operations of discontinued components
          3       8       13      
 
 
Disposal of discontinued components — pre-tax gain
    3             273            
Income tax expense
    3             109            
 
 
Gain on disposal of discontinued components, net of income tax
                164            
 
 
Income from discontinued operations, net of income tax expense
   $      $ 3      $ 172      $ 13      
 
 
 
Note 4 —  Fair Value of Financial Instruments
 
Fair Value of Long-Term Debt
 
The Company’s long-term debt is recorded at carrying value on the Company’s consolidated balance sheet. The carrying amounts and fair value of the Company’s long-term debt as of September 30, 2008 and December 31, 2007 were as follows:
 
                                     
    September 30, 2008     December 31, 2007  
       
        Carrying
    Fair
    Carrying
    Fair
 
 (In millions)
      Amount     Value     Amount     Value  
   
Long-term debt, including current portion
      $  8,028     $  7,218     $  8,180     $  8,164  
 
 
 
The fair value of long-term debt is based on quoted market prices for these instruments that are publicly traded, or estimated based on the income approach valuation technique for non-publicly traded debt using current interest rates for similar instruments with equivalent credit quality.


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Adoption of SFAS No. 157
 
The Company partially adopted SFAS 157 on January 1, 2008, delaying application for non-financial assets and non-financial liabilities as permitted. This statement establishes a framework for measuring fair value, and expands disclosures about fair value measurements.
 
SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
 
  •  Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG’s financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments.
 
  •  Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG’s financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over-the-counter derivatives such as swaps, options and forwards.
 
  •  Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG’s financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models.
 
In accordance with SFAS 157, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.
 
Recurring Fair Value Measurements
 
The following table presents assets and liabilities measured and recorded at fair value on the Company’s consolidated balance sheet on a recurring basis and their level within the fair value hierarchy as of September 30, 2008:
 
                                         
 (In millions)
  Fair Value
 As of September 30, 2008       Level 1     Level 2     Level 3     Total      
 
Investment in available-for-sale securities (classified within other non-current assets):
                                       
Debt securities
      $     $     $ 10     $ 10      
Marketable equity securities
        5                   5      
Trust fund investments
        180       135       20       335      
Derivative assets
        2,152       2,832       22       5,006      
 
 
Total assets
      $  2,337     $  2,967     $  52     $  5,356      
 
 
Derivative liabilities
      $ 2,153     $ 3,023     $ 4     $ 5,180      
 
 
 
The following table reconciles, for the period ended September 30, 2008, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:
 
                                         
    Fair Value Measurement Using Significant Unobservable Inputs
    (Level 3)
 (In millions)
            Trust Fund
                 
 Nine Months Ended September 30, 2008       Debt Securities     Investments     Derivatives     Total      
 
Beginning balance as of January 1, 2008
      $ 32     $ 37     $   27     $   96      
Total gains and losses (realized/unrealized)
                                       
Included in earnings
        (22 )           (19 )     (41 )    
Included in nuclear decommissioning obligations
              (9 )           (9 )    
Included in other comprehensive income
                    28       28      
Purchases/(sales), net
              (9 )      (17 )      (26 )    
Transfer into Level 3
              1       (1 )          
 
 
Ending balance as of September 30, 2008
      $ 10     $ 20     $ 18     $ 48      
 
 
The amount of the total gains or losses for the period included in earnings attributable to the change in unrealized gains and losses relating to assets still held as of September 30, 2008
      $ 22     $     $ 19     $ 41      
 
 


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Realized and unrealized gains and losses included in earnings that are related to the debt securities are recorded in other income, while those related to energy derivatives are recorded in operating revenues.
 
Non-derivative fair value measurements
 
NRG’s debt securities are classified as Level 3 and consist of non-traded debt instruments that are valued based on an auction process.
 
The trust fund investments are held primarily to satisfy NRG’s nuclear decommissioning obligations. These trust fund investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. In addition, US Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding US Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. Commingled funds, which are analogous to mutual funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair value of commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See Note 5 Nuclear Decommissioning Trust Fund.
 
Derivative fair value measurements
 
A small portion of NRG’s contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG’s contracts are non exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. For the majority of our markets we receive quotes from multiple sources. To the extent that we receive multiple quotes our prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If we only receive one quote then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 11% of the total fair value of all derivative contracts. The fair value of each contract is discounted using a risk free interest rate. In addition, we apply a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that our net exposure under a specific master agreement is an asset we are using the counterparty’s risk of default. If the exposure under a specific master agreement is a liability we are using NRG’s probability of default. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG’s liabilities or that a market participant would be willing to pay for NRG’s assets. As of September 30, 2008 the credit reserve resulted in a $6 million decrease in fair value which is composed of a $5 million gain in OCI and an $11 million loss in derivative revenue. The fair values in each category reflect the level of forward prices and volatility factors as of September 30, 2008 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.
 
Under the guidance of FSP FIN 39-1, entities may choose to offset derivative positions in the financial statements against the fair value of the amounts recognized as cash collateral paid or received under those arrangements. The Company has credit arrangements within various agreements to call on or pay additional collateral support. The Company has chosen not to offset positions as defined in this FSP. As of September 30, 2008, the Company recorded $544 million of cash collateral paid and $154 million of cash collateral received on its balance sheet.


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Note 5 —  Nuclear Decommissioning Trust Fund
 
NRG’s nuclear decommissioning trust fund assets which are for the decommissioning of South Texas Project, or STP, are primarily comprised of securities recorded at fair value based on actively quoted market prices. NRG accounts for these trust fund assets per SFAS 71, Accounting for the Effects of Certain Types of Regulation, because the Company’s nuclear decommissioning activities are regulated by the Public Utility Commission of Texas, or PUCT. Although the owners of STP are responsible for the management of decommissioning STP, the cost of decommissioning is the responsibility of the Texas ratepayers. As such, NRG does not bear the cost for these decommissioning responsibilities, except to the extent that NRG has a prudence obligation with respect to the management of the trust funds and the future decommissioning of STP. Third party appraisals are periodically conducted to estimate the future decommissioning liability related to STP. These appraisals are then used to determine the adequacy of the existing decommissioning trust investments to cover that estimated future liability. Should there be a shortfall in the value of the assets in the trust relative to the estimated liability, NRG has the ability to file a rate case with the PUCT to increase decommissioning reimbursements over time from retail customers.
 
The following table summarizes the fair values of the securities held in the trust funds as of September 30, 2008 and December 31, 2007:
 
                     
 (In millions)   September 30, 2008     December 31, 2007      
 
Cash and cash equivalents
    $          1       $          4      
US government and federal agency obligations
    26       21      
Federal agency mortgage-backed securities
    65       59      
Commercial mortgage-backed securities
    23       22      
Corporate debt securities
    39       44      
Marketable equity securities
    179       234      
 
 
Total
    $      333       $      384      
 
 
 
Note 6 —  Accounting for Derivative Instruments and Hedging Activities
 
SFAS 133, requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a Normal Purchase Normal Sale, or NPNS, exception. If certain conditions are met, NRG may be able to designate certain derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives to Other Comprehensive Income, or OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.
 
Accumulated Other Comprehensive Income
 
The following tables summarize the effects of SFAS 133 on NRG’s OCI balance attributable to hedged derivatives, net of tax:
 
                         
 (In millions)
  Energy
    Interest
       
 Three months ended September 30, 2008   Commodities     Rate     Total  
   
Accumulated OCI balance at June 30, 2008
  $  (1,235 )   $  (30 )   $  (1,265 )
Realized from OCI during the period:
                       
— Due to realization of previously deferred amounts
    26             26  
Mark-to-market of hedge contracts
    1,088       (2 )     1,086  
 
 
Accumulated OCI balance at September 30, 2008
  $ (121 )   $ (32 )   $ (153 )
 
 
Gains expected to be realized from OCI during the next 12 months, net of $53 tax
  $ 81     $     $ 81  
 
 


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 (In millions)
  Energy
    Interest
           
 Three months ended September 30, 2007   Commodities     Rate     Total      
 
Accumulated OCI balance at June 30, 2007
  $  (145 )   $  30     $  (115 )    
Realized from OCI during the period:
                           
— Due to realization of previously deferred amounts
    (10 )     (1 )     (11 )    
Mark-to-market of hedge contracts
    86       (29 )     57      
 
 
Accumulated OCI balance at September 30, 2007
  $ (69 )   $     $ (69 )    
 
 
 
                             
 (In millions)
  Energy
    Interest
           
 Nine months ended September 30, 2008   Commodities     Rate     Total      
 
Accumulated OCI balance at December 31, 2007
  $  (234 )   $  (31 )   $  (265 )    
Realized from OCI during the period:
                           
— Due to realization of previously deferred amounts
    32             32      
Mark-to-market of hedge contracts
    81       (1 )     80      
 
 
Accumulated OCI balance at September 30, 2008
  $ (121 )   $ (32 )   $ (153 )    
 
 
 
                             
 (In millions)
  Energy
    Interest
           
 Nine months ended September 30, 2007   Commodities     Rate     Total      
 
Accumulated OCI balance at December 31, 2006
  $  193     $   16     $  209      
Realized from OCI during the period:
                           
— Due to realization of previously deferred amounts
    (37 )     (1 )     (38 )    
Mark-to-market of hedge contracts
    (225 )     (15 )     (240 )    
 
 
Accumulated OCI balance at September 30, 2007
  $ (69 )   $     $ (69 )    
 
 
 
As of September 30, 2008 and 2007, the net balances in OCI relating to SFAS 133 were unrecognized losses of approximately $153 million and $69 million, which were net of income taxes of $102 million and $46 million, respectively.
 
As of July 31, 2008, our regression analysis for natural gas prices to ERCOT power prices did not meet the required threshold for cash flow hedge accounting for calendar years 2012 and 2013. As a result, we de-designated our 2012 and 2013 ERCOT cash flow hedges as of July 31, 2008. We will continue to monitor the correlations in this market, and if the regression analysis meets the required thresholds in the future, we may elect to re-designate these transactions as cash flow hedges.
 
Statement of Operations
 
In accordance with SFAS 133, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives and ineffectiveness of hedge derivatives are reflected in current period earnings.
 
The following table summarizes the pre-tax effects of economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activity on NRG’s statement of operations. These amounts are included within operating revenues.
 
                                     
    Three months ended September 30,     Nine months ended September 30,      
     
 (In millions)   2008     2007     2008     2007      
 
Unrealized mark-to-market results
                                   
Reversal of previously recognized unrealized gains on settled positions related to economic hedges
  $ (7 )   $   (17 )   $ (32 )   $ (109 )    
Reversal of previously recognized unrealized gains on settled positions related to trading activity
    (9 )     (3 )     (20 )     (23 )    
Net unrealized gains on open positions related to economic hedges
    439       1       180       22      
(Loss)/gain on ineffectiveness associated with open positions treated as cash flow hedges
    352       9       (27 )     32      
Net unrealized gains on open positions related to trading activity
    26       16       57       37      
 
 
Total unrealized mark-to-market results
  $   801     $ 6     $   158     $   (41 )    
 
 
 
Discontinued Hedge Accounting — During the third quarter of 2008, a relatively mild summer season in the Northeast resulted in falling power prices and expected lower power generation for the remainder of 2008 and calendar year 2009. As such, NRG discontinued cash flow hedge accounting for certain contracts related to commodity price risk previously accounted for as cash flow hedges for 2008 and 2009. These contracts were originally entered into as hedges of forecasted sales by baseload plants. As a result, $31 million of gain previously deferred in OCI was recognized in earnings for the three and nine months ended September 30, 2008.


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Note 7 — Long-Term Debt  
 
Debt Related to NRG Common Stock Finance I, LLC
 
In March 2008, the Company executed an arrangement with Credit Suisse, or CS, to extend the notes and preferred interest maturities of NRG Common Stock Finance I, LLC, or CSF I, from October 2008 to June 2010. In addition, the settlement date of an embedded derivative, or CSFI CAGR, which is based on NRG’s share price appreciation beyond a 20% compound annual growth rate since the original date of purchase by CSF I, was extended 30 days to early December 2008. As part of this extension arrangement, the Company contributed 795,503 treasury shares to CSF I as additional collateral to maintain a blended interest rate in the CSF I facility of approximately 7.5%. Accordingly, the amount due at maturity in June 2010 for the CSF I notes and preferred interests will be $248 million.
 
In August 2008, the Company amended the CSF I notes and preferred interests to early settle the CSFI CAGR. Accordingly, NRG made a cash payment of $45 million to CS for the benefit of CSFI, which was recorded to interest expense in the Company’s Consolidated Statement of Operations.
 
Senior Credit Facility
 
Beginning in 2008, NRG must annually offer a portion of its excess cash flow (as defined in the Senior Credit Facility) for the prior year to its first lien lenders under the Company’s Term B loan. The percentage of the excess cash flow offered to these lenders is dependent upon the Company’s consolidated leverage ratio (as defined in the Senior Credit Facility) at the end of the preceding year. Of the amount offered, the first lien lenders must accept 50%, while the remaining 50% may either be accepted or rejected at the lenders’ option. The mandatory annual offer required for 2008 was $446 million, against which the Company made a prepayment of $300 million in December 2007. Of the remaining $146 million, the lenders accepted a repayment of $143 million in March 2008. The amount retained by the Company can be used for investments, capital expenditures and other items as permitted by the Senior Credit Facility.
 
Note 8 —  Changes in Capital Structure
 
The following table reflects the changes in NRG’s common stock issued and outstanding during the nine months ended September 30, 2008:
 
                                     
    Authorized     Issued     Treasury     Outstanding      
 
Balance as of December 31, 2007
    500,000,000       261,285,529       (24,550,600 )     236,734,929      
2008 Capital Allocation Program
                (4,691,883 )     (4,691,883 )    
Shares issued from LTIP
          984,176             984,176      
 
 
Balance as of September 30, 2008
    500,000,000       262,269,705       (29,242,483 )     233,027,222      
 
 
 
Treasury Stock
 
In December 2007, the Company initiated its 2008 Capital Allocation Program, with the repurchase of 2,037,700 shares of NRG common stock during that month for approximately $85 million. In February 2008, the Company’s Board of Directors authorized an additional $200 million in common share repurchases that would raise the total 2008 Capital Allocation Program to approximately $300 million. In the first quarter 2008, the Company repurchased 1,281,600 shares of NRG common stock for approximately $55 million. In the third quarter 2008, the Company repurchased an additional 3,410,283 of NRG common stock in the open market for approximately $130 million. As of September 30, 2008, NRG had repurchased a total of 6,729,583 shares of NRG common stock at a cost of approximately $270 million as part of its 2008 Capital Allocation Program.


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Note 9 —  Equity Compensation
 
Non-Qualified Stock Options, or NQSO’s
 
The following table summarizes the Company’s NQSO activity as of September 30, 2008 and the changes during the nine months then ended:
 
                             
                Aggregate
     
          Weighted
    Intrinsic
     
          Average
    Value
     
    Shares     Exercise Price     (In millions)      
 
Outstanding as of December 31, 2007
    3,579,775     $ 19.98              
Granted
    1,174,200       40.48              
Forfeited
    (148,536 )     32.79              
Exercised
    (507,986 )     16.29              
             
             
Outstanding at September 30, 2008
    4,097,453       25.84     $  —      
Exercisable at September 30, 2008
    2,056,803     $ 17.54       15      
 
 
 
The weighted average grant date fair value of NQSO’s granted for the nine months ending September 30, 2008 was $10.61.
 
Restricted Stock Units, or RSU’s
 
The following table summarizes the Company’s non-vested RSU awards as of September 30, 2008 and changes during the nine months then ended:
 
                     
          Weighted
     
          Average
     
          Grant-Date
     
          Fair Value
     
    Units     Per Unit      
 
Non-vested as of December 31, 2007
    1,588,316     $   26.99      
Granted
    163,200       40.22      
Vested
    (610,760 )     19.38      
Forfeited
    (71,320 )     31.13      
 
 
Non-vested as of September 30, 2008
    1,069,436     $ 33.08      
 
 
 
Performance Units, or PU’s
 
The following table summarizes the Company’s non-vested PU awards as of September 30, 2008 and changes during the nine months then ended:
 
                     
          Weighted
     
          Average
     
          Grant- Date
     
          Fair Value
     
    Units     Per Unit      
 
Non-vested as of December 31, 2007
    536,764     $   20.18      
Granted
    227,300       27.75      
Vested
    (50,000 )     15.74      
Forfeited
    (59,700 )     21.49      
 
 
Non-vested as of September 30, 2008
    654,364     $ 23.05      
 
 
 
In the third quarter 2008, 100,000 shares of common stock were issued for performance units that vested in accordance with the plan payout provisions.
 
Employee Stock Purchase Plan
 
In May 2008, NRG shareholders approved the adoption of the NRG Energy, Inc. Employee Stock Purchase Plan, or ESPP, pursuant to which eligible employees may elect to withhold up to 10% of their eligible compensation to purchase shares of NRG common stock at 85% of its fair market value on the exercise date. An exercise date occurs each June 30 and December 31. The initial six month employee withholding period began July 1, 2008 and ends December 31, 2008. There are 500,000 shares of treasury stock reserved for issuance under the ESPP.


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Note 10 —  Earnings Per Share
 
Basic earnings per common share is computed by dividing net income adjusted for accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.
 
The reconciliation of basic earnings per common share to diluted earnings per share is as follows:
 
                                     
     
    Three months ended
September 30,
    Nine months ended
September 30,
     
 (In millions, except per share data)   2008     2007     2008     2007      
 
Basic earnings per share
                                   
Numerator:
                                   
Income from continuing operations
  $  784     $ 265     $ 793     $ 469      
Preferred stock dividends
    (13 )     (13 )     (41 )     (41 )    
 
 
Net income available to common stockholders from continuing operations
    771       252       752       428      
Discontinued operations, net of income tax expense
          3       172       13      
 
 
Net income available to common stockholders
  $ 771     $ 255     $ 924     $ 441      
 
 
Denominator:
                                   
Weighted average number of common shares outstanding
     234.8        239.4        235.7        240.5      
Basic earnings per share:
                                   
Income from continuing operations
  $ 3.28     $ 1.05     $ 3.19     $ 1.78      
Discontinued operations, net of income tax expense
          0.02       0.73       0.05      
 
 
Net income
  $ 3.28     $ 1.07     $ 3.92     $ 1.83      
 
 
Diluted earnings per share
                                   
Numerator:
                                   
Net income available to common stockholders from continuing operations
  $ 771     $ 252     $ 752     $ 428      
Add preferred stock dividends for dilutive preferred stock
    11       11       34       34      
 
 
Adjusted income from continuing operations available to common shareholders
    782       263       786       462      
Discontinued operations, net of tax
          3       172       13      
 
 
Net income available to common stockholders
  $ 782     $ 266     $ 958     $ 475      
 
 
Denominator:
                                   
Weighted average number of common shares outstanding
    234.8       239.4       235.7       240.5      
Incremental shares attributable to the issuance of equity compensation (treasury stock method)
    2.2       3.8       3.0       3.7      
Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method)
    2.0       4.6       1.8       4.9      
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)
    37.5       37.5       37.5       37.5      
 
 
Total dilutive shares
    276.5       285.3       278.0       286.6      
Diluted earnings per share:
                                   
Income from continuing operations available to common shareholders
  $ 2.83     $ 0.92     $ 2.83     $ 1.61      
Income from discontinued operations, net of tax
          0.01       0.62       0.05      
 
 
Net income
  $ 2.83     $ 0.93     $ 3.45     $ 1.66      
 
 


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Effects on Earnings per Share
 
The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted earnings per share:
 
                                     
    Three Months Ended September 30,     Nine Months Ended September 30,      
 (In millions of shares)   2008     2007     2008     2007      
 
Equity compensation
    1.8             1.4       0.4      
Embedded derivative of 3.625% convertible perpetual preferred stock
    14.0       13.2       14.2       13.0      
Embedded derivative of preferred interests and notes issued by CSF I and CSF II
    8.3       16.7       8.3       16.6      
 
 
Total
    24.1       29.9       23.9       30.0      
 
 
 
Note 11 —  Segment Reporting
 
The Company’s segment structure reflects NRG’s core areas of operation which are primarily the geographic regions of the Company’s wholesale power generation, thermal and chilled water business, and corporate activities. Within NRG’s wholesale power generation operations, there are distinct components with separate operating results and management structures for the following regions: Texas, Northeast, South Central, West and International.
 
                                                                             
 
  Wholesale Power Generation                              
 (In millions)
              South
                                         
 Three Months Ended  September 30, 2008   Texas     Northeast     Central     West     International     Thermal     Corporate     Elimination     Total      
 
Operating revenues
  $ 1,661     $ 677     $ 233     $  40       $        41     $  36     $ 3     $ (1 )   $ 2,690      
Depreciation and amortization
    108       26       16       2             3       1             156      
Equity in earnings of unconsolidated affiliates
    40                   1       17                         58      
Income/(loss) from continuing operations before income taxes
    1,050       351       24       13       25       4       (152 )     (1 )     1,314      
Income from discontinued operations, net of income taxes
                                                         
 
 
Net income/(loss)
  $ 594     $ 351     $ 24     $ 13       $        19     $ 4     $ (220 )   $ (1 )   $ 784      
 
 
Total assets
  $  12,102     $  1,634     $  942     $ 53       $   1,002     $  212     $  19,006     $  (11,268 )   $  23,683      
 
 
 
                                                                             
 
  Wholesale Power Generation                              
 (In millions)
              South
                                         
 Three Months Ended  September 30, 2007   Texas     Northeast     Central     West     International     Thermal     Corporate     Elimination     Total      
 
Operating revenues
  $  956     $  502     $  200     $  33       $       38     $  36     $  7     $  —     $  1,772      
Depreciation and amortization
    113       25       17       1             3       1             160      
Equity in earnings of unconsolidated affiliates
                      1       18                         19      
Income/(loss) from continuing operations before income taxes
    275       171       18       13       25       4       (96 )           410      
Income from discontinued operations, net of income taxes
                            3                         3      
 
 
Net income/(loss)
  $ 161     $ 171     $ 17     $ 13       $      54     $ 4     $  (152 )   $     $ 268      
 
 


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    Wholesale Power Generation                              
 (In millions)               South
                                         
 Nine Months Ended September 30, 2008   Texas     Northeast     Central     West     International     Thermal     Corporate     Elimination     Total      
 
Operating revenues
  $  3,061     $  1,302     $  584     $  127     $  122     $  114     $  1     $  (3 )   $  5,308      
Depreciation and amortization
    334       77       50       6             8       3             478      
Equity in (losses)/earnings of unconsolidated affiliates
    (10 )                 (2 )     47                         35      
Income/(loss) from continuing operations before income taxes
    1,131       365       57       38       72       11       (339 )     (11 )     1,324      
Income from discontinued operations, net of income taxes
                            172                         172      
 
 
Net income/(loss)
  $ 644     $ 365     $ 57     $ 38     $ 229     $ 11     $ (368 )   $ (11 )   $ 965      
 
 
 
                                                                             
    Wholesale Power Generation                              
 (In millions)               South
                                         
 Nine Months Ended September 30, 2007   Texas     Northeast     Central     West     International     Thermal     Corporate     Elimination     Total      
 
Operating revenues
  $  2,526     $  1,239     $  514     $  90     $  102     $  122     $  29     $  (15 )   $  4,607      
Depreciation and amortization
    341       74       51       2             9       4             481      
Equity in (losses)/earnings of unconsolidated affiliates
                      (2 )     42                         40      
Income/(loss) from continuing operations before income taxes
    624       319       24       26       60       32       (304 )     (12 )     769      
Income from discontinued operations, net of income taxes
                            13                         13      
 
 
Net income/(loss)
  $ 355     $ 319     $ 23     $ 26     $ 88     $ 32     $ (349 )   $ (12 )   $ 482      
 
 
 
Note 12 —   Income Taxes
 
Income tax expense from continuing operations for the three months and nine months ended September 30, 2008 was $530 million and $531 million, respectively, compared to $145 million and $300 million for the three and nine months ended September 30, 2007, respectively. The income tax expense for the three months and nine months ended September 30, 2008 included domestic tax expense of $523 million and $515 million, respectively, and foreign tax expense of $7 million and $16 million, respectively. The income tax expense for the three and nine months ended September 30, 2007 included domestic tax expense of $171 million and $314 million, respectively, and a foreign tax benefit of $26 million and $14 million, respectively.
 
A reconciliation of the US statutory rate to NRG’s effective tax rate from continuing operations is as follows:
 
                     
 (In millions except percentages)
               
 Nine Months Ended September 30,   2008     2007      
 
Income from continuing operations before income taxes
  $  1,324     $  769      
 
 
Tax at 35%
    463       269      
State taxes
    62       37      
Valuation allowance
    (1 )     1      
Foreign operations
    (10 )     (5 )    
Foreign dividend
    5       21      
Non-deductible interest
    24       7      
Change in German tax rate
          (30 )    
Section 199 Manufacturing Deduction
    (17 )     (3 )    
Other permanent differences including subpart F income
    5       3      
 
 
Income tax expense
  $ 531     $ 300      
 
 
Effective income tax rate
    40.1 %     39.0 %    
 
 
 
The effective income tax rate for the nine months ended September 30, 2008 and 2007 differs from the US statutory rate of 35% due to a taxable dividend from foreign operations and non-deductible interest, offset by earnings in foreign jurisdictions that are taxed at rates lower than the US statutory rate.


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Tax Payable
 
As of September 30, 2008, NRG recorded a current tax payable of $191 million for domestic federal and state taxes.
 
Deferred tax assets and valuation allowance
 
Net deferred tax balance — As of September 30, 2008, NRG recorded a net deferred tax liability of $560 million. However, due to an assessment of positive and negative evidence, including projected capital gains and available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $539 million of tax assets, thus a valuation allowance has remained, resulting in a net deferred tax liability of $1,099 million.
 
NOL carryforwards — As of September 30, 2008, the Company had cumulative foreign NOL carryforwards of $253 million, of which $54 million will expire starting in 2011 through 2017 and $199 million do not have an expiration date.
 
Uncertain tax benefits
 
NRG has identified certain unrecognized tax benefits whose after-tax value was $709 million, of which $36 million would impact the Company’s income tax expense. Of the $709 million in unrecognized tax benefits, $673 million relates to periods prior to the Company’s emergence from bankruptcy. In accordance with Statement of Position 90-7, Financial Reporting by Entities in Reorganization under the Bankruptcy Code, and the application of fresh start accounting, recognition of previously unrecognized tax benefits existing pre-emergence would not impact the Company’s effective tax rate but would increase additional paid-in capital, or APIC. In accordance with SFAS 141R, any changes to our uncertain tax benefits occurring after January 1, 2009 will be credited to income tax expense rather than APIC.
 
As of September 30, 2008, NRG has recorded a $138 million non-current tax liability for unrecognized tax benefits, resulting from taxable earnings for the period, for which there are no NOLs available to offset for financial statement purposes. NRG accrued interest and penalties related to these unrecognized tax benefits of approximately $4 million as of September 30, 2008. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. For the nine months ended September 30, 2008, the Company incurred an immaterial amount of interest and penalties related to its unrecognized tax benefits.
 
Tax jurisdictions — NRG is subject to examination by taxing authorities for income tax returns filed in the US federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to US federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company’s significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2000.
 
The Company has been contacted for examination by the Internal Revenue Service for years 2004 through 2006. The audit commenced during the third quarter 2008 and is expected to continue for approximately 18 to 24 months.


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Note 13 —  Benefit Plans and Other Postretirement Benefits
 
NRG Defined Benefit Plans
 
NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-Bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation solely by eligible Texas-based employees. The total amount of employer contributions paid for the nine months ended September 30, 2008 was $57 million. NRG expects to make $7 million in further contributions for the remainder of 2008.
 
The net periodic pension cost related to all of the Company’s defined benefit pension plans includes the following components:
 
                                     
    Defined Benefit Pension Plans
    Three Months Ended September 30,     Nine Months Ended September 30,      
     
 (In millions)   2008     2007     2008     2007      
 
Service cost benefits earned
  $   4     $   3     $   11     $   11      
Interest cost on benefit obligation
    4       4       13       13      
Net gain
                (1 )          
Expected return on plan assets
    (4 )     (3 )     (11 )     (9 )    
 
 
Net periodic benefit cost
  $ 4     $ 4     $ 12     $ 15      
 
 
 
The net periodic cost related to all of the Company’s other postretirement benefits plans include the following components:
 
                                     
    Other Postretirement Benefits Plans
    Three Months Ended September 30,     Nine Months Ended September 30,      
     
 (In millions)   2008     2007     2008     2007      
 
Service cost benefits earned
  $      1     $      1     $      2     $      2      
Interest cost on benefit obligation
    1       2       4       4      
 
 
Net periodic benefit cost
  $ 2     $ 3     $ 6     $ 6      
 
 
 
STP Defined Benefit Plans
 
NRG has a 44% undivided ownership interest in South Texas Project, or STP. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. The total amount of employer contributions reimbursed to STPNOC for the nine months ended September 30, 2008 was $4 million. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plans of $2 million and $1 million for the three months ended September 30, 2008 and 2007, respectively. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plan of $6 million and $5 million for the nine months ended September 30, 2008 and 2007, respectively.


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Note 14 —  Commitments and Contingencies
 
Commitments
 
Fuel Commitments
 
NRG enters into long-term contractual arrangements to procure fuel and transportation services for the Company’s generation assets. NRG entered into additional coal purchase agreements during the nine months ended September 30, 2008 with total commitments of approximately $465 million, spanning from 2008 through 2011. In addition, NRG’s natural gas purchase commitments have decreased by approximately $264 million during the nine months ended September 30, 2008 as the 2008 monthly commitments were settled.
 
First and Second Lien Structure
 
NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets in the United States in order to secure primarily long-term obligations under power and gas sale agreements and related contracts. NRG uses the first or second lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program is limited by volumes hedged, not by the value of underlying out-of-the money positions. The first lien program does not require us to post collateral above any threshold amount of exposure. Within the first and second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first rolling 60 months with such permitted hedging volumes declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first and second lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty.
 
As part of the amendments to NRG’s Senior Credit Facility entered into on June 8, 2007, the Company obtained the ability to move its second lien counterparty exposure to the first lien on a pari passu basis with the Company’s existing first lien lenders. In exchange for moving to a pari passu basis with the Company’s first lien lenders, the counterparties relinquished letters of credit issued by NRG which they held as a part of their collateral package.
 
The Company’s lien counterparties may have a claim on our assets to the extent their net positions are out-of-the-money. As of September 30, 2008 and October 23, 2008, the first lien exposure of net out-of-the-money positions to counterparties on hedges was $405 million and $185 million, respectively. As of September 30, 2008 and October 23, 2008, the second lien net out-of-the-money positions to counterparties on hedges were approximately $16 million and $2 million, respectively.
 
RepoweringNRG
 
NRG has made non-refundable payments relating to RepoweringNRG projects totaling approximately $148 million primarily towards the procurement of wind turbines. The Company believes that these payments are necessary for the timely and successful execution of these projects. The payments are in support of expected deliveries of wind turbines and other equipment totaling approximately $248 million through 2009. In addition, as discussed further in Note 1, Basis of Presentation, NRG expects to contribute approximately $87 million in equity to Sherbino in 2008 and has posted a letter of credit in that amount. To date, NRG has made capital contributions to Sherbino in the amount of $17 million. Also, NRG’s share of cash security posted to The Connecticut Light and Power Company by GenConn Energy LLC, or GenConn, a 50/50 joint venture vehicle of NRG and The United Illuminating Company, for the project at Devon Station is approximately $9 million.


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Contingencies
 
Set forth below is a description of the Company’s material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. Pursuant to the requirements of SFAS No. 5, Accounting for Contingencies, or SFAS 5, and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company’s liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.
 
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect NRG’s consolidated financial position, results of operations, or cash flows.
 
California Department of Water Resources
 
On December 19, 2006, the US Court of Appeals for the Ninth Circuit reversed the Federal Energy Regulatory Commission’s, or FERC’s, prior determinations regarding the enforceability of certain wholesale power contracts and remanded the case to FERC for further proceedings consistent with the decision. One of these contracts was the wholesale power contract between the California Department of Water Resources, or CDWR, and subsidiaries of WCP. This case originated with a February 2002 complaint filed at FERC by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, FERC rejected this complaint, denied rehearing, and the case was appealed to the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Court decided that in FERC’s review of the contracts at issue, FERC could not rely on the Mobil-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by FERC with full knowledge of the then existing market conditions. On May 3, 2007, WCP and the other defendants filed separate petitions for certiorari seeking review by the US Supreme Court. On June 26, 2008, the Supreme Court issued its decision. The Court held (1) that the Mobil-Sierra public interest standard of review applied to contracts made under a seller’s market-based rate authority; (2) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (3) that the Mobil-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. The Supreme Court affirmed the Ninth Circuit’s decision, agreeing that the case should be remanded to FERC to clarify FERC’s 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. Although WCP’s petition for review was not heard by the Supreme Court, the Supreme Court’s decision with respect to the Morgan Stanley petition applies equally to WCP.
 
On October 20, 2008, the Ninth Circuit ordered the parties, including FERC, to submit short briefs on the question of whether that Court should answer a question that the US Supreme Court did not address in its June 26, 2008, decision. That question is whether the Mobil-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in the case. WCP’s response is due November 14, 2008.
 
At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG’s financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy’s 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.


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Station Service Disputes
 
On October 2, 2000, Niagara Mohawk Power Corporation, or NiMo, commenced an action against NRG in New York state court seeking damages related to NRG’s alleged failure to pay retail tariff amounts for utility services at the Dunkirk plant between June 1999 and September 2000. The parties agreed to consolidate this action with two other actions against the Huntley and Oswego plants. On October 8, 2002, by stipulation and order, this action was stayed pending submission to FERC of the disputes in the action. At FERC, NiMo asserted the same claims and legal theories, and on November 19, 2004, FERC denied NiMo’s petition and ruled that the NRG facilities could net their service obligations over each 30 calendar day period from the day NRG acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. NiMo appealed to the US Court of Appeals for the D.C. Circuit which, on June 23, 2006, denied the appeal finding that New York Independent System Operator’s, or NYISO’s, station service program that permits generators to self supply their station power needs by netting consumption against production in a month is lawful. On April 30, 2007, the US Supreme Court denied NiMo’s request for review of the D.C. Circuit decision thus ending further avenues to appeal FERC’s ruling in this matter. NRG believes it is adequately reserved.
 
On December 14, 1999, NRG acquired certain generating facilities from CL&P. A dispute arose over station service power and delivery services provided to the facilities. On December 20, 2002, as a result of a petition filed at FERC by Northeast Utilities Services Company on behalf of itself and CL&P, FERC issued an order finding that, at times when NRG is not able to self-supply its station power needs, there is a sale of station power from a third-party and retail charges apply. In August 2003, the parties agreed to submit the dispute to binding arbitration. On September 11, 2007, the parties argued the dispute before a three judge arbitration panel. On February 19, 2008, the parties executed a settlement agreement ending the arbitration, and on April 30, 2008, that settlement agreement became effective thereby ending the case.
 
Native Village of Kivalina and City of Kivalina
 
Twenty-four electric generating companies and oil and gas companies were named as defendants in this complaint, in which damages of up to $400 million had been asserted. The complaint was filed on behalf of a small Alaskan town and sought damages associated with the need to relocate from the northern coast of Alaska purportedly because of the effects of global warming caused by the defendant’s CO2 emissions. On June 11, 2008, NRG and the plaintiffs executed a Stipulation of Dismissal with Prejudice and on June 16, 2008, the US District Court for the Northern District of California dismissed NRG with prejudice thereby ending the case for NRG. The Company had argued to the plaintiffs that their allegations were blocked by NRG’s 2003 bankruptcy. NRG did not pay any money or exchange anything of value with the plaintiffs in exchange for its dismissal.
 
Spring Creek Coal Company
 
In August 2007, Spring Creek Coal Company filed a complaint against NRG Texas LP, NRG South Texas LP, NRG Texas Power LLC, NRG Texas LLC, and NRG Energy, Inc. in the US District Court for the federal district of Wyoming. The complaint alleged multiple breaches in 2007 of a 1978 coal supply agreement as amended by a later 1987 agreement, which plaintiff alleges is a “take or pay” contract. On April 10, 2008, the parties reached a settlement in principal ending the litigation and on May 5, 2008, the parties executed a settlement agreement. On May 15, 2008, the case was dismissed with prejudice thereby ending the matter. While neither party admitted liability in the settlement, NRG paid Spring Creek approximately $18 million for the amount of coal it did not take in 2007 and NRG’s obligation to take coal under the coal supply agreement in the future was reduced by an identical amount. In addition, NRG is receiving a price reduction on all remaining tons under the coal supply agreement valued at approximately $3 million. NRG recorded expense of $15 million in connection with the settlement.
 
Disputed Claims Reserve
 
As part of NRG’s plan of reorganization, NRG funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, as such claims are resolved, the claimants are paid from the reserve on the same basis as if they had been paid out in the bankruptcy. To the extent the aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the funded claims reserve, NRG will be obligated to provide additional cash and common stock to satisfy the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the reserves is held by an escrow agent to complete the distribution and settlement process. Since NRG has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from the balance sheet. Similarly, NRG removed the obligations relevant to the claims from the balance sheet when the common stock was issued and cash contributed.


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On April 3, 2006, the Company made a supplemental distribution to creditors under the Company’s Chapter 11 bankruptcy plan, totaling $25 million in cash and 5,082,000 shares of common stock. As of October 23, 2008, the reserve held approximately $10 million in cash and approximately 1,319,142 shares of common stock. NRG believes the cash and stock together represent sufficient funds to satisfy all remaining disputed claims. During the fourth quarter of 2008, NRG expects to file with the US Bankruptcy Court for the Southern District of New York, a Closing Report and an Application for Final Decree Closing the Chapter 11 Case for NRG Energy, Inc. et al.
 
Note 15 —  Regulatory Matters
 
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which NRG participates. These wholesale power markets are subject to ongoing legislative and regulatory changes.
 
New England — On July 16, 2007, FERC conditionally accepted, subject to refund, the Reliability-Must-Run, or RMR, agreement filed on April 26, 2007 by Norwalk Power for its units 1 and 2, specifying a June 19, 2007 effective date. Norwalk’s RMR rate and its eligibility for the RMR agreement, which is based upon the facility’s projected market revenues and costs, are subject to further proceedings. Norwalk filed for the RMR agreement in response to FERC’s order eliminating the Peaking Unit Safe Harbor bidding mechanism which took effect on June 19, 2007. Settlement proceedings are still ongoing.
 
On March 18, 2008, the US Court of Appeals for the D.C. Circuit rejected the appeal filed by the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts regarding the settlement of the New England capacity market design. The settlement, filed with FERC on March 7, 2006, by a broad group of New England market participants, provides for interim capacity transition payments for all generators in New England for the period starting December 1, 2006 through May 31, 2010, and a Forward Capacity Market, or FCM, for the period thereafter. All substantive challenges to the settlement, to the validity of the interim capacity transition payments, and to the market design were rejected by the D.C. Circuit, although one procedural argument relating to future challenges by non-settling parties was sustained. Several parties sought rehearing on this issue due to concerns regarding the sanctity of contracts. On October 6, 2008, the D.C. Circuit denied all requests for rehearing.
 
New York — On March 7, 2008, FERC issued an order accepting the NYISO’s proposed market reforms to the in-city Installed Capacity, or ICAP, market, with only minor modifications. On October 4, 2007, the NYISO had filed its proposal for revising the ICAP market for the New York City zone. The proposal retains the existing ICAP market structure, but imposes additional market power mitigation on the current owners of Consolidated Edison’s divested generation units in New York City (which include NRG’s Arthur Kill and Astoria facilities), who are deemed to be pivotal suppliers. Specifically, the NYISO proposal imposes a new reference price on pivotal suppliers and requires bids to be submitted at or below the reference price. The new reference price is derived from the expected clearing price based upon the intersection of the supply curve and the ICAP Demand Curve if all suppliers bid as price-takers. The NYISO’s proposed reforms became effective March 27, 2008. Although FERC had established a refund effective date of May 12, 2007, its March 7 order determined that the NYISO’s proposal should be implemented only prospectively and that no refunds should be required. No party sought rehearing on the refund issue, thus resolving the contingency. On September 29, 2008, FERC issued its order on rehearing and the NYISO’s compliance filings that substantially reaffirmed the NYISO’s proposed market reforms.
 
On March 15, 2006, NRG received the results from NYISO Market Monitoring Unit’s review of NRG’S Astoria plant’s 2004 Generating Availability Data System, or GADS, reporting. On July 25, 2008, the NYISO determined that it would assess NRG a capacity deficiency charge relating to the Astoria plant as a result of a restatement of its GADS data for 2004. NRG agreed to and paid the NYISO’s assessment.
 
PJM — On August 23, 2007, several entities, including the New Jersey Board of Public Utilities, the District of Columbia Office of the People’s Counsel, and the Maryland Office of People’s Counsel, filed appeals of the FERC orders accepting the settlement of the locational capacity market for PJM Interconnection, LLC. The settlement, filed at FERC on September 29, 2006, provides for a capacity market mechanism known as the Reliability Pricing Model, or RPM, which is designed to provide a long-term price signal through competitive forward auctions. On December 22, 2006, FERC issued an order accepting the settlement, which was reaffirmed on rehearing by order dated June 25, 2007. The RPM auctions have been conducted and capacity payments pursuant to the RPM mechanism have commenced. A successful appeal by the appellants could disturb the settlement and create a refund obligation of capacity payments.


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On January 15, 2008, the Maryland Public Service Commission, or MDPSC, filed at FERC a complaint against PJM claiming that PJM had failed to adequately mitigate certain generation resources, due to exemptions for resources used to relieve reactive limits on interfaces or that were constructed during certain periods after 1999. In addition to seeking an order eliminating the exemptions and a refund effective date as of the date of the complaint, the MDPSC sought an investigation of periods prior to the complaint that could have led to disgorgement by certain entities, and possibly a resettlement of the market. On May 16, 2008, FERC issued an order granting in part, and dismissing in part, the complaint and establishing a proceeding to examine the justness and reasonableness of PJM’s other market power mitigation mechanisms. FERC denied the request for retroactive relief and resettlement of the market.
 
On May 30, 2008, the MDPSC, together with other load interests, filed at FERC a complaint against PJM challenging the results of the RPM transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint seeks to replace the auction-determined results for installed capacity for the 2008/2009, 2009/2010, and 2010/2011 delivery years with administratively-determined prices. On September 19, 2008, FERC dismissed the complaint. The parties representing load interests have sought rehearing of the dismissal of the complaint. In a related proceeding, FERC directed PJM to commence stakeholder processes towards addressing issues with RPM and required PJM to make a filing of proposed changes to RPM no later than December 15, 2008.
 
Note 16 —  Environmental Matters
 
The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the US. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. New legislation and regulations to mitigate the effects of greenhouse gas, or GHG, including CO2 from power plants, are under consideration at the federal and state levels. In general, the effect of such future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the Company’s operations.
 
Environmental Capital Expenditures
 
Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures to be incurred from 2008 through 2013 will be approximately $1.3 billion. These capital expenditures, in general, are related to installation of particulate, SO2, NOx, and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of “Best Technology Available” under the Phase II 316(b) rule. NRG continues to explore cost effective alternatives that can achieve desired results. While this estimate reflects anticipated changes in schedules and controls related to recent court rulings that vacate both the Clean Air Interstate Rule, or CAIR, and the Clear Air Mercury Rule, or CAMR, the full impact on the scope and timing of environmental retrofits from any revised and/or replacement regulations cannot be determined at this time.
 
Northeast Region
 
On December 20, 2005, 10 northeastern states entered into a Memorandum of Understanding, or MOU, to create the Regional Greenhouse Gas Initiative, or RGGI, to establish a cap-and-trade GHG program for electric generators. Electric generating units in participating RGGI states will have to procure one allowance for every US ton of CO2 emitted with true up for 2009-2011 occurring in 2012. NRG units located in Connecticut, Delaware, Maryland, Massachusetts and New York emitted approximately 13 million US tons of CO2 in 2007. NRG believes that to the extent allowance costs will not be fully reflected in wholesale electricity prices, the direct financial impact on the Company is likely to be negative as costs are incurred to secure the necessary RGGI allowances and offsets at auction and in the market.
 
On May 29, 2008, the Delaware Department of Natural Resources, or DNREC, issued an invitation to NRG’s Indian River Operations, Inc. to participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with the DNREC and other Trustees to close out the property.


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South Central Region
 
On January 27, 2004, NRG’s Louisiana Generating LLC and the Company’s Big Cajun II plant received a request under Section 114 of the Clean Air Act, or CAA, from USEPA seeking information primarily related to physical changes made at the Big Cajun II plant, and subsequently received a notice of violation, or NOV, on February 15, 2005, alleging that NRG’s predecessors had undertaken projects that triggered requirements under the Prevention of Significant Deterioration, or PSD, program, including the installation of emission controls. NRG submitted multiple responses commencing February 27, 2004 and ending on October 20, 2004. On May 9, 2006, these entities received from the Department of Justice, or DOJ, a notice of deficiency related to their responses, to which NRG responded on May 22, 2006. A document review was conducted at NRG’s Louisiana Generating LLC offices by the DOJ during the week of August 14, 2006. On December 8, 2006, the USEPA issued a supplemental NOV updating the original February 15, 2005 NOV. Discussions with the USEPA are ongoing and the Company cannot predict with certainty the outcome of this matter.
 
Note 17 —  Guarantees
 
NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company’s business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, joint venture agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. In some cases, NRG’s maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability.
 
This footnote should be read in conjunction with the complete description under Note 25, Guarantees, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2007.
 
For the nine months ended September 30, 2008, NRG had net increases to its guarantee obligations under other commercial arrangements of approximately $202 million.


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Note 18 —  Condensed Consolidating Financial Information
 
As of September 30, 2008, the Company had $1.2 billion of 7.25% Senior Notes due 2014, $2.4 billion of 7.375% Senior Notes due 2016 and $1.1 billion of 7.375% Senior Notes due 2017 outstanding. These notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.
 
Each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2008:
 
     
Arthur Kill Power LLC
  NRG Construction LLC
Astoria Gas Turbine Power LLC
  NRG Devon Operations Inc.
Berrians I Gas Turbine Power LLC
  NRG Dunkirk Operations, Inc.
Big Cajun II Unit 4 LLC
  NRG El Segundo Operations Inc.
Cabrillo Power I LLC
  NRG Generation Holdings, Inc.
Cabrillo Power II LLC
  NRG Huntley Operations Inc.
Chickahominy River Energy Corp.
  NRG International LLC
Commonwealth Atlantic Power LLC
  NRG Kaufman LLC
Conemaugh Power LLC
  NRG Mesquite LLC
Connecticut Jet Power LLC
  NRG MidAtlantic Affiliate Services Inc.
Devon Power LLC
  NRG Middletown Operations Inc.
Dunkirk Power LLC
  NRG Montville Operations Inc.
Eastern Sierra Energy Company
  NRG New Jersey Energy Sales LLC
El Segundo Power, LLC
  NRG New Roads Holdings LLC
El Segundo Power II LLC
  NRG North Central Operations, Inc.
GCP Funding Company LLC
  NRG Northeast Affiliate Services Inc.
Hanover Energy Company
  NRG Norwalk Harbor Operations Inc.
Hoffman Summit Wind Project LLC
  NRG Operating Services Inc.
Huntley IGCC LLC
  NRG Oswego Harbor Power Operations Inc.
Huntley Power LLC
  NRG Power Marketing LLC
Indian River IGCC LLC
  NRG Rocky Road LLC
Indian River Operations Inc.
  NRG Saguaro Operations Inc.
Indian River Power LLC
  NRG South Central Affiliate Services Inc.
James River Power LLC
  NRG South Central Generating LLC
Kaufman Cogen LP
  NRG South Central Operations Inc.
Keystone Power LLC
  NRG South Texas LP
Lake Erie Properties Inc.
  NRG Texas LLC
Louisiana Generating LLC
  NRG Texas Power LLC
Middletown Power LLC
  NRG West Coast LLC
Montville IGCC LLC
  NRG Western Affiliate Services Inc.
Montville Power LLC
  Oswego Harbor Power LLC
NEO Chester-Gen LLC
  Padoma Wind Power, LLC
NEO Corporation
  Saguaro Power LLC
NEO Freehold-Gen LLC
  San Juan Mesa Wind Project II, LLC
NEO Power Services Inc.
  Somerset Operations Inc.
New Genco GP LLC
  Somerset Power LLC
Norwalk Power LLC
  Texas Genco Financing Corp.
NRG Affiliate Services Inc.
  Texas Genco GP, LLC
NRG Arthur Kill Operations Inc.
  Texas Genco Holdings, Inc.
NRG Asia-Pacific Ltd.
  Texas Genco LP, LLC
NRG Astoria Gas Turbine Operations Inc.
  Texas Genco Operating Services, LLC
NRG Bayou Cove LLC
  Texas Genco Services, LP
NRG Cabrillo Power Operations Inc.
  Vienna Operations, Inc.
NRG Cadillac Operations Inc.
  Vienna Power LLC
NRG California Peaker Operations LLC
  WCP (Generation) Holdings LLC
NRG Cedar Bayou Development Company LLC
  West Coast Power LLC
NRG Connecticut Affiliate Services Inc.
   


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The non-guarantor subsidiaries include all of NRG’s foreign subsidiaries and certain domestic subsidiaries. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company’s ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG’s ability to receive funds from its subsidiaries. Except for NRG Bayou Cove LLC, which is subject to certain restrictions under the Company’s Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries.
 
The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
 
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis.


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NRG ENERGY, INC. AND SUBSIDIARIES
 
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2008
 
                                             
                NRG Energy,
                 
    Guarantor
    Non-Guarantor
    Inc.
          Consolidated
     
 (In millions)   Subsidiaries     Subsidiaries     (Note Issuer)     Eliminations (a)     Balance      
 
Operating Revenues
                                           
Total operating revenues
  $  2,597       $ 111       $      —       $      (18 )     $ 2,690      
 
 
Operating Costs and Expenses
                                           
Cost of operations
    919       99       (3 )     (18 )     997      
Depreciation and amortization
    148       7       1             156      
General and administrative
    16       14       45             75      
Development costs
    2       2       9             13      
 
 
Total operating costs and expenses
    1,085       122       52       (18 )     1,241      
 
 
Operating Income/(Loss)
    1,512       (11 )     (52 )           1,449      
Other Income/(Expense)
                                           
Equity in earnings/(losses) of consolidated subsidiaries
    52             897       (949 )          
Equity in earnings of unconsolidated affiliates
    1       57                   58      
Other income/(expense), net
    4       11       (22 )           (7 )    
Interest expense
    (46 )     (61 )     (79 )           (186 )    
 
 
Total other income/(expense)
    11       7       796       (949 )     (135 )    
 
 
Income/(Losses) From Continuing Operations Before Income Taxes
    1,523       (4 )      744       (949 )     1,314      
Income tax expense/(benefit)
    532       38       (40 )           530      
 
 
Income/(Losses) From Continuing Operations
    991       (42 )     784       (949 )     784      
Income/(Losses) from discontinued operations, net of income taxes
                                 
 
 
Net Income/(Loss)
  $ 991       $(42 )     $    784       $     (949 )     $784      
 
 
 
 
(a) All significant intercompany transactions have been eliminated in consolidation.


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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2008
 
                                             
                NRG Energy,
                 
    Guarantor
    Non-Guarantor
    Inc.
          Consolidated
     
 (In millions)   Subsidiaries     Subsidiaries     (Note Issuer)     Eliminations (a)     Balance      
 
Operating Revenues
                                           
Total operating revenues
  $ 5,020       $    306       $      —       $      (18 )     $ 5,308      
 
 
Operating Costs and Expenses
                                           
Cost of operations
    2,600       231             (19 )     2,812      
Depreciation and amortization
    454       21       3             478      
General and administrative
    47       10       176             233      
Development costs
    (3 )     5       27             29      
 
 
Total operating costs and expenses
    3,098       267       206       (19 )     3,552      
 
 
Operating Income/(Loss)
    1,922       39       (206 )     1       1,756      
Other Income/(Expense)
                                           
Equity in earnings/(losses) of consolidated subsidiaries
    262             1,347       (1,609 )          
Equity in (losses)/earnings of unconsolidated affiliates
    (2 )     37                   35      
Other income/(expense), net
    19       10       (14 )     (1 )     14      
Interest expense
    (148 )     (95 )     (238 )           (481 )    
 
 
Total other income/(expense)
    131       (48 )     1,095       (1,610 )     (432 )    
 
 
Income/(Losses) From Continuing Operations Before Income Taxes
    2,053       (9 )     889       (1,609 )     1,324      
Income tax expense/(benefit)
    699       5       (173 )           531      
 
 
Income/(Losses) From Continuing Operations
    1,354       (14 )     1,062       (1,609 )     793      
Income/(Losses) from discontinued operations, net of income taxes
          269       (97 )           172      
 
 
Net Income/(Loss)
  $ 1,354       $     255       $     965       $   (1,609 )     $ 965      
 
 
 
 
(a) All significant intercompany transactions have been eliminated in consolidation.


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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2008
 
                                             
    Guarantor
    Non-Guarantor
    NRG Energy, Inc.
          Consolidated
     
 (In millions)   Subsidiaries     Subsidiaries     (Note Issuer)     Eliminations (a)     Balance      
 
ASSETS
Current Assets
                                           
Cash and cash equivalents
  $ 2     $ 182     $ 1,299     $     $ 1,483      
Restricted cash
    1       31                   32      
Accounts receivable, net
    487       44                   531      
Inventory
    444       12                   456      
Derivative instruments valuation
    4,190                         4,190      
Cash collateral paid in support of energy risk management activities
    544                         544      
Prepayments and other current assets
    79       35       382       (293 )     203      
 
 
Total current assets
    5,747       304       1,681       (293 )     7,439      
 
 
Net property, plant and equipment
    10,752       696       24             11,472      
 
 
Other Assets
                                           
Investment in subsidiaries
    659       19       10,936       (11,614 )          
Equity investments in affiliates
    26       402                   428      
Notes receivable and capital lease, less current portion
    535       450       2,889       (3,424 )     450      
Goodwill
    1,786                         1,786      
Intangible assets, net
    808       14                   822      
Nuclear decommissioning trust
    333                         333      
Derivative instruments valuation
    816                         816      
Other non-current assets
    6       3       125             134      
Intangible assets held-for-sale
    3                         3      
 
 
Total other assets
    4,972       888       13,950       (15,038 )     4,772      
 
 
Total Assets
  $ 21,471     $ 1,888     $ 15,655     $ (15,331 )   $ 23,683      
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
                                           
Current portion of long-term debt and capital leases
  $ 83     $ 90     $ 31     $ (82 )   $ 122      
Accounts payable
    (293 )     648       12             367      
Derivative instruments valuation
    4,011       10       1             4,022      
Deferred income taxes
          19       (3 )           16      
Cash collateral received in support of energy risk management activities
    154                         154      
Accrued expenses and other current liabilities
    422       36       381       (210 )     629      
 
 
Total current liabilities
    4,377       803       422       (292 )     5,310      
 
 
Other Liabilities
                                           
Long-term debt and capital leases
    2,808       824       7,852       (3,425 )     8,059      
Nuclear decommissioning reserve
    320                         320      
Nuclear decommissioning trust liability
    252                         252      
Deferred income taxes
    659       (172 )     596             1,083      
Derivative instruments valuation
    1,089       17       52             1,158      
Out-of-market contracts
    336                         336      
Other non-current liabilities
    360       65       143             568      
 
 
Total non-current liabilities
    5,824       734       8,643       (3,425 )     11,776      
 
 
Total liabilities
    10,201       1,537       9,065       (3,717 )     17,086      
 
 
Minority interest
    7                         7      
3.625% Preferred Stock
                247             247      
Stockholders’ Equity
    11,263       351       6,343       (11,614 )     6,343      
 
 
Total Liabilities and Stockholders’ Equity
  $  21,471     $  1,888     $  15,655     $  (15,331 )   $  23,683      
 
 
 
 
(a) All significant intercompany transactions have been eliminated in consolidation.


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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2008
 
                                             
          Non-
    NRG Energy,
                 
    Guarantor
    Guarantor
    Inc.
          Consolidated
     
 (In millions)   Subsidiaries     Subsidiaries     (Note Issuer)     Eliminations (a)     Balance      
 
Cash Flows from Operating Activities
                                           
Net income
  $1,354       $     255       $     965       $   (1,609 )   $     965      
Adjustments to reconcile net income to net cash provided by operating activities:
                                           
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries
    (260 )     (26 )     (1,347 )     1,609       (24 )    
Depreciation and amortization
    454       21       3             478      
Amortization of nuclear fuel
    31                         31      
Amortization of financing costs and debt discount
          5       17             22      
Amortization of intangibles and out-of-market contracts
    (226 )                       (226 )    
Changes in deferred income taxes and liability for unrecognized tax benefits
    102       (21 )     346             427      
Changes in nuclear decommissioning liability
    8                         8      
Changes in derivatives
    (101 )     (9 )                 (110 )    
Changes in collateral deposits supporting energy risk management activities
    (320 )                       (320 )    
Loss on disposal and sales of assets
    13                         13      
Gain on sale of discontinued operations
          (273 )                 (273 )    
Gain on sale of emission allowances
    (52 )                       (52 )    
Amortization of unearned equity compensation
                21             21      
Cash provided by/(used by) changes in other working capital
    473       52       (444 )           81      
 
 
Net Cash Provided (Used) by Operating Activities
    1,476       4       (439 )           1,041      
 
 
Cash Flows from Investing Activities
                                           
Intercompany (loans to)/receipts from subsidiaries
    (175 )           885       (710 )          
Capital expenditures
    (444 )     (200 )     (5 )           (649 )    
Increase in restricted cash
          (3 )                 (3 )    
Decrease in notes receivable
          35       (15 )           20      
Purchases of emission allowances
    (6 )                       (6 )    
Proceeds from sale of emission allowances
    75                         75      
Investment in nuclear decomissioning trust fund securities
    (441 )                       (441 )    
Proceeds from sales of nuclear decomissioning trust fund securities
    434                         434      
Proceeds from sale of discontinued operations, net of cash divested
          (59 )     300             241      
Proceeds from sale of assets
    14                         14      
Equity investments in unconsolidated affiliates
                (17 )           (17 )    
 
 
Net Cash Provided (Used) by Investing Activities
    (543 )     (227 )     1,148       (710 )     (332 )    
 
 
Cash Flows from Financing Activities
                                           
(Payments)/proceeds for intercompany loans
    (882 )     208       (36 )     710            
Payments for dividends to preferred stockholders
                (41 )           (41 )    
Payment of financing element of acquired derivatives
    (49 )                       (49 )    
Payments for treasury stock
                (185 )           (185 )    
Proceeds from issuance of common stock, net of issuance costs
                8             8      
Proceeds from sale of minority interest in subsidiary
          50                   50      
Proceeds from issuance of long-term debt
          20                   20      
Payments for deferred debt issuance costs
                (2 )           (2 )    
Payments for short and long-term debt
          (36 )     (166 )           (202 )    
 
 
Net Cash Provided (Used) by Financing Activities
    (931 )     242       (422 )     710       (401 )    
Change in cash from discontinued operations
          43                   43      
Effect of exchange rate changes on cash and cash equivalents
                                 
 
 
Net Increase in Cash and Cash Equivalent
    2       62       287             351      
Cash and Cash Equivalents at Beginning of Period
          120       1,012             1,132      
 
 
Cash and Cash Equivalents at End of Period
  $      2       $     182       $   1,299       $     —       $   1,483      
 
 
 
 
(a) All significant intercompany transactions have been eliminated in consolidation.


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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2007
 
                                             
                NRG Energy,
                 
    Guarantor
    Non-Guarantor
    Inc.
          Consolidated
     
 (In millions)   Subsidiaries     Subsidiaries     (Note Issuer)     Eliminations (a)     Balance      
 
 
 Operating Revenues
                                           
Total operating revenues
  $  1,676       $       96       $      —       $      —       $   1,772      
 
 
Operating Costs and Expenses
                                           
Cost of operations
    868       73       (2 )           939      
Depreciation and amortization
    153       4       3             160      
General and administrative
    34       5       39             78      
Development costs
    30       1       18             49      
 
 
Total operating costs and expenses
    1,085       83       58             1,226      
Gain/(Loss) on sale of assets
    (1 )           1                  
 
 
Operating Income/(Loss)
    590       13       (57 )           546      
Other Income/(Expense)
                                           
Equity in earnings of consolidated subsidiaries
    60             359       (419 )          
Equity in (losses)/earnings of unconsolidated affiliates
    1       18                   19      
Other income, net
    3       3       13       (5 )     14      
Interest expense
    (60 )     (19 )     (95 )     5       (169 )    
 
 
Total other income/(expense)
    4       2       277       (419 )     (136 )    
 
 
Income From Continuing Operations Before Income Taxes
    594       15       220       (419 )     410      
Income tax expense/(benefit)
    216       (23 )     (48 )           145      
 
 
Income From Continuing Operations
    378       38       268       (419 )     265      
Income from discontinued operations, net of income taxes
          3                   3      
 
 
Net Income
  $ 378       $    41       $     268       $     (419 )     $    268      
 
 
 
(a) All significant intercompany transactions have been eliminated in consolidation.


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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2007
 
                                             
                NRG Energy,
                 
    Guarantor
    Non-Guarantor
    Inc.
          Consolidated
     
 (In millions)   Subsidiaries     Subsidiaries     (Note Issuer)     Eliminations (a)     Balance      
 
Operating Revenues
                                           
Total operating revenues
  $  4,326       $     281       $     —       $     —     $   4,607      
 
 
Operating Costs and Expenses
                                           
Cost of operations
    2,346       213       1             2,560      
Depreciation and amortization
    460       17       4             481      
General and administrative
    80       14       140             234      
Development costs
    85       1       22             108      
 
 
Total operating costs and expenses
    2,971       245       167             3,383      
Gain/(loss) on sale of assets
    16                         16      
 
 
Operating Income/(Loss)
    1,371       36       (167 )           1,240      
Other Income/(Expense)
                                           
Equity in earnings of consolidated subsidiaries
    114             768       (882 )          
Equity in (losses)/earnings of unconsolidated affiliates
    (2 )     42                   40      
Other income, net
    7       22       30       (15 )     44      
Refinancing expense
                (35 )           (35 )    
Interest expense
    (198 )     (63 )     (274 )     15       (520 )    
 
 
Total other income/(expense)
    (79 )     1       489       (882 )     (471 )    
 
 
Income From Continuing Operations Before Income Taxes
    1,292       37       322       (882 )     769      
Income tax expense/(benefit)
    472       (12 )     (160 )           300      
 
 
Income From Continuing Operations
    820       49       482       (882 )     469      
Income from discontinued operations, net of income taxes
          13                   13      
 
 
Net Income
  $ 820       $     62       $     482     $ $     (882 )   $     482      
 
 
 
(a) All significant intercompany transactions have been eliminated in consolidation.


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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2007
 
                                             
    Guarantor
    Non-Guarantor
    NRG Energy
          Consolidated
     
 (In millions)   Subsidiaries     Subsidiaries     Inc.     Eliminations (a)     Balance      
 
 
ASSETS
                                           
Current Assets
                                           
Cash and cash equivalents
  $     $ 120     $ 1,012     $     $ 1,132      
Restricted cash
    1       28                   29      
Accounts receivable, net
    445       37                   482      
Inventory
    439       12                   451      
Deferred income taxes
    139       (18 )     3             124      
Derivative instruments valuation
    1,034                         1,034      
Cash collateral paid in support of energy risk management activities
    85                         85      
Prepayments and other current assets
    97       34       195       (152 )     174      
Current assets — discontinued operations
          51                   51      
 
 
Total current assets
    2,240       264       1,210       (152 )     3,562      
 
 
Net Property, Plant and Equipment
    10,828       470       22             11,320      
 
 
Other Assets
                                           
Investment in subsidiaries
    610             9,787       (10,397 )          
Equity investments in affiliates
    28       397                   425      
Notes receivable
    360       126       3,779       (4,139 )     126      
Capital lease, less current portion
          365                   365      
Goodwill
    1,786                         1,786      
Intangible assets, net
    859       14                   873      
Intangible assets held-for-sale
    14                         14      
Nuclear decommissioning trust fund
    384                         384      
Derivative instruments valuation
    150                         150      
Other non-current assets
    11       1       164             176      
Non-current assets — discontinued operations
          93                   93      
 
 
Total other assets
    4,202       996       13,730       (14,536 )     4,392      
 
 
Total Assets
  $ 17,270     $ 1,730     $ 14,962     $ (14,688 )   $ 19,274      
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                           
Current Liabilities
                                           
Current portion of long-term debt and capital leases
  $ 83     $ 282     $ 184     $ (83 )   $ 466      
Accounts payable — trade
    (695 )     348       731             384      
Derivative instruments valuation
    916       1                   917      
Cash collateral received in support of energy risk management activities
    14                         14      
Accrued expenses and other current liabilities
    321       62       145       (69 )     459      
Current liabilities — discontinued operations
          37                   37      
 
 
Total current liabilities
    639       730       1,060       (152 )     2,277      
 
 
Other Liabilities
                                           
Long-term debt and capital leases
    3,773       571       7,690       (4,139 )     7,895      
Nuclear decommissioning reserve
    307                         307      
Nuclear decommissioning trust liability
    326                         326      
Deferred income taxes
    598       (138 )     383             843      
Derivative instruments valuation
    690       16       53             759      
Non-current out-of-market contracts
    628                         628      
Other non-current liabilities
    377       10       25             412      
Non-current liabilities — discontinued operations
          76                   76      
 
 
Total non-current liabilities
    6,699       535       8,151       (4,139 )     11,246      
 
 
Total liabilities
    7,338       1,265       9,211       (4,291 )     13,523      
 
 
3.625% Preferred Stock
                247             247      
Stockholders’ Equity
    9,932       465       5,504       (10,397 )     5,504      
 
 
Total Liabilities and Stockholders’ Equity
  $  17,270     $  1,730     $  14,962     $  (14,688 )   $  19,274      
 
 
 
(a) All significant intercompany transactions have been eliminated in consolidation.


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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2007
 
                                             
          Non-
    NRG Energy,
                 
    Guarantor
    Guarantor
    Inc.
          Consolidated
     
 (In millions)   Subsidiaries     Subsidiaries     (Note Issuer)     Eliminations (a)     Balance      
 
 Cash Flows from Operating Activities
                                           
Net income
  $ 821     $ 61     $ 482     $  (882 )   $ 482      
Adjustments to reconcile net income to net cash provided by operating activities:
                                           
Distributions and equity (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries
    190       (25 )     (466 )     278       (23 )    
Depreciation and amortization
    459       20       4             483      
Amortization of nuclear fuel
    42                         42      
Amortization of financing costs and debt discount
          5       54             59      
Amortization of intangibles and out-of-market contracts
    (116 )     4                   (112 )    
Changes in deferred income taxes
    63       (40 )     209             232      
Changes in nuclear decommissioning trust liability
    23                         23      
Changes in derivatives
    41                         41      
Changes in collateral deposits supporting energy risk management activities
    (107 )                       (107 )    
Gain on disposal and sale of assets
    (16 )                       (16 )    
Gain on sale of emission allowances
    (31 )                       (31 )    
Amortization of unearned equity compensation
                19             19      
Cash (used)/provided by changes in other working capital
    (88 )     128       (156 )           (116 )    
 
 
Net Cash (Used)/Provided by Operating Activities
    1,281       153       146       (604 )     976      
 
 
Cash Flows from Investing Activities
                                           
Intercompany (loans to)/receipts from subsidiaries
    (81 )     (18 )     754       (655 )          
Capital expenditures
    (210 )     (93 )     (6 )           (309 )    
Increase in restricted cash
          (18 )                 (18 )    
Decrease in notes receivable
          26                     26      
Purchases of emission allowances
    (152 )                       (152 )    
Proceeds from the sale of emission allowances
    170                         170      
Investment in nuclear decommissioning trust fund securities
    (193 )                       (193 )    
Proceeds from sales of nuclear decommissioning trust fund securities
    170                         170      
Proceeds from the sale of assets
    29             28             57      
Decrease in trust fund balances
    19                         19      
Other
          2       (4 )           (2 )    
 
 
Net Cash (Used)/Provided by Investing Activities
    (248 )     (101 )     772       (655 )     (232 )    
 
 
Cash Flows from Financing Activities
                                           
Payments/proceeds for intercompany loans
    (754 )           99       655            
Payments from intercompany dividends
    (302 )     (302 )           604            
Payment for dividends to preferred stockholders
                (41 )           (41 )    
Payments for treasury stock
                (268 )           (268 )    
Proceeds from issuance of long-term debt
                1,411             1,411      
Payment of deferred debt issuance costs
                (5 )           (5 )    
Payments for short and long-term debt
    (1 )     (36 )     (1,435 )           (1,472 )    
 
 
Net Cash (Used)/Provided by Financing Activities
    (1,057 )     (338 )     (239 )     1,259       (375 )    
 
 
Effect of Exchange Rate Changes on Cash and Cash Equivalents
          7                   7      
Change in Cash from Discontinued Operations
          (16 )                 (16 )    
 
 
Net Increase/(Decrease) in Cash and Cash Equivalents
    (24 )     (295 )     679             360      
Cash and Cash Equivalents at Beginning of Period
    20       414       343             777      
 
 
Cash and Cash Equivalents at End of Period
  $ (4 )   $  119     $  1,022     $     $  1,137      
 
 
 
(a) All significant intercompany transactions have been eliminated in consolidation.


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ITEM 2 —  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Introduction and Overview
 
NRG Energy, Inc., or NRG, or the Company, is a wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is primarily engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the United States and select international markets. As of September 30, 2008, NRG had a total global portfolio of 189 active operating generation units at 48 power generation plants, with an aggregate generation capacity of approximately 24,020 MW and approximately 472 MW under construction. Within the United States, NRG has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,940 MW of generation capacity in 177 active generating units at 43 plants. These power generation facilities are primarily located in Texas (approximately 10,815 MW), the Northeast (approximately 7,020 MW), South Central (approximately 2,860 MW), and the West (approximately 2,130 MW) regions of the United States, with approximately 115 MW of additional generation capacity from the Company’s thermal assets. NRG’s principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired and nuclear facilities, representing approximately 46%, 33%, 16% and 5% of the Company’s total domestic generation capacity, respectively. In addition, 15% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option, and consist primarily of baseload, intermediate and peaking power generation facilities, the ranking of which is referred to as the Merit Order, and also include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company’s revenues. In addition, NRG’s generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.
 
The Company’s strategy is reflected in five major initiatives, described below. These initiatives are designed to enable the Company to take advantage of opportunities and surmount the challenges faced by the power industry.
 
1.  FORNRG is a companywide effort designed to increase the return on invested capital, or ROIC, through operational performance improvements to the Company’s asset fleet, along with a range of initiatives at plants and at corporate offices to reduce costs, or in some cases, monetize or reduce excess working capital and other assets. The FORNRG accomplishments disclosed in NRG’s SEC filings and press releases include both recurring and one-time improvements measured from a prior base year. For plant operations, the program measures cumulative current year benefits using current gross margins multiplied by the change in baseline levels of certain key performance indicators. The plant performance benefits include both positive and negative results for plant reliability, capacity, heat rate and station service. During 2007, the Company announced the acceleration and planned conclusion of the FORNRG 1.0 program by bringing forward the previously announced 2009 target of $250 million to 2008. Improvements in reliability throughout the baseload fleet, coupled with higher gross margins, especially in the Texas region, were the drivers of the year-to-date program performance. Through September 2008, the Company has estimated the cumulative value of implemented FORNRG improvements will achieve a value in excess of the established a goal of $250 million by December 31, 2008. The FORNRG 1.0 program was measured from a 2004 baseline, with the exception of the Texas Region where benefits were measured using 2005 as the base year.
 
Beginning in January 2009, the Company will transition to FORNRG 2.0 and target an incremental 100 basis point improvement to the Company’s return on invested capital by 2012. The initial targets for FORNRG 2.0 will be based upon improvements in the Company’s ROIC as measured by increased cash flow. The economic results of FORNRG 2.0 will focus on: (1) revenue enhancement, (2) cost savings, and (3) asset optimization including reducing excess working capital and other assets. FORNRG 2.0 program will measure its progress towards the FORNRG 2.0 goals by using the Company’s 2008 financial results as a baseline, while plant performance calculations will be based upon the average full year plant key performance indicators for years 2006-2008.
 
2. RepoweringNRG is a comprehensive portfolio redevelopment program designed to develop, construct and operate new multi-fuel, multi-technology, highly efficient and environmentally responsible generation capacity over the next decade. Through this initiative, the Company anticipates retiring certain existing units and adding new generation to meet growing demand in the Company’s core markets, with an emphasis on new capacity that is expected to be supported by long-term hedging programs, including power purchase agreements, or PPAs, and financed with limited or non-recourse project financing.


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3.  econrg represents NRG’s commitment to environmentally responsible power generation. econrg seeks to find ways for NRG to meet the challenges of climate change, clean air and water, and conservation of our natural resources while taking advantage of business opportunities that may inure to NRG as a result of our demonstration and deployment of “green” technologies. Within NRG, econrg builds upon a foundation in environmental compliance and embraces environmental initiatives for the benefit of our communities, employees and shareholders, such as encouraging investment in new environmental technologies, pursuing activities that preserve and protect the environment and encouraging changes in the daily lives of our employees.
 
4.  Future NRG is the Company’s workforce planning and development initiative and represents NRG’s strong commitment to planning for future staffing requirements to meet the on-going needs of the Company’s current operations in addition to the Company’s RepoweringNRG initiatives. Future NRG encompasses analyzing the demographics, skill set and size of the Company’s workforce in addition to the organizational structure with a focus on succession planning, training, development, staffing and recruiting needs. Included under the Future NRG umbrella is NRG University, which provides leadership, managerial, supervisory and technical training programs and individual skill development courses.
 
5.  NRG Global Giving — Respect for the community is one of NRG’s core values. Our Global Giving Program invests NRG’s resources to strengthen the communities where we do business and seeks to make community investments in four FOCUS areas: community and economic development, education, environment and human welfare.
 
NRG’s 2007 Annual Report on Form 10-K includes a detailed discussion of various items impacting its business, results of operations and financial condition. These include:
 
  •  Introduction and Overview section which provides a description of NRG’s business segments;
 
  •  Strategy section;
 
  •  Business Environment section, including how regulation, weather, and other factors affect NRG’s business; and
 
  •  Critical Accounting Policies section.
 
Critical accounting policies are the accounting policies that are most important to the portrayal of NRG’s financial condition and results of operations and require management’s most difficult, subjective or complex judgment. NRG’s critical accounting policies include revenue recognition and derivative accounting, income taxes and valuation allowance for deferred taxes, evaluation of assets for impairment and other than temporary decline in value, goodwill and other intangible assets, and contingencies.
 
This discussion and analysis explains the general financial condition and the results of operations for NRG, including:
 
  •  factors which affect the business;
 
  •  earnings and costs in the periods presented;
 
  •  changes in earnings and costs between periods;
 
  •  sources of earnings;
 
  •  impact of these factors on NRG’s overall financial condition;
 
  •  expected future expenditures for capital projects; and
 
  •  expected sources of cash for further operations and capital expenditures.


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As you read this discussion and analysis, refer to the consolidated statements of income which present the results of operations for the three and nine months ended September 30, 2008 and 2007. NRG analyzes and explains the differences between periods in the specific line items of the consolidated statements of income.
 
NRG has organized the discussion and analysis as follows:
 
  •  changes to the business environment during the period;
 
  •  results of operations beginning with an overview of NRG’s consolidated results, followed by a more detailed discussion of those results by major operating segment;
 
  •  financial condition, addressing liquidity, the sources and uses of cash, capital resources and commitments; and
 
  •  known trends that will affect NRG’s results of operation and financial condition in the future.
 
Changes in Accounting Standards
 
See Note 1 to the condensed consolidated financial statements of this Form 10-Q as found in Item 1 for a discussion of recent accounting developments.
 
Business Environment — Financial Credit Market Availability and Domestic Recessionary Pressures
 
A sharp economic downturn in the US and overseas during the latter part of 2008 was prompted by a combination of factors: tight credit markets, speculation and fear regarding the health of the US and global financial systems, and weaker economic activity in general prompting fears of an economic recession. Power generation companies are capital intensive and, as such, rely on the credit markets for liquidity and for the financing of power generation investments. In addition, economic recessions historically result in lower power demand, power prices, and fuel prices. NRG has a diversified liquidity program, with $3.0 billion in total liquidity, and a first and second lien structure that enables significant strategic hedging while reducing requirements for the posting of cash or letters of credit as collateral. NRG expects to continue to manage commodity price volatility through its strategic hedging program, under which the Company expects to hedge revenues and fuel costs. This program should provide the Company with the flexibility to enter into hedges opportunistically, such as when gas prices are increasing, while at the same time protecting NRG against longer-term volatility in the commodity markets. The Company believes that an economic recession is unlikely to have material impact on the Company’s cash generation in the near term due to the hedged position of its portfolio. NRG transacts with a diversified pool of counterparties and actively manages our exposure to any single counterparty. See Part 1, Item 1 — Liquidity and Capital Resources, and Part 1, Item 3 — Quantitative and Qualitative Disclosures about Market Risk for further discussion.
 
Unsolicited Exelon Proposal
 
On October 19, 2008, NRG received an unsolicited proposal from Exelon Corporation to acquire all of the outstanding shares of NRG at a fixed exchange ratio of 0.485 Exelon shares for each NRG common share. NRG’s Board of Directors is reviewing Exelon’s proposal with their advisors and will determine the appropriate response in due course. As of the date of the filing of this quarterly report, NRG stockholders have been advised to take no action at this time pending the review by NRG’s Board of Directors.
 
Environmental Matters
 
Carbon Update
 
At the national level and at various regional and state levels, policies are under development to regulate GHG emissions, including CO2, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. The Northeast states are furthest along where six of ten participating states held the first CO2 allowances auction on September 25, 2008. The effective start date is January 1, 2009. California under legislation enacted in 2007 known as AB32, the seven states and four Canadian provinces in the Western Climate Initiative, and the six states in the Midwest GHG Accord continue to develop market based programs for their respective jurisdictions. It is almost certain that all GHG regulatory schemes will encompass power plants. The impact on the Company’s financial performance will depend on a number of factors, including the overall level of GHG reductions required under any such regulation, the price and availability of offsets, and the extent to which NRG would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market. Despite current fiscal and economic concerns, Congressional leaders continue to seek an approach to national climate change legislation that will gain the support necessary to become law. In October 2008, Representatives Boucher and Dingell introduced a climate change discussion draft into Congress that, along with basic cap and trade architecture, offers a menu of options for dealing with a number of important details


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such as allocations and factors that could affect allowance price. In addition, the climate change discussion draft continues the trend of all major climate legislation in Congress to provide significant support for low carbon investments such as those involved in the Company’s RepoweringNRG and econrg programs. Information regarding the Company’s carbon strategy is discussed in greater detail in Part I, Item 1, Carbon Update in NRG Energy, Inc.’s 2007 Annual Report on Form 10-K for the fiscal year ended December 31, 2007.
 
On April 2, 2007, the US Supreme Court issued a decision in Massachusetts v. EPA that the USEPA has authority under Title II of the Clean Air Act or CAA to regulate CO2 emissions from new motor vehicles. The actual treatment of CO2 under the CAA is contingent upon an official finding by the USEPA on whether these emissions endanger public health and the environment. While such a finding, based on the Supreme Court decision, would be specific to mobile sources, the outcome would also be applicable to the regulation of stationary sources including electric generating units. On July 30, 2008, the USEPA released an Advance Notice of Proposed Rulemaking, or ANPR, inviting public comment on the benefits and ramifications of regulating GHG emissions under the CAA with comments due to EPA by November 28, 2008. Given this schedule it appears unlikely that there will be any regulation of CO2 under the CAA during the remainder of 2008. At this time, NRG cannot predict the outcome of the ANPR process, any resulting changes to federal regulations, nor the impact on Company operations.
 
Federal Environmental Initiatives
 
On May 18, 2005, the USEPA published the Clean Air Mercury Rule, or CAMR, to permanently cap and reduce mercury emissions from coal-fired power plants. CAMR imposed limits on mercury emissions from new and existing coal-fired plants and created a market-based cap-and-trade program to reduce nationwide emissions of mercury. The rule was challenged by New Jersey and ten other states. On February 8, 2008, the US Court of Appeals for the D.C. Circuit vacated USEPA’s rule delisting coal- and oil-fired electric generating units from regulation under CAA § 112, or the Delisting Rule, and CAMR. Power plant emissions are now subject to Section 112 of the CAA which requires installation of maximum achievable control technology, or MACT, to reduce emissions. The USEPA plans to develop MACT standards and existing power plants will need to provide plans to meet the new requirements. Certain states in which NRG operates coal plants, such as Delaware, Massachusetts and New York, adopted state implementation plans in lieu of the CAMR federal implementation plan and these state rules remain unchanged. Texas and Louisiana adopted the federal CAMR.
 
On May 12, 2005, the USEPA published the market based Clean Air Interstate Rule, or CAIR. This rule applied to 28 eastern states and the District of Columbia, or D.C., and capped both SO2 and NOx emissions from power plants in two phases; 2010 and 2015 for SO2 and 2009 and 2015 for NOx. CAIR applies to some of the Company’s power plants in New York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois, Pennsylvania, Maryland and Texas. On July 11, 2008, the D.C. Circuit Court ruled that CAIR should be vacated in its entirety. The USEPA petitioned for rehearing en banc on September 24, 2008. The D.C. Circuit Court must grant or deny the petition over the next few months after which it will be reheard or the USEPA can appeal for a hearing before the Supreme Court. The Court has not yet stayed the rule leaving January 1, 2009 as the effective date for the CAIR annual and seasonal NOx trading program. NRG’s SO2 and NOx plans are driven primarily by state requirements and consent orders. NRG’s estimate for environmental capital expenditures reflects changes in schedule and design related to the current status of both CAIR and CAMR. The timing and substantive provisions of any ensuing revised or replacement regulations or legislation may alter the composition and rate of spending for environmental retrofits at our facilities.
 
On September 30, 2008, the NRG Texas region held a bank of emissions allowances with a net carrying value of $748 million, consisting of $504 million for SO2 and $244 million for NOx. These are classified as long-term intangible assets and are carried at average cost. The D.C. Circuit Court ruling has resulted in a decline in current SO2 market prices. NRG has estimated its SO2 allowance requirement needed for generation based on the new ruling and evaluated any excess SO2 allowances for potential impairment. Variability in generation assumptions and any ensuing regulations or legislation will alter our assumed rate of excess SO2 allowances. NRG does not expect that CAIR and the D.C. Circuit Court ruling will have a material impact on the carrying value of our excess SO2 allowances.
 
On March 12, 2008, the USEPA strengthened the primary and secondary ground level ozone National Ambient Air Quality Standards, or NAAQS, (eight hour average) from 0.08 ppm to 0.075 ppm. The USEPA plans to finalize ozone non-attainment regions by March 2010 and states would likely submit plans to come into attainment by 2013. The Company is unable to predict with certainty the impact of the states’ future recommendations on NRG’s operations.


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Regional Environmental Initiatives
 
Northeast Region — On December 20, 2005, 10 northeastern states entered into a Memorandum of Understanding, or MOU, to create the Regional Greenhouse Gas Initiative, or RGGI, to establish a cap-and-trade GHG program for electric generators. Electric generating units in participating RGGI states will have to procure one allowance for every US ton of CO2 emitted with true up for 2009-2011 occurring in 2012. NRG units located in Connecticut, Delaware, Maryland, Massachusetts and New York emitted approximately 13 million US tons of CO2 in 2007. NRG believes that to the extent allowance costs will not be fully reflected in wholesale electricity prices, the direct financial impact on the Company is likely to be negative as costs are incurred to secure the necessary RGGI allowances and offsets at auction and in the market.
 
Regulatory Matters
 
As an operator of power plants and a participant in the wholesale markets, NRG is subject to regulation by various federal and state government agencies. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which NRG participates. These wholesale power markets are subject to ongoing legislative and regulatory changes. In some of NRG’s regions, interested parties have advocated for material market design changes, including the elimination of a single clearing price mechanism, as well as proposals to re-regulate the markets or require divestiture by generating companies in order to reduce their market share. The Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on NRG’s business.
 
Northeast Region
 
New England — On July 1, 2008, ISO-NE filed proposed revisions to its market rules tariff addressing the compensation for units needed for reliability purposes after June 1, 2010 (the scheduled date for the implementation of the forward capacity market). These rule changes will impact NRG’s units that have operated pursuant to RMR agreements and that seek to delist in the forward capacity auctions such as Norwalk Power’s units 1 and 2 which submitted a delist bid in the first forward capacity auction. On October 28, 2008, FERC determined that units, such as Norwalk Power’s units, that submitted a dynamic delist bid that was rejected by ISO-NE for reliability reasons should be required to operate at their bid amount, not a cost of service rate, notwithstanding mitigation rules that restricted the ability of the units to submit a higher delist bid. As a result, the Norwalk Power units will be compensated at their delist bid of $5.99/kw-mo. for the first FCM capacity year.
 
On October 20, 2008, Northeast Utilities Service Company, or NU, the parent company of Connecticut Light and Power, filed an application with the Connecticut Siting Council for the Greater Springfield Reliability component of the New England East-West Solution, or NEEWS, transmission project, a significant reinforcement of the 345 kV transmission system. If constructed, the NEEWS line will increase the import capacity into Connecticut by approximately 1,100 MW.
 
New York — On March 7, 2008, FERC issued an order accepting the NYISO’s proposed market reforms to the in-city Installed Capacity, or ICAP, market, with only minor modifications. The NYISO proposal retains the existing ICAP market structure, but imposes additional market power mitigation on the current owners of Consolidated Edison’s divested generation units in New York City (which include NRG’s Arthur Kill and Astoria facilities), who are deemed to be pivotal suppliers. Specifically, the NYISO proposal imposes a new reference price on pivotal suppliers and requires bids to be submitted at or below the reference price. The new reference price is derived from the expected clearing price based upon the intersection of the supply curve and the ICAP Demand Curve if all suppliers bid as price-takers. The NYISO’s proposed reforms became effective March 27, 2008.
 
Texas Region
 
ERCOT has adopted “Texas Nodal Protocols” that will revise the wholesale market design to incorporate locational marginal pricing (in place of the current ERCOT zonal market). Major elements of the Texas Nodal Protocols include the continued capability for bilateral contracting of energy and ancillary services, a financially binding day-ahead market, resource-specific energy and ancillary service bid curves, the direct assignment of all congestion rents, nodal energy prices for resources, aggregation of nodal to zonal energy prices for loads, congestion revenue rights (including pre-assignment for public power entities), and pricing safeguards. The Public Utility Commission of Texas, or PUCT, approved the Texas Nodal Protocols on April 5, 2006, and full implementation of the new market design was scheduled to begin in 2008. On May 20, 2008, ERCOT announced that it would delay the implementation of the Texas Nodal Protocols, and has not provided a new target implementation date.
 
In May 2008, the ERCOT real-time energy market experienced periods of high prices as a result of limited intervals during which two zonal constraints were simultaneously binding, and this congestion was irresolvable through the dispatch of available resources. In response, ERCOT enacted revised protocols, effective June 9, 2008, for addressing such zonal congestion, providing ERCOT with greater authority to manage such congestion through the use of out-of-market mechanisms towards the goal of lowering prices. In addition, on June 17, 2008, ERCOT enacted revisions to its price cap procedures in order to further dampen the volatility and high prices. Thus, it is unlikely that the circumstances contributing to the price spikes of May 2008 will be repeated.


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On July 17, 2008, as part of its determination of Competitive Renewable Energy Zones, or CREZ, the PUCT approved a significant transmission expansion plan to provide for the delivery of approximately 18,500 MW of energy from the western region of Texas, primarily wind generation. The schedule for construction of the transmission upgrades (approximately 2,300 miles of new 345 kV lines and 42 miles of new 138 kV lines) will be determined in subsequent PUCT proceedings. If completed as currently approved, the transmission upgrades and associated wind generation could impact wholesale energy and ancillary service prices in ERCOT. The PUCT issued its written order on August 15, 2008.
 
West Region
 
CAISO has indicated that its Market Redesign and Technology Upgrade, or MRTU, program will not be implemented before February 1, 2009. Significant components of the MRTU include: (i) locational marginal pricing of energy; (ii) a more effective congestion management system; (iii) a day-ahead market; and (iv) an increase to the existing bid caps. NRG considers these market reforms to be a positive development for its assets in the region.
 
On October 22, 2008, FERC issued a definitive order regarding the provision of station power in California. The FERC’s order reaffirmed the right of generators to engage in monthly netting of their station power needs and, further, clarified that local transmission-owning utilities are preempted from imposing state-based charges on such generators. This order should allow the Company to engage in monthly netting and thus avoid buying power at retail for many of its stations and, further, to avoid the other charges that the local transmission-owning utilities have been imposing. The Company is proceeding with preparation of a station power plan for submission to the California Public Utility Commission, or CPUC, and expects to realize savings in operation costs as a result of this order.


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Consolidated Results of Operations