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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, 2009
Commission File Number: 001-15891
NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)
     
Delaware
 
41-1724239
(State or other jurisdiction
 
(I.R.S. Employer
of incorporation or organization)
 
Identification No.)
 
 
 
211 Carnegie Center Princeton, New Jersey
 
08540
(Address of principal executive offices)
 
(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 shorter 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
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 Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
Yes þ   No o
      As of October 28, 2009, there were 256,409,300 shares of common stock outstanding, par value $0.01 per share.
 
 

 


 

TABLE OF CONTENTS
Index
         
 
 
3
 
 
 
4
 
 
 
9
 
 
 
9
 
 
 
61
 
 
 
110
 
 
 
115
 
 
 
116
 
 
 
116
 
 
 
116
 
 
 
116
 
 
 
116
 
 
 
116
 
 
 
117
 
 
 
118
 
 
 
119
 
 EX-10.1.A
 EX-10.1.B
 EX-31.1
 EX-31.2
 EX-31.3
 EX-32
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

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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 of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or 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 Factors Related to NRG Energy, Inc. in Part I, Item 1A, of the Company’s Annual Report on Form 10-K, for the year ended December 31, 2008 and Risk Factors in Part II, Item 1A, of the Quarterly Report on Form 10-Q, for the quarters ended March 31, 2009 and June 30, 2009 including the following:
   
General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;
 
   
Volatile power supply costs and demand for power;
 
   
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 ISOs 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, wind and solar projects;
 
   
NRG’s ability to implement its econrg strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;
 
   
NRG’s ability to implement its FORNRG strategy of increasing the return on invested capital through operational performance improvements and a range of initiatives at plants and corporate offices to reduce costs or generate revenue;
 
   
NRG’s ability to achieve its strategy of regularly returning capital to shareholders; and
 
   
NRG’s ability to successfully integrate and manage any acquired companies.
     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:
     
APB
 
Accounting Principles Board
 
 
 
ASC
 
The FASB Accounting Standards Codification, which the FASB has established as the source of authoritative U.S. GAAP
 
 
 
ASU
 
Accounting Standards Updates – updates to the ASC
 
 
 
Baseload capacity
 
Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
 
 
 
BACT
 
Best Available Control Technology
 
 
 
BTA
 
Best Technology Available
 
 
 
BTU
 
British Thermal Unit
 
 
 
CAA
 
Clean Air Act
 
 
 
CAGR
 
Compound annual growth rate
 
 
 
CAIR
 
Clean Air Interstate Rule
 
 
 
CAISO
 
California Independent System Operator
 
 
 
Capital Allocation Plan
 
Share repurchase program
 
 
 
Capital Allocation Program
 
NRG’s plan of allocating capital between debt reduction, reinvestment in the business, and share repurchases through the Capital Allocation Plan
 
 
 
CDWR
 
California Department of Water Resources
 
 
 
C&I
 
Commercial, industrial and governmental/institutional
 
 
 
CL&P
 
The Connecticut Light & Power Company
 
 
 
CO2
 
Carbon dioxide
 
 
 
CREZ
 
Competitive Renewable Energy Zones
 
 
 
CS
 
Credit Suisse Group
 
 
 
CSF I
 
NRG Common Stock Finance I LLC
 
 
 
CSF II
 
NRG Common Stock Finance II LLC
 
 
 
CSF CAGRs
 
Embedded derivatives within the CSF debt, individually referred to as CSF I CAGR and CSF II CAGR
 
 
 
CSF Debt
 
CSF I and CSF II issued notes and preferred interest, individually referred to as CSF I Debt and CSF II Debt
 
 
 
CSRA
 
Credit Sleeve Reimbursement Agreement with Merrill Lynch in connection with acquisition of Reliant Energy, as hereinafter defined
 
 
 
DNREC
 
Delaware Department of Natural Resources and Environmental Control
 
 
 
DPUC
 
Department of Public Utility Control
 
 
 
EITF
 
Emerging Issues Task Force
 
 
 
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
 
 
 
FERC
 
Federal Energy Regulatory Commission
 
 
 
FSP
 
FASB Staff Position
 
 
 
GHG
 
Greenhouse Gases

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Table of Contents

     
 
 
GLOSSARY OF TERMS (continued)
 
 
 
Heat Rate
 
A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWh’s generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh.
 
 
 
IGCC
 
Integrated Gasification Combined Cycle
 
 
 
IRS
 
Internal Revenue Service
 
 
 
ISO
 
Independent System Operator, also referred to as Regional Transmission Organizations, or RTO
 
 
 
ISO-NE
 
ISO New England Inc.
 
 
 
ITISA
 
Itiquira Energetica S.A.
 
 
 
kV
 
Kilovolts
 
 
 
kW
 
Kilowatts
 
 
 
kWh
 
Kilowatt-hours
 
 
 
LIBOR
 
London Inter-Bank Offer Rate
 
 
 
Licensing Board
 
Atomic Licensing and Safety Board
 
 
 
LTIP
 
Long-Term Incentive Plan
 
 
 
MACT
 
Maximum Achievable Control Technology
 
 
 
Mass
 
Residential and small business
 
 
 
MDPSC
 
Maryland Public Service Commission
 
 
 
Merit Order
 
A term used for the ranking of power stations in order of ascending marginal cost
 
 
 
MIBRAG
 
Mitteldeutsche Braunkohlengesellschaft mbH
 
 
 
MMBtu
 
Million British Thermal Units
 
 
 
MRTU
 
Market Redesign and Technology Upgrade
 
 
 
MVA
 
Megavolt-ampere
 
 
 
MW
 
Megawatts
 
 
 
MWh
 
Saleable megawatt hours net of internal/parasitic load megawatt-hours
 
 
 
MWt
 
Megawatts Thermal
 
 
 
NAAQS
 
National Ambient Air Quality Standards
 
 
 
Net Exposure
 
Counterparty credit exposure to NRG, net of collateral
 
 
 
NINA
 
Nuclear Innovation North America LLC
 
 
 
NOx
 
Nitrogen oxide
 
 
 
NOL
 
Net Operating Loss
 
 
 
NOV
 
Notice of Violation
 
 
 
NPNS
 
Normal Purchase Normal Sale
 
 
 
NRC
 
United States Nuclear Regulatory Commission
 
 
 
NSR
 
New Source Review
 
 
 
NYISO
 
New York Independent System Operator
 
 
 
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

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Table of Contents

     
 
 
GLOSSARY OF TERMS (continued)
 
 
 
PML
 
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
 
 
 
PUCT
 
Public Utility Commission of Texas
 
 
 
Reliant Energy
 
NRG’s retail business in Texas purchased on May 1, 2009, from Reliant Energy, Inc. which is now known as RRI Energy, Inc., or RRI
 
 
 
Repowering
 
Technologies utilized to replace, rebuild, or redevelop 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
 
 
 
REPS
 
Reliant Energy Power Supply, LLC
 
 
 
RERH
 
RERH Holding, LLC and its subsidiaries
 
 
 
Revolving Credit Facility
 
NRG’s $1 billion senior secured revolving credit facility which matures on February 2, 2011
 
 
 
RGGI
 
Regional Greenhouse Gas Initiative
 
 
 
ROIC
 
Return on Invested Capital
 
 
 
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 (as amended)
 
 
 
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 Loan Facility and a $1.3 billion Synthetic Letter of Credit Facility which mature on February 1, 2013, and a $1 billion Revolving Credit Facility, which matures on February 2, 2011
 
 
 
SIFMA
 
Securities Industry and Financial Markets Association
 
 
 
Senior Notes
 
The Company’s $5.4 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, $1.1 billion of 7.375% senior notes due 2017 and $700 million of 8.5% senior notes due 2019
 
 
 
SFAS
 
Statement of Financial Accounting Standards issued by the FASB
 
 
 
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
 
 
 
TANE
 
Toshiba American Nuclear Energy Corporation
 
 
 
TANE Facility
 
NINA’s $500 million credit facility with TANE which matures on February 24, 2012
 
 
 
Term Loan Facility
 
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
 
 
 
Tonnes
 
Metric tonnes, which are units of mass or weight in the metric system each equal to 2,205 lbs and are the global measurement for GHG
 
 
 
U.S.
 
United States of America
 
 
 
U.S. EPA
 
United States Environmental Protection Agency
 
 
 
U.S. GAAP
 
Accounting principles generally accepted in the United States
 
 
 
VaR
 
Value at Risk
 
 
 
WCP
 
WCP (Generation) Holdings, Inc.

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Table of Contents

ACCOUNTING PRONOUNCEMENTS
     The following ASC topics are referenced in this report. In addition, certain U.S. GAAP standards and interpretations were adopted by the Company in 2009 prior to the July 1, 2009, effective date of the ASC, and were subsequently incorporated into one or more ASC topics. Further, certain U.S. GAAP standards were ratified by the FASB in 2009 prior to July 1, 2009, but are not yet effective and have therefore not yet been incorporated into the ASC. This glossary includes the definition of these “legacy” standards and interpretations under the ASC topic or topics which have been, or are expected to be, fully or partially incorporated.
     
ASC 105   ASC-105, Generally Accepted Accounting Principles; incorporates:
    SFAS 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles
     
ASC 270   ASC-270, Interim Reporting; incorporates:
    FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments
     
ASC 275   ASC-275, Risks and Uncertainties, incorporates:
    FSP FAS 142-3, Determination of the Useful Life of Intangible Assets
     
ASC 320   ASC-320, Investments-Debt and Equity Securities; incorporates:
    FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments
     
ASC 323   ASC-323, Investments-Equity Method and Joint Ventures; incorporates:
    EITF 08-6, Equity Method Investment Accounting Considerations
     
ASC 350   ASC-350, Intangibles-Goodwill and Others; incorporates:
    FSP FAS 142-3, Determination of the Useful Life of Intangible Assets
     
ASC 450   ASC-450, Contingencies
     
ASC 470   ASC-470, Debt; incorporates:
    FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)
     
ASC 715   ASC-715, Compensation-Retirement Benefits, incorporates:
    FSP FAS 132 (R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets
     
ASC 718   ASC-718, Compensation-Stock Compensation; incorporates:
    EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock
     
ASC 740   ASC-740, Income Taxes
     
ASC 805   ASC-805, Business Combinations; incorporates:
    SFAS 141(R), Business Combinations
    FSP FAS 141R-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies
     
ASC 810   ASC-810, Consolidation; incorporates:
    SFAS 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51, Consolidate Financial Statements
 
  Expected to incorporate SFAS 167, Amendments to FASB Interpretations No. 46 (R), effective January 1, 2010
     
ASC 815   ASC-815, Derivatives and Hedging; incorporates:
    SFAS 161, Disclosures About Derivative Instruments and Hedging Activities
 
    EITF 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock
     
ASC 820   ASC-820, Fair Value Measurements and Disclosures; incorporates:
 
    FSP FAS 157-2, Effective Date of FASB Statement No. 157
 
    FSP FAS 157-4 Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

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EITF 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement
     
ASC 825
 
ASC-825, Financial Instruments; incorporates:
   
FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)
   
FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments
     
ASC 855
 
ASC-855, Subsequent Events; incorporates:
   
SFAS 165, Subsequent Events
     
ASU 2009-5
 
ASU 2009-5, Fair Value Measurement and Disclosures: Measuring Liabilities at Fair Value
 
 
 
ASU 2009-15
 
ASU 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing; incorporates:
   
EITF 09-1, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing

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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)
  2009     2008     2009     2008  
 
Operating Revenues
                               
Total operating revenues
  $ 2,916     $ 2,612     $ 6,811     $ 5,230  
 
Operating Costs and Expenses
                               
Cost of operations
    1,893       997       3,901       2,812  
Depreciation and amortization
    212       156       594       478  
Selling, general and administrative
    182       75       396       233  
Acquisition-related transaction and integration costs
    6             41        
Development costs
    12       13       34       29  
 
Total operating costs and expenses
    2,305       1,241       4,966       3,552  
Operating Income
    611       1,371       1,845       1,678  
 
Other Income/(Expense)
                               
Equity in earnings of unconsolidated affiliates
    6       58       33       35  
Gain on sale of equity method investment
                128        
Other income/(loss), net
    5       (7 )     (9 )     14  
Interest expense
    (178 )     (142 )     (475 )     (442 )
 
Total other expense
    (167 )     (91 )     (323 )     (393 )
 
Income From Continuing Operations Before Income Taxes
    444       1,280       1,522       1,285  
Income tax expense
    166       502       614       503  
 
Income From Continuing Operations
    278       778       908       782  
Income from discontinued operations, net of income taxes
                      172  
 
Net Income
    278       778       908       954  
Less: Net loss attributable to noncontrolling interest
                (1 )      
 
Net income attributable to NRG Energy, Inc.
    278       778       909       954  
 
Dividends for preferred shares
    6       13       27       41  
 
Income Available for NRG Energy, Inc. Common Stockholders
  $ 272     $ 765     $ 882     $ 913  
 
Earnings per share attributable to NRG Energy, Inc.
                               
Common Stockholders
                               
Weighted average number of common shares outstanding — basic
    249       235       247       236  
Income from continuing operations per weighted average common share — basic
  $ 1.09     $ 3.26     $ 3.58     $ 3.14  
Income from discontinued operations per weighted average common share — basic
                      0.73  
 
Net Income per Weighted Average Common Share — Basic
  $ 1.09     $ 3.26     $ 3.58     $ 3.87  
 
Weighted average number of common shares outstanding — diluted
    272       277       274       278  
Income from continuing operations per weighted average common share — diluted
  $ 1.02     $ 2.81     $ 3.29     $ 2.79  
Income from discontinued operations per weighted average common share — diluted
                      0.62  
 
Net Income per Weighted Average Common Share — Diluted
  $ 1.02     $ 2.81     $ 3.29     $ 3.41  
 
Amounts attributable to NRG Energy, Inc.:
                               
Income from continuing operations, net of income taxes
  $ 278     $ 778     $ 909     $ 782  
Income from discontinued operations, net of income taxes
                      172  
 
Net Income
  $ 278     $ 778     $ 909     $ 954  
 
See notes to condensed consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
                 
      September 30, 2009        December 31, 2008     
(In millions, except shares)
  (unaudited)        
 
ASSETS
               
Current Assets
               
Cash and cash equivalents
    $ 2,250       $ 1,494  
Funds deposited by counterparties
    293       754  
Restricted cash
    26       16  
Accounts receivable, less allowance for doubtful accounts of $40 and $3, respectively
    1,119       464  
Inventory
    533       455  
Derivative instruments valuation
    3,199       4,600  
Deferred income taxes
    101        
Cash collateral paid in support of energy risk management activities
    475       494  
Prepayments and other current assets
    215       215  
 
Total current assets
    8,211       8,492  
 
Property, plant and equipment, net of accumulated depreciation of $2,876 and $2,343, respectively
    11,610       11,545  
 
Other Assets
               
Equity investments in affiliates
    392       490  
Capital leases and note receivable, less current portion
    507       435  
Goodwill
    1,718       1,718  
Intangible assets, net of accumulated amortization of $483 and $335, respectively
    1,942       815  
Nuclear decommissioning trust fund
    354       303  
Derivative instruments valuation
    1,039       885  
Other non-current assets
    181       125  
 
Total other assets
    6,133       4,771  
 
Total Assets
    $ 25,954       $ 24,808  
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current Liabilities
               
Current portion of long-term debt and capital leases
    $ 537       $ 464  
Accounts payable
    725       451  
Derivative instruments valuation
    3,017       3,981  
Deferred income taxes
          201  
Cash collateral received in support of energy risk management activities
    293       760  
Accrued expenses and other current liabilities
    636       724  
 
Total current liabilities
    5,208       6,581  
 
Other Liabilities
               
Long-term debt and capital leases
    8,229       7,697  
Nuclear decommissioning reserve
    296       284  
Nuclear decommissioning trust liability
    249       218  
Deferred income taxes
    1,572       1,190  
Derivative instruments valuation
    859       508  
Out-of-market contracts
    324       291  
Other non-current liabilities
    1,138       669  
 
Total non-current liabilities
    12,667       10,857  
 
Total Liabilities
    17,875       17,438  
 
3.625% convertible perpetual preferred stock
    247       247  
Commitments and Contingencies
               
Stockholders’ Equity
               
Preferred stock
    406       853  
Common stock
    3       3  
Additional paid-in capital
    4,568       4,350  
Retained earnings
    3,305       2,423  
Less treasury stock, at cost — 26,080,051 and 29,242,483 shares, respectively
    (782 )     (823 )
Accumulated other comprehensive income
    320       310  
Noncontrolling interest
    12       7  
 
Total Stockholders’ Equity
    7,832       7,123  
 
Total Liabilities and Stockholders’ Equity
    $ 25,954       $ 24,808  
 
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,
  2009     2008  
 
Cash Flows from Operating Activities
               
Net income
  $   908     $   954  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Distributions and equity in earnings of unconsolidated affiliates
    (33 )     (24 )
Depreciation and amortization
    594       478  
Provision for bad debts
    37        
Amortization of nuclear fuel
    28       31  
Amortization of financing costs and debt discount/premiums
    35       28  
Amortization of intangibles and out-of-market contracts
    79       (226 )
Changes in deferred income taxes and liability for unrecognized tax benefits
    561       439  
Changes in nuclear decommissioning trust liability
    19       8  
Changes in derivatives
    (234 )     (144 )
Changes in collateral deposits supporting energy risk management activities
    13       (320 )
Loss on sale of assets
    2       13  
Gain on sale of equity method investment
    (128 )      
Gain on sale of discontinued operations
          (273 )
Gain on sale of emission allowances
    (8 )     (52 )
Gain recognized on settlement of pre-existing relationship
    (31 )      
Amortization of unearned equity compensation
    20       21  
Changes in option premiums collected
    (278 )     203  
Cash used by changes in other working capital
    (304 )     (50 )
 
Net Cash Provided by Operating Activities
    1,280       1,086  
 
Cash Flows from Investing Activities
               
Acquisition of Reliant Energy, net of cash acquired
    (356 )      
Capital expenditures
    (560 )     (649 )
Increase in restricted cash, net
    (10 )     (3 )
(Increase)/decrease in notes receivable
    (18 )     20  
Purchases of emission allowances
    (68 )     (6 )
Proceeds from sale of emission allowances
    20       75  
Investments in nuclear decommissioning trust fund securities
    (237 )     (441 )
Proceeds from sales of nuclear decommissioning trust fund securities
    218       434  
Proceeds from sale of discontinued operations, net of cash divested
          241  
Proceeds from sale of assets, net
    6       14  
Proceeds from sale of equity method investment
    284        
Equity investment in unconsolidated affiliate
          (17 )
Other investments
    (6 )      
 
Net Cash Used by Investing Activities
    (727 )     (332 )
 
Cash Flows from Financing Activities
               
Payment of dividends to preferred stockholders
    (27 )     (41 )
Net payments to settle acquired derivatives that include financing elements
    (140 )     (49 )
Payment to settle CSF I CAGR
          (45 )
Payment for treasury stock
    (250 )     (185 )
Proceeds from issuance of common stock, net of issuance costs
    1       8  
Installment proceeds from sale of noncontrolling interest in subsidiary
    50       50  
Proceeds from issuance of long-term debt
    843       20  
Payment of deferred debt issuance costs
    (29 )     (2 )
Payments for short and long-term debt
    (248 )     (202 )
 
Net Cash Provided by/(Used by) Financing Activities
    200       (446 )
 
Change in cash from discontinued operations
          43  
Effect of exchange rate changes on cash and cash equivalents
    3        
 
Net Increase in Cash and Cash Equivalents
    756       351  
Cash and Cash Equivalents at Beginning of Period
    1,494       1,132  
 
Cash and Cash Equivalents at End of Period
  $   2,250     $   1,483  
 
See notes to condensed consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 — Basis of Presentation
     NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company with a significant presence in major competitive power markets in the United States, as well as a major retail electricity franchise in the ERCOT (Texas) market. NRG is engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, the trading of energy, capacity and related products in the United States and select international markets, and supply of electricity and energy services to retail electricity customers in the Texas market.
     The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the U.S. Securities and Exchange Commission’s, or 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 following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2008. Interim results are not necessarily indicative of results for a full year.
     In the opinion of management, the accompanying unaudited interim condensed 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, 2009, the results of operations for the three and nine months ended September 30, 2009, and 2008, and cash flows for the nine months ended September 30, 2009, and 2008. These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through November 2, 2009, the date the financial statements were issued.
     Certain prior-year amounts have been reclassified for comparative purposes. In addition, as disclosed in Note 27, Unaudited Quarterly Financial Data, to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, the results of operations for the three months ended September 30, 2008, have been revised to reflect the correction of a $78 million overstatement of revenues from an error in the accounting for energy options. The effect of the revision on the three and nine months ended September 30, 2008 from the Company’s previously filed Form 10-Q, as adjusted for the effect of the adoption of FSP APB 14-1 (as discussed in Note 2, Summary of Significant Accounting Policies), is summarized as follows:
         
(In millions, except per share amounts)
  Adjustment
 
Increase/(decrease):
       
Operating revenues
  $ (78 )
Operating income
    (78 )
Income tax expense
    28  
Income/(losses) from continuing operations, net of income taxes
    (50 )
Net income attributable to NRG Energy, Inc.
  $ (50 )
Income/(losses) from continuing operations per weighted average common share — basic
  $ (0.21 )
Net income per weighted average common share — basic
  $ (0.21 )
Income/(losses) from continuing operations per weighted average common share — diluted
  $ (0.18 )
Net income per weighted average common share — diluted
  $ (0.18 )
 

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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.
Note 2 — Summary of Significant Accounting Policies
Cash and Cash Equivalents
     Cash and cash equivalents at September 30, 2009, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.
Other Cash Flow Information
     NRG’s investing activities do not include non-cash capital expenditures of $43 million which were accrued at September 30, 2009.
Recent Accounting Developments
     SFAS 168 — In June 2009, the Financial Accounting Standards Board, or FASB, issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, or SFAS 168. Effective July 1, 2009, this guidance establishes the FASB Accounting Standards Codification, or ASC, as the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. In addition, SFAS 168 also specifies that rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. All guidance contained in the ASC carries an equal level of authority. The Company adopted SFAS 168 for the quarterly reporting period ending September 30, 2009. SFAS 168 has been incorporated into the ASC as ASC-105, Generally Accepted Accounting Principles, or ASC 105.
     Certain U.S. GAAP standards and interpretations were adopted by the Company in 2009 prior to the July 1, 2009, effective date of the ASC, and were subsequently incorporated into one or more ASC topics. Further, certain U.S. GAAP standards were ratified by the FASB in 2009 prior to July 1, 2009, but are not yet effective and have therefore not yet been incorporated into the ASC. This report retains the original title of these standards and interpretations, and references the ASC topic or topics which have been, or are expected to be, incorporated.
     SFAS 141R — The Company adopted SFAS No. 141 (revised 2007), Business Combinations, or SFAS 141R, on January 1, 2009. The provisions of SFAS 141R are applied prospectively to business combinations for which the acquisition date occurs after January 1, 2009. 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. In addition, transaction costs are required to be expensed as incurred. As discussed in Note 4, Business Acquisition, to this Form 10-Q, on May 1, 2009, NRG acquired all of the Texas electric retail business operations, or Reliant Energy, of Reliant Energy, Inc., now known as RRI Energy, Inc., or RRI. The Company has applied the provisions of SFAS 141R to the Reliant Energy acquisition. As discussed further in Note 13, Income Taxes, any reductions after January 1, 2009, to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, as they relate to Fresh Start or previously completed acquisitions, will be recorded to income tax expense rather than additional paid-in capital or goodwill. SFAS 141R has been incorporated into ASC-805, Business Combinations, or ASC 805.
     FSP FAS 141R-1 — In April 2009, the FASB issued FSP No. FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, or FSP FAS 141R-1, which the Company adopted effective January 1, 2009. This FSP amends and clarifies SFAS 141R, to address application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The provisions of FSP FAS 141R-1 are applied prospectively to assets or liabilities arising from contingencies in business combinations for which the acquisition date occurs after January 1, 2009. Accordingly, the Company has applied the provisions of FSP FAS 141R-1 to the Reliant Energy acquisition. The provisions of FSP FAS 141R-1 have been incorporated into ASC 805.

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     SFAS 160 — The Company adopted SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51, Consolidated Financial Statements, or SFAS 160, on January 1, 2009. SFAS 160 establishes 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 is applied prospectively from the date of adoption, except for the presentation and disclosure requirements, which shall be applied retrospectively. Accordingly, the Company has conformed its financial statement presentation and disclosures to the requirements of SFAS 160. SFAS 160 has been incorporated into ASC-810, Consolidation, or ASC 810.
     FSP APB 14-1 — The Company adopted 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, on January 1, 2009, applying it retrospectively to all periods presented. FSP APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) should separately account for the liability component and the equity component represented by the embedded conversion option in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. Upon settlement, the entity shall allocate consideration transferred and transaction costs incurred to the extinguishment of the liability component and the reacquisition of the equity component. The provisions of FSP APB 14-1 have been incorporated into ASC-470, Debt, or ASC 470, and ASC-825, Financial Instruments, or ASC 825.
     During the third quarter 2006, NRG’s unrestricted wholly-owned subsidiaries CSF I and CSF II issued notes and preferred interests, or CSF Debt, which included embedded derivatives, or CSF CAGRs, requiring NRG to pay to Credit Suisse Group, or CS, at maturity, either in cash or stock at NRG’s option, the excess of NRG’s then current stock price over a threshold price. The CSF Debt and CSF CAGRs are accounted for under the guidance in ASC 470. Upon adoption of FSP APB 14-1, the fair value of the CSF CAGRs at the date of issuance was determined to be $32 million and has been recorded as a debt discount to the CSF Debt, with a corresponding credit to Additional Paid-in Capital. This debt discount will be amortized over the terms of the underlying CSF Debt. The cumulative effect of the change in accounting principle for periods prior to December 31, 2008, was recorded as a $7 million decrease to Long-Term Debt, a $13 million decrease to Additional Paid-In Capital, and a $20 million increase to Retained Earnings on the Condensed Consolidated Balance Sheet as of December 31, 2008. In addition, in August 2008 the Company paid $45 million to CS for the benefit of CSF I to early settle the CSF CAGR in the Company’s CSF I notes and preferred interests, which was reclassified from interest expense to Additional Paid-In Capital upon the adoption of FSP APB 14-1.
     The following table summarizes the effect of the adoption of FSP APB 14-1 on income and per-share amounts for all periods presented:
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
(In millions, except per share amounts)   2009     2008     2009     2008  
 
Increase/(decrease):
                               
Interest Expense
  $ 2     $ (44 )   $ 5     $ (39 )
Income From Continuing Operations
    (2 )     44       (5 )     39  
Net Income attributable to NRG Energy, Inc.
    (2 )     44       (5 )     39  
Basic Earnings Per Share
  $ (0.01 )   $ 0.19     $ (0.02 )   $ 0.16  
Diluted Earnings Per Share
  $     $ 0.16     $ (0.02 )   $ 0.14  
 
     FSP FAS 157-4 — In April 2009, the FASB issued FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, or FSP FAS 157-4. FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with ASC-820, Fair Value Measurements and Disclosure, or ASC 820, when the volume and level of activity for the asset or liability have significantly decreased, includes guidance on identifying circumstances that indicate a transaction is not orderly, and requires disclosures about inputs and valuation techniques used to measure fair value. This FSP applies to all assets and liabilities within the scope of accounting pronouncements that require or permit fair value measurements. FSP FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009, and is applied prospectively. The Company’s adoption of FSP FAS 157-4 beginning with the interim reporting period ended June 30, 2009, did not have a material impact on the Company’s results of operations, financial position, or cash flows. The provisions of FSP FAS 157-4 have been incorporated into ASC 820.

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     FSP FAS 107-1 and APB 28-1 — In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, or FSP 107-1 and APB 28-1. This FSP requires disclosures about fair value of financial instruments for interim and annual reporting periods of publicly traded companies ending after the FSP’s effective date of June 15, 2009. The Company’s adoption of FSP FAS 107-1 and APB 28-1 beginning with the interim period ended June 30, 2009, did not have an impact on the Company’s results of operations, financial position, or cash flows. The provisions of FSP FAS 107-1 and APB 28-1 have been incorporated in ASC-270, Interim Reporting, or ASC 270, and ASC-825, Financial Instruments, or ASC 825.
     FSP FAS 115-2 and FAS 124-2 — In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, or FSP FAS 115-2 and FAS 124-2. This FSP amends the other-than-temporary impairment guidance in U.S. GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This FSP does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. FSP FAS 115-2 and FAS 124-2 is effective for interim and annual reporting periods ending after June 15, 2009, and its disclosure requirements apply only to periods ending after the FSP’s effective date. The Company’s adoption of FSP FAS 115-2 and FAS 124-2 beginning with the interim period ended June 30, 2009, did not have an impact on the Company’s results of operations, financial position, or cash flows. The provisions of FSP FAS 115-2 and FAS 124-2 have been incorporated in ASC-320, Investments — Debt and Equity Securities, or ASC 320.
     SFAS 165 — In May 2009, the FASB issued SFAS No. 165, Subsequent Events, or SFAS 165. SFAS 165 incorporates the accounting and disclosure requirements related to subsequent events found in auditing standards into U.S. GAAP, effectively making management directly responsible for subsequent events accounting and disclosures. SFAS 165 also requires disclosure of the date through which subsequent events have been evaluated. SFAS 165 is effective for interim and annual reporting periods ending after June 15, 2009, and shall be applied prospectively. The Company’s adoption of SFAS 165 beginning with the interim period ended June 30, 2009, did not have an impact on the Company’s results of operations, financial position, or cash flows. SFAS 165 has been incorporated in ASC-855, Subsequent Events, or ASC 855.
     SFAS 167 — In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R), or SFAS 167. This guidance amends FIN 46(R) by altering how a company determines when an entity that is insufficiently capitalized or not controlled through voting should be consolidated. SFAS 167 is effective at the start of the first fiscal year beginning after November 15, 2009. The Company is presently evaluating the impact of SFAS 167 on its results of operations, financial position, and cash flows. SFAS 167 is expected be incorporated into ASC 810 upon its effective date.
     ASU 2009-15/EITF 09-1 — In July 2009, the FASB ratified EITF Issue No. 09-1, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, or EITF 09-1. This Issue applies to equity-classified share lending arrangements on an entity’s own shares, when executed in contemplation of a convertible debt offering or other financing. EITF 09-1 addresses how to account for the share-lending arrangement and the effect, if any, that the loaned shares have on earnings-per-share calculations. The share lending arrangement is required to be measured at fair value and recognized as an issuance cost associated with the convertible debt offering or other financing. Earnings-per-share calculations would not be affected by the loaned shares unless the share borrower defaults on the arrangement and does not return the shares. If counterparty default is probable, the share lender is required to recognize an expense equal to the then fair value of the unreturned shares, net of the fair value of probable recoveries. The Company will apply EITF 09-1 for share lending agreements entered into after June 15, 2009, and will apply EITF 09-1 on a retrospective basis for arrangements outstanding as of January 1, 2010. 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 October 2009, the FASB issued Accounting Standards Update, or ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, or ASU 2009-15, which formally incorporated the provisions of EITF 09-1 into ASC 470.
     ASU 2009-5 — In August 2009, the FASB issued ASU No. 2009-05, Fair Value Measurement and Disclosures: Measuring Liabilities at Fair Value, or ASU 2009-5. This ASU, which amends ASC 820 and ASC 825, provides clarification on measuring liabilities at fair value when a quoted price in an active market is not available. The Company’s adoption of ASU 2009-5 beginning with the interim period ended September 30, 2009, did not have an impact on the Company’s results of operations, financial position or cash flows.

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     Other — The following accounting standards were adopted on January 1, 2009, with no impact on the Company’s results of operations, financial position, or cash flows:
    FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets, which has been incorporated in ASC-275, Risks and Uncertainties, or ASC 275, and ASC-350, Intangibles — Goodwill and Other, or ASC 350.
 
    FSP No. FAS 157-2, Effective Date of FASB Statement No. 157, which has been incorporated in ASC 820.
 
    SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities, which has been incorporated in ASC-815, Derivatives and Hedging, or ASC 815.
 
    FSP No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets, which has been incorporated in ASC-715, Compensation–Retirement Benefits, or ASC 715.
 
    EITF No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock, which has been incorporated in ASC 718, Compensation-Equity Compensation, or ASC 718, and ASC 815.
 
    EITF No. 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement, which has been incorporated in ASC 820.
 
    EITF No. 08-6, Equity Method Investment Accounting Considerations, which has been incorporated in ASC-323, Investments-Equity Method and Joint Ventures, or ASC 323.
Note 3 — Comprehensive Income/(Loss)
     The following table summarizes the components of the Company’s comprehensive income/(loss), net of tax:
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
(In millions)   2009     2008     2009     2008  
 
Net income
  $ 278     $ 778     $ 908     $ 954  
 
Changes in derivative activity
    (73 )     1,112       (9 )     112  
Foreign currency translation adjustment
    20       (104 )     38       (69 )
Reclassification adjustment for translation loss/(gain) realized upon sale of foreign investments
                (22 )     15  
Unrealized gain/(loss) on available-for-sale securities
    1       (4 )     3       (1 )
 
Other comprehensive income/(loss)
    (52 )     1,004       10       57  
Comprehensive income attributable to noncontrolling interest
                1        
 
Comprehensive income attributable to NRG Energy, Inc.
  $ 226     $ 1,782     $ 919     $ 1,011  
 
     The following table summarizes the changes in the Company’s accumulated other comprehensive income, net of tax:
         
(In millions)        
 
Accumulated other comprehensive income as of December 31, 2008
  $ 310  
Changes in derivative activity
    (9 )
Foreign currency translation adjustment
    38  
Reclassification adjustment for translation gain realized upon sale of foreign investment
    (22 )
Unrealized gain on available-for-sale securities
    3  
 
Accumulated other comprehensive income as of September 30, 2009
  $ 320  
 

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Note 4 — Business Acquisition
General
     On May 1, 2009, NRG, through its wholly-owned subsidiary NRG Retail LLC, acquired Reliant Energy, which consisted of the entire Texas electric retail business operations of RRI, including the exclusive use of the trade name “Reliant.” Reliant Energy arranges for the transmission and delivery of electricity to customers, bills customers, collects payments for electricity sold and maintains call centers to provide customer service. Reliant Energy is the second largest electricity provider to residential and small business, or Mass, customers in Texas, with approximately 1.6 million Mass customers as of September 30, 2009. Reliant Energy also sells electricity and energy services to commercial, industrial and governmental/institutional customers, or C&I, customers in Texas with approximately 0.1 million C&I customers, based on metered locations as of September 30, 2009. These customers include refineries, chemical plants, manufacturing facilities, hospitals, universities, government agencies, restaurants, and other facilities.
     With its complementary generation portfolio, the Texas region is a supplier of power to Reliant Energy, thereby creating the potential for a more stable, reliable and competitive business that benefits Texas consumers. By backing Reliant Energy’s load-serving requirements with NRG’s generation and risk management practices, the need to sell and buy power from other financial institutions and intermediaries that trade in the ERCOT market may be reduced, resulting in reduced transaction costs and credit exposures. This combination of generation and retail allows for a reduction in actual and contingent collateral, initially through offsetting transactions and over time by reducing the need to hedge the retail power supply through third parties, thus reducing collateral postings. In addition, with Reliant Energy’s base of retail customers, NRG now has a customer interface with the scale that is important to the successful deployment of new distributed generation and retail alternative energy technologies.
Credit Support
     On May 1, 2009, NRG arranged with Merrill Lynch Commodities, Inc. and certain of its affiliates, or Merrill Lynch, the former credit provider of RRI Energy, Inc., or RRI, to provide continuing credit support to Reliant Energy after closing the acquisition. In connection with entering into a transitional credit sleeve facility, or CSRA, NRG contributed $200 million of cash to Reliant Energy. In conjunction with the CSRA, NRG Power Marketing LLC, or PML, and Reliant Energy Power Supply LLC, or REPS, wholly-owned subsidiaries of NRG, modified or novated certain transactions with counterparties to transfer PML’s in-the-money transactions to REPS and moved $522 million of cash collateral held by NRG to Merrill Lynch, thereby reducing Merrill Lynch’s actual and contingent collateral supporting Reliant Energy out-of-money positions. At September 30, 2009, these trades with counterparties were still open, thus there was no impact on NRG’s consolidated financial statements, and NRG continued to record unrealized and realized gains/losses for these novated trades in its Texas and Northeast segments. The monthly fee for the CSRA was 5.875% on an annualized basis of the predetermined exposure.
     Additionally, on May 1, 2009, NRG entered into a $50 million working capital facility with Merrill Lynch in connection with the acquisition of Reliant Energy. The facility required that the Company comply with all terms of the CSRA. NRG initially drew $25 million under the facility. These funds accrued interest at the prime rate.
     Reliant Energy conducts its business through RERH Holdings, LLC and subsidiaries, or RERH, Reliant Energy Texas Retail, LLC, and Reliant Energy Services Texas, LLC. Through October 5, 2009, the obligations of Reliant Energy under the CSRA were secured by first liens on substantially all of the assets of RERH, and the obligations of RERH under the CSRA were non-recourse to NRG and its other non-pledgor subsidiaries. The CSRA agreement (a) restricted the ability of RERH to, among other actions, (i) encumber its assets; (ii) sell certain assets; (iii) incur additional debt; (iv) pay dividends or pay subordinated debt; (v) make investments or acquisitions; or (vi) enter into certain transactions with affiliates and (b) required NRG to manage risks related to commodity prices. RERH was designed to maintain the separate nature of its assets in order to ensure that such assets are available first and foremost to satisfy the entities’ creditor claims. At September 30, 2009, the cash balance at RERH was $322 million.
     Effective October 5, 2009, as discussed in Note 20, Subsequent Event, to this Form 10-Q, the Company executed the CSRA Amendment resulting in the removal of the associated first liens and the termination of the $50 million working capital facility with Merrill Lynch.

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   Acquisition method of accounting
     The acquisition of Reliant Energy is accounted for under the acquisition method of accounting in accordance with ASC-805. Accordingly, NRG has conducted an assessment of net assets acquired and has recognized provisional amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition are expensed as incurred. The initial accounting for the business combination is not complete because the appraisals necessary to assess the fair values of the net assets acquired and the amount of goodwill (if any) to be recognized are still in process, and the Company is also in the process of valuing the tax basis of the net assets acquired, which will affect the deferred tax balances. The provisional amounts recognized are subject to revision until the appraisals are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments and the tax basis values will affect the final balance of goodwill.
     NRG paid RRI $287.5 million in cash at closing, funded from NRG’s cash on hand. NRG also made payments to RRI of $63 million on June 15, 2009, and $11 million on July 24, 2009, as initial remittances of acquired net working capital. In addition, the Company expects to remit approximately $9 million of acquired net working capital to RRI in the fourth quarter of 2009, bringing the total cash consideration to approximately $370 million. NRG also recognized a $31 million non-cash gain on the settlement of a pre-existing relationship, representing the in-the-money value to NRG of an agreement that permits Reliant Energy to call on certain NRG gas plants when necessary for Reliant Energy to meet its load obligations. NRG has recorded this gain within “Operating Revenues” in its condensed consolidated statement of operations. This non-cash gain is considered a component of consideration in accordance with ASC 805, and together with cash consideration, brings total consideration to approximately $401 million.
     The following table summarizes the provisional values assigned to the net assets acquired, including cash acquired of $6 million, as of the acquisition date:
         
(In millions)        
 
Assets
       
Current and non-current assets
  $ 635  
Property, plant and equipment
    72  
Intangible assets subject to amortization:
       
In-market customer contracts
    790  
Customer relationships
    399  
Trade names
    178  
In-market energy supply contracts
    54  
Other
    6  
Derivative assets
    1,942  
Deferred tax asset, net
    14  
Goodwill
     
 
Total assets acquired
    4,090  
 
Liabilities
       
Current and non-current liabilities
    550  
Derivative liabilities
    2,996  
Out-of-market energy supply and customer contracts
    143  
 
Total liabilities assumed
    3,689  
 
Net assets acquired
  $ 401  
 
     No goodwill is expected to be deductible for tax purposes.
     Current assets include accounts receivable with a preliminary fair value of $569 million and gross contractual amounts of $589 million at the time of acquisition. The Company expects to collect the fair value of the contractual cash flows; any difference between fair value and the amount collected will be an adjustment to the acquired working capital payment due to RRI.
     The Company, through its acquisition of Reliant Energy, is subject to material contingencies relating to Excess Mitigation Credits (see Note 15, Commitments and Contingencies, to this Form 10-Q) and Retail Replacement Reserve (see Note 16, Regulatory Matters, to this Form 10-Q). Due to the number of variables and assumptions involved in assessing the possible outcome of these matters, sufficient information does not exist to reasonably estimate the fair value of these contingent liabilities. These material contingencies have been evaluated in accordance with ASC-450, Contingencies, or ASC 450, and related guidance, and no provisional amounts for these matters have been recorded at the acquisition date. In addition, NRG provided certain indemnities in connection with the acquisition. See Note 18, Guarantees, to this Form 10-Q for further discussion.

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Measurement period adjustments
     The following measurement period adjustments to the provisional amounts, attributable to refinement of the underlying appraisal assumptions, were recognized during the quarter ended September 30, 2009:
         
(In millions)   Increase/(Decrease)
 
Assets
       
Intangible assets subject to amortization:
       
In-market customer contracts
  $ 57  
Customer relationships
    (82 )
In-market energy supply contracts
    17  
Deferred tax asset, net
    3  
 
Total assets acquired
    (5 )
 
Liabilities
       
Out-of-market energy supply and customer contracts
    (5 )
 
Total liabilities assumed
    (5 )
 
Net assets acquired
  $  
 
Fair value measurements
     The provisional fair values of the intangible assets/liabilities and property, plant and equipment at the acquisition date were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. Significant inputs were as follows:
   
Customer contracts — The fair values of the customer contracts, representing those with Reliant Energy’s C&I customers, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on contract type, discounted utilizing a current market interest rate consistent with the overall credit quality of the portfolio. The fair values also accounted for Reliant Energy’s historical costs to acquire customers. The above/below market cash flows were estimated by comparing the expected cash flows to be generated based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market costs, such as price of energy, transmission and distribution costs, and miscellaneous fees, plus a normal profit margin. The customer contracts are amortized to revenues, over a weighted average amortization period of five years, based on expected volumes to be delivered for the portfolio.
 
   
Customer relationships — The customer relationships, reflective of Reliant Energy’s Mass customer base, were valued using a variation of the income approach. Under this approach, the Company estimated the present value of expected future cash flows resulting from the existing customer relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, software, workforce and trade names) utilized in the business, discounted at an independent power producer peer group’s weighted average cost of capital. The customer relationships are amortized to depreciation and amortization, over a weighted average amortization period of eight years, based on the expected discounted future net cash flows by year.
 
   
Trade names — The trade names were valued using a “relief from royalty” method, an approach under which fair value is estimated to be the present value of royalties saved because NRG owns the intangible asset and therefore does not have to pay a royalty for its use. The trade names were valued in two parts based on Reliant Energy’s two primary customer segments — Mass customers and C&I customers. The avoided royalty revenues were discounted at an independent power producer peer group’s weighted average cost of capital. The remaining useful life of the trade names was determined by considering various factors, such as turnover and name changes in the independent power producer and utility industries, the current age of the Reliant brand, management’s intent to continue using the name at the current time, and feedback from external consultants regarding their experience with similar trade names. The trade names are amortized to depreciation and amortization, on a straight-line basis, over 15 years.
 
   
Energy supply contracts — The fair values of the in-market and out-of-market energy supply contracts were determined in accordance with ASC 820. These contracts are amortized over periods ranging through 2016, based on the expected delivery under the respective contracts.

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Property, plant and equipment — The fair value of property, plant and equipment was valued using a cost approach, which estimates value by determining the current cost of replacing an asset with another of equivalent economic utility. The cost to replace a given asset reflects the estimated reproduction or replacement cost for the property, less an allowance for loss in value due to depreciation.
     The fair values of derivative assets and liabilities as of the acquisition date were determined in accordance with ASC 820. The breakdown of Level 1, 2 and 3 is as follows:
                                 
    Fair Value
(In millions)   Level 1     Level 2     Level 3     Total  
 
Derivative assets
    $ 534     $ 1,375     $ 33     $   1,942  
 
Derivative liabilities
    $ 534     $ 2,357     $ 105     $   2,996  
 
Amortization of acquired intangible assets and out-of-market contracts
     The following table presents the estimated remaining amortization related to the acquired intangible assets, for periods subsequent to September 30, 2009 and through 2014:
                                 
Year Ended December 31,   Customer   Customer   Trade   Energy Supply  
(In millions)   Contracts   Relationships   Names   Contracts
 
2009 (three months)
  $ 99     $ 44     $ 3     $  
2010
    225       81       12       3  
2011
    152       57       12       4  
2012
    104       44       12       5  
2013
    49       31       12       6  
2014
          24       12       6  
 
     The following table presents the estimated amortization related to the acquired out-of-market contracts for 2009 — 2014:
         
       Energy Supply   
Year Ended December 31,   and Customer
(In millions)   Contracts
 
2009 (three months)
  $   23  
2010
    48  
2011
    18  
2012
    7  
2013
    3  
2014
     
 
     These amortization tables reflect the measurement period adjustments recognized during the quarter ended September 30, 2009.
Supplemental Pro Forma Information
     Since the acquisition date, Reliant Energy contributed $2,965 million of operating revenues and $807 million in net income attributable to NRG.
     The following supplemental pro forma information represents the results of operations as if NRG and Reliant Energy had combined at the beginning of the respective reporting periods:
                                 
    Three months ended September 30,   Nine months ended September 30,
(In millions, except per share amounts)   2009   2008   2009   2008
 
Operating revenues
  $   2,911     $   5,122     $   8,625     $   11,633  
Net income/(loss) attributable to NRG Energy, Inc.
    282       (322 )     878       245  
Earnings per share attributable to NRG common stockholders:
                               
Basic
  $   1.11     $   (1.43 )   $   3.45     $   1.60  
Diluted
  $   1.04     $   (1.43 )   $   3.17     $   1.49  
 

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     The supplemental pro forma information has been adjusted to include the pro forma impact of amortization of intangible assets and out-of-market contracts, and depreciation of property, plant and equipment, based on the preliminary purchase price allocations. The pro forma data has also been adjusted to eliminate the non-recurring transaction costs incurred by NRG. Transactions between NRG and Reliant Energy have not been eliminated. The pro forma results are presented for illustrative purposes only and do not reflect the realization of potential cost savings, or any related integration costs. Certain cost savings may result from the acquisition, however, there can be no assurance that these cost savings will be achieved.
Significant Accounting Policies
     The following pertains to Reliant Energy, in addition to NRG’s significant accounting policies referred to in Note 2, Summary of Significant Accounting Policies, to this Form 10-Q:
   
Revenues — Gross revenues for energy sales and services to Mass customers and to C&I customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $151 million for the period ended September 30, 2009. These revenues represent a sale of excess supply to third parties in the market.
 
     
As of September 30, 2009, Reliant Energy recorded unbilled revenues of $321 million for energy sales and services. Accrued unbilled revenues are based on Reliant Energy’s estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.
 
   
Cost of Energy — Reliant Energy records cost of energy for electricity sales and services to retail customers based on estimated supply volumes for the applicable reporting period. A portion of its cost of energy ($68 million as of September 30, 2009) consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, Reliant Energy considers the effects of historical customer volumes, weather factors and usage by customer class. Reliant Energy estimates its transmission and distribution delivery fees using the same method that it uses for electricity sales and services to retail customers. In addition, Reliant Energy estimates ERCOT ISO fees based on historical trends, estimates supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.
 
   
Allowance for Doubtful Accounts — Reliant Energy accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. Reliant Energy writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.
 
   
Gross Receipts Taxes — Reliant Energy records gross receipts taxes on a gross basis in revenues and cost of operations in its condensed consolidated statements of operations. During the period ended September 30, 2009, Reliant Energy’s revenues and cost of operations included gross receipts taxes of $39 million.
 
   
Sales Taxes — Reliant Energy records sales taxes collected from its taxable customers and remitted to the various governmental entities on a net basis, thus, there is no impact on the Company’s condensed consolidated statement of operations.

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Note 5 — Investments Accounted for by the Equity Method
MIBRAG — On June 10, 2009, NRG completed the sale of its 50% ownership interest in Mibrag B.V. to a consortium of Severoćeské doly Chomutov, a member of the CEZ Group, and J&T Group. Mibrag B.V.’s principal holding is MIBRAG, which is jointly owned by NRG and URS Corporation. As part of the transaction, URS Corporation also entered into an agreement to sell its 50% stake in MIBRAG.
     For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40 U.S.$/EUR), net of transaction costs. During the nine months ended September 30, 2009, NRG recognized an after-tax gain of $128 million. Prior to completion of the sale, NRG continued to record its share of MIBRAG’s operations to “Equity in earnings of unconsolidated affiliates.”
     In connection with the transaction, NRG entered into a foreign currency forward contract to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200 million in exchange for $255 million on June 15, 2009. For the nine months ended September 30, 2009, NRG recorded an exchange loss of $24 million on the contract within “Other income/(loss), net.”
     NRG provided certain indemnities in connection with its share of the transaction. See Note 18, Guarantees, to this Form 10-Q for further discussion.
Note 6 — Fair Value of Financial Instruments
     The estimated carrying values and fair values of NRG’s recorded financial instruments are as follows:
                                 
    Carrying Amount   Fair Value
    September 30,   December 31,   September 30,   December 31,
    2009   2008   2009   2008
    (In millions)
Cash and cash equivalents
  $   2,250      1,494     $   2,250     1,494  
Funds deposited by counterparties
    293       754       293       754  
Restricted cash
    26       16       26       16  
Cash collateral paid in support of energy risk management activities
    475       494       475       494  
Investment in available-for-sale securities (classified within other non-current assets):
                               
Debt securities
    8       7       8       7  
Marketable equity securities
    4       2       4       2  
Trust fund investments
    356       305       356       305  
Notes receivable
    214       156       221       166  
Derivative assets
    4,238       5,485       4,238       5,485  
Long-term debt, including current portion
    8,636       8,019       8,422       7,475  
Cash collateral received in support of energy risk management activities
    293       760       293       760  
Derivative liabilities
    3,876       4,489       3,876       4,489  
 

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Recurring Fair Value Measurements
     The following table presents assets and liabilities measured and recorded at fair value on the Company’s condensed consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:
                                 
 (In millions)   Fair Value
 As of September 30, 2009   Level 1   Level 2   Level 3   Total
 
  Cash and cash equivalents
  2,250         $       2,250  
  Funds deposited by counterparties
    293              —       293  
  Restricted cash
    26              —       26  
  Cash collateral paid in support of energy risk management activities
    475              —       475  
  Investment in available-for-sale securities (classified within other non-current assets):
                               
Debt securities
                 8       8  
Marketable equity securities
    4              —       4  
 Trust fund investments
    203       113        40       356  
 Derivative assets
    964       3,171        103       4,238  
 
Total assets
  4,215     3,284     $   151     7,650  
 
 Cash collateral received in support of energy risk management activities
  293         $       293  
 Derivative liabilities
    956       2,747        173       3,876  
 
Total liabilities
  1,249     2,747     $   173     4,169  
 
     The following table reconciles the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements using significant unobservable inputs:
                                 
    Fair Value Measurement Using Significant Unobservable Inputs
    (Level 3)
 (In millions)           Trust Fund        
 Nine months ended September 30, 2009   Debt Securities   Investments   Derivatives   Total
 
  Beginning balance as of January 1, 2009
  7     31     49     87  
Total gains/(losses) (realized and unrealized)
                               
Included in earnings
    1             (110 )     (109 )
Included in nuclear decommissioning obligations
          8             8  
Purchases/(sales), net
          1       (3 )     (2 )
Transfers out of Level 3
                (6 )     (6 )
 
 Ending balance as of September 30, 2009
  8     40     $ (70 )   $ (22 )
 
 The amount of the total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held as of September 30, 2009
          3     3  
 
     Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in operating revenues and cost of operations.
     In determining the fair value of NRG’s Level 2 and 3 derivative contracts, NRG applies a credit reserve to reflect credit risk which is calculated based on credit default swaps. As of September 30, 2009, the credit reserve resulted in a $18 million increase in fair value which is composed of a $4 million gain in other comprehensive income, or OCI, and a $14 million gain in operating revenue and cost of operations.
     This footnote should be read in conjunction with the complete description under Note 4, Fair Value of Financial Instruments, to the Company’s financial statements in its 2008 Annual Report on Form 10-K.
     See Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding concentration of credit risk.

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Note 7 — Accounting for Derivative Instruments and Hedging Activities
     ASC 815 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 OCI until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.
     For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivative and the hedged transaction are recorded in current earnings. The ineffective portion of a hedging derivative instrument’s change in fair value is immediately recognized into earnings.
     For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established per ASC 815, certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG’s energy related commodity contracts, interest rate swaps, and foreign exchange contracts.
     As the Company engages principally in the trading and marketing of its generation assets and retail business, some of NRG’s commercial activities qualify for hedge accounting under the requirements of ASC 815. In order for the generation assets to qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company’s baseload plants. For this reason, many trades in support of NRG’s baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG’s peaking units will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the supply contracts are recorded under mark-to-market accounting. All of NRG’s hedging and trading activities are in accordance with the Company’s Risk Management Policy.
Energy-Related Commodities
     To manage the commodity price risk associated with the Company’s competitive supply activities and the price risk associated with wholesale and retail power sales from the Company’s electric generation facilities, NRG may enter into a variety of derivative and non-derivative hedging instruments, utilizing the following:
   
Forward contracts, which commit NRG to sell or purchase energy commodities or purchase fuels in the future.
 
   
Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument.
 
   
Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity.
 
   
Option contracts, which convey the right or obligation to purchase or sell a commodity.
 
   
Weather and hurricane derivative products used to mitigate a portion of Reliant Energy’s lost revenue due to weather.
     The objectives for entering into derivative contracts designated as hedges include:
   
Fixing the price for a portion of anticipated future electricity sales through the use of various derivative instruments including gas collars and swaps at a level that provides an acceptable return on the Company’s electric generation operations.
 
   
Fixing the price of a portion of anticipated fuel purchases for the operation of NRG’s power plants.
 
   
Fixing the price of a portion of anticipated energy purchases to supply Reliant Energy’s customers.

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     NRG’s trading activities include contracts entered into to profit from market price changes as opposed to hedging an exposure, and are subject to limits in accordance with the Company’s Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. These trading activities are a complement to NRG’s competitive wholesale supply and retail operations.
Interest Rate Swaps
     NRG is exposed to changes in interest rates through the Company’s issuance of variable and fixed rate debt. In order to manage the Company’s interest rate risk, NRG enters into interest-rate swap agreements. As of September 30, 2009, NRG had interest rate derivative instruments extending through June 2019, all of which had been designated as either cash flow or fair value hedges.
Volumetric Underlying Derivative Transactions
     The following table summarizes the net notional volume buy/(sell) of NRG’s derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of September 30, 2009. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.
             
        Total Volume as
        of September 30, 2009
Commodity   Units   (In millions)
 
Emissions
  Short Ton     1  
Coal
  Short Ton     60  
Natural Gas
  MMBtu     (582 )
Power(a)
  MWH     (27 )
Interest
  Dollars   $   3,306  
 
(a)  
Power volumes include capacity sales.
Fair Value of Derivative Instruments
     The following table summarizes the fair value within the derivative instrument valuation on the balance sheet as of September 30, 2009:
                 
    Fair Value
(In millions)   Derivatives Asset   Derivatives Liability
 
Derivatives Designated as Cash Flow or Fair Value Hedges:
               
Interest rate contracts current
  $       $   4  
Interest rate contracts long term
    9       123  
Commodity contracts current
    278       13  
Commodity contracts long term
    378       30  
 
Total Derivatives Designated as Cash Flow or Fair Value Hedges
    665       170  
 
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
               
Commodity contracts current
    2,921       3,000  
Commodity contracts long term
    652       706  
 
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges
    3,573       3,706  
 
Total Derivatives
  $   4,238     $   3,876  
 
Impact of Derivative Instruments on the Statement of Operations
     The following table summarizes the amount of gain/(loss) resulting from fair value hedges reflected in interest income/(expense) for interest rate contracts:
                 
Amount of gain/(loss) recognized   Three months ended   Nine months ended
(In millions)   September 30, 2009   September 30, 2009
 
Derivative
  $   3     $   (5 )
Senior Notes (hedged item)
  $   (3 )   $   5  
 

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     The following table summarizes the location and amount of gain/(loss) resulting from cash flow hedges:
                                         
                            Location of   Amount of
    Amount of   Location of   Amount of   gain/(loss)   gain/(loss)
    gain/(loss)   gain/(loss)   gain/(loss)   recognized in   recognized in
  recognized in OCI   reclassified from   reclassified from   income   income
(In millions)   (effective portion)   Accumulated   Accumulated   (ineffective   (ineffective
Three months ended September 30, 2009   after tax   OCI into Income   OCI into Income   portion)   portion)
 
Interest rate contracts
  (2 )   Interest expense       Interest expense   4  
Commodity contracts
    (71 )   Operating revenue     75     Operating revenue     16  
 
Total
  (73 )           75             20  
 
                                         
                            Location of   Amount of
    Amount of   Location of   Amount of   gain/(loss)   gain/(loss)
    gain/(loss)   gain/(loss)   gain/(loss)   recognized in   recognized in
    recognized in OCI   reclassified from   reclassified from   income   Income
(In millions)   (effective portion)   Accumulated   Accumulated   (ineffective   (ineffective
Nine months ended September 30, 2009   after tax   OCI into Income   OCI into Income   portion)   Portion)
 
Interest rate contracts
  23     Interest expense       Interest expense   4  
Commodity contracts
    (32 )   Operating revenue     398     Operating revenue     17  
 
Total
  (9 )           398             21  
 
     The following table summarizes the amount of gain/(loss) recognized in income for derivatives not designated as cash flow or fair value hedges on commodity contracts:
                 
Amount of gain/(loss) recognized in income or cost of operations for derivatives   Three months ended   Nine months ended
(In millions)   September 30, 2009   September 30, 2009
 
Location of gain/(loss) recognized in income for derivatives:
               
Operating revenue
  (233 )   (117 )
Cost of operations
  203     476  
 
Credit Risk Related Contingent Features
     Certain of the Company’s hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements. Other agreements contain provisions that require the Company to post additional collateral if there was a one notch downgrade in the Company’s credit rating. The collateral required for out-of-the-money positions and net accounts payable for contracts that have adequate assurance clauses that are in a net liability position as of September 30, 2009, was $163 million. The collateral required for out-of-the-money positions and net accounts payable for contracts with credit rating contingent features that are in a net liability position as of September 30, 2009, was $31 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $24 million as of September 30, 2009.
     Under the CSRA, Merrill Lynch provided guarantees and the posting of collateral to the Company’s counterparties in supply transactions for the Company’s retail energy business. As of September 30, 2009, Merrill Lynch was providing $163 million in credit support to various counterparties (includes cash collateral posted by counterparties and Reliant Energy as an offset to exposure).
     As described in Note 20, Subsequent Event, to this Form 10-Q, pursuant to the CSRA Amendment, effective October 5, 2009, the Company was required to post collateral for any net liability derivatives and other static margin associated with supply for Reliant Energy. In connection with the CSRA Amendment, the Company posted $366 million of cash collateral to Merrill Lynch and other counterparties, returned $53 million of counterparty collateral, issued letters of credit of $206 million, and received $45 million of counterparty collateral.

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Concentration of Credit Risk
     Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties’ credit limits; (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk with a diversified portfolio of counterparties, including ten participants under its first and second lien structure. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.
     Since the credit crisis began in late 2008, NRG has taken several additional steps to mitigate credit risk including the use of netting arrangements, entering contracts with collateral thresholds, setting volumetric limits with certain counterparties and restricting trading relationships with counterparties where exposure was high or where credit quality of the counterparty had deteriorated. NRG avoids concentration of counterparties whenever possible and applies credit policies that include an evaluation of counterparties’ financial condition, collateral requirements and the use of standard agreements that allow for netting and other security.
     As of September 30, 2009, total credit exposure to substantially all counterparties was $1.8 billion and NRG held collateral (cash and letters of credit) against those positions of $280 million resulting in a net exposure of $1.5 billion. Total credit exposure is discounted at the risk free rate.
     The following table highlights the credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, includes amounts net of receivables or payables and excludes non-affiliate third party exposure under the CSRA.
         
    Net Exposure (a)(b)
       as of September 30, 2009   
Category   (% of Total)
 
Financial institutions
    81 %
Utilities, energy, merchants, marketers and other
    13  
Coal suppliers
    3  
ISOs
    3  
 
Total
    100 %
 
 
    Net Exposure (a)(b)
       as of September 30, 2009   
Category   (% of Total)
 
Investment grade
    93 %
Non-Investment grade
    2  
Non-rated
    5  
 
Total
    100 %
 
(a)  
Credit exposure excludes California tolling, uranium, coal transportation, New England Reliability Must-Run, cooperative load contracts, and Texas Westmoreland coal contracts. The aforementioned exposures were excluded for various reasons including regulatory support or liens held against the contracts which serve to reduce the risk of loss, or credit risks for certain contracts are not readily measurable due to a lack of market reference prices.
 
(b)  
The exposure amounts presented in the above table do not include non-affiliate third party exposure under the CSRA which was amended on October 5, 2009. The gross credit exposure to third parties under the CSRA was $385 million, and the cash collateral held by Merrill Lynch against this exposure was $304 million.
     NRG has credit risk exposure to certain counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $704 million. Approximately 72% of NRG’s positions relating to credit risk roll-off by the end of 2011. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company’s financial results from nonperformance by a counterparty.

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     NRG is exposed to retail credit risk through our competitive electricity supply business, which serves C&I customers and the Mass market in Texas. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangement. Retail credit risk is dependent on the overall economy, but is minimized due to the fact that NRG’s portfolio of retail customers is largely diversified, with no significant single name concentration.
Accumulated Other Comprehensive Income
     The following table summarizes the effects of ASC 815 on NRG’s accumulated OCI balance attributable to hedged derivatives, net of tax:
                         
(In millions)   Energy   Interest    
Three months ended September 30, 2009   Commodities   Rate   Total
 
Accumulated OCI balance at June 30, 2009
  $   445     $   (66 )   $   379  
Realized from OCI during the period:
                       
— Due to realization of previously deferred amounts
    (75 )           (75 )
Mark-to-market of cash flow hedge accounting contracts
    4       (2 )     2  
 
Accumulated OCI balance at September 30, 2009
  $   374     $   (68 )   $   306  
 
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $172 tax
  $   288     $   (3 )   $   285  
 
                         
(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 cash flow hedge accounting contracts
    1,088       (2 )     1,086  
 
Accumulated OCI balance at September 30, 2008
  $   (121 )   $   (32 )   $   (153 )
 
                         
(In millions)   Energy   Interest    
Nine months ended September 30, 2009   Commodities   Rate   Total
 
Accumulated OCI balance at December 31, 2008
  $   406     $   (91 )   $   315  
Realized from OCI during the period:
                       
— Due to realization of previously deferred amounts
    (263 )           (263 )
— Due to discontinuance of cash flow hedge accounting
    (135 )           (135 )
Mark-to-market of cash flow hedge accounting contracts
    366       23       389  
 
Accumulated OCI balance at September 30, 2009
  $   374     $   (68 )   $   306  
 
                         
(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 cash flow hedge accounting contracts
    81       (1 )     80  
 
Accumulated OCI balance at September 30, 2008
  $   (121 )   $   (32 )   $   (153 )
 
     As of September 30, 2009, the net balance in OCI relating to ASC 815 was an unrecognized gain of approximately $306 million, which is net of $189 million in income taxes. As of September 30, 2008, the net balance in OCI relating to ASC 815 was an unrecognized loss of approximately $153 million, which was net of $102 million in income taxes.
     Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of July 31, 2008, the Company’s regression analysis for natural gas prices to ERCOT power prices, while positively correlated, did not meet the required threshold for cash flow hedge accounting for calendar years 2012 and 2013. As a result, the Company de-designated its 2012 and 2013 ERCOT cash flow hedges as of July 31, 2008 and prospectively marked these derivatives to market. On April 1, 2009, the required correlation threshold for cash flow hedge accounting was achieved for these transactions, and accordingly, these hedges were re-designated as cash flow hedges.

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     As discussed in Note 4, Business Acquisition, to this Form 10-Q, in conjunction with the CSRA, PML and REPS modified or novated certain transactions with counterparties. The novated transactions are financial sales of natural gas to the counterparties covering the period from 2009 through 2012 to hedge NRG’s Texas baseload generation. A portion of these transactions were accounted for as cash flow hedges. The effective portion of the fair value of these transactions recorded in OCI was approximately $245 million. On the date of novation, NRG elected to de-designate these cash flow hedges and to recognize future changes in value in earnings prospectively. As the underlying baseload power generation is still probable, the gains through the date of novation related to the cash flow hedges remain frozen in OCI and will be amortized into income when the underlying power is generated. Approximately $248 million of the fair values of these transactions at the novation date were accounted for as mark-to-market transactions through the income statement both before and after the novations.
     As discussed in Note 20, Subsequent Event, to this Form 10-Q, NRG amended the CSRA effective October 5, 2009, and net settled or offset certain REPS transactions with counterparties.
Statement of Operations
     In accordance with ASC 815, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow 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 and cost of operations.
                                 
    Three Months ended September 30,   Nine months ended September 30,
(In millions)   2009   2008   2009   2008
 
Unrealized mark-to-market results
                               
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges
  $   1     (7 )   (33 )   $   (32 )
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009
    238             448        
Reversal of previously recognized unrealized gains on settled positions related to trading activity
    (21 )     (9 )     (125 )     (20 )
Net unrealized (losses)/gains on open positions related to economic hedges
    (239 )     439       70       180  
Gains/(losses) on ineffectiveness associated with open positions treated as cash flow hedges
    16       352       17       (27 )
Net unrealized (losses)/gains on open positions related to trading activity
    (9 )     60       (1 )     91  
 
Total unrealized (losses)/gains
  $   (14 )   $   835     $   376     $   192  
 
                                 
    Three months ended September 30,   Nine months ended September 30,
(In millions)   2009   2008   2009   2008
 
Revenue from operations — energy commodities
  $   (217 )   $   835     $   (100 )   $   192  
Cost of operations
    203             476        
 
Total impact to statement of operations
  $   (14 )   $   835     $   376     $   192  
 

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     For the nine months ended September 30, 2009, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $376 million was comprised of gains of $70 million from fair value increases in forward sales and purchases of natural gas, electricity and fuel, $17 million gain from ineffectiveness, $158 million loss from the reversal of mark-to-market gains, $448 million roll-off of Reliant Energy loss positions acquired as of May 1, 2009, and $1 million of losses associated with the Company’s trading activity. The $70 million gain from economic hedge positions includes $217 million recognized in earnings from previously deferred amounts in OCI as the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New York due to lower expected generation, and a $147 million increase in value of forward purchases and sales of natural gas, electricity and fuel due to decrease in forward power and gas prices. The $17 million gain is primarily from hedge accounting ineffectiveness related to gas trades in Texas which was driven by decreasing forward gas prices while forward power prices decreased at a slower pace. The Company recognized a derivative loss of $29 million resulting from discontinued NPNS designated coal purchases due to expected lower coal consumption and accordingly could not assert taking physical delivery. This amount is included in the Company’s cost of operations.
     The Reliant Energy’s loss positions were acquired as of May 1, 2009 and valued using forward prices on that date. The $448 million roll-off amounts were offset by realized losses at the settled prices and are reflected in the cost of operations during the same period.
     For the nine months ended September 30, 2008, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $192 million was comprised of $180 million of fair value increases in forward sales of electricity and fuel, a $27 million loss due to the ineffectiveness associated with financial forward contracted electric and gas sales, $52 million from the reversal of mark-to-market gains which ultimately settled as financial revenues of which $32 million was related to economic hedges and $20 million was related to trading activity. These decreases were partially offset by $91 million of gains associated with open positions related to trading activity.
     Discontinued Hedge Accounting — During the first half of 2009, a relatively sharp decline in commodity prices resulted in falling power prices and lower power generation for the remainder of 2009. As such, NRG discontinued cash flow hedge accounting for certain 2009 contracts previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted sales by baseload plants in Texas and Northeast. As a result, $217 million of gain previously deferred in OCI was recognized in earnings for the nine months ended September 30, 2009.
     Discontinued Normal Purchase and Sale for Coal Purchases — Due to lower coal-fired generation during the first quarter 2009, the Company’s coal consumption was lower than forecasted. The Company net settled some of its coal purchases under NPNS designation and thus was no longer able to assert physical delivery under these coal contracts. The forward positions previously treated as accrual accounting have been reclassified into mark-to-market accounting during the first quarter and prospectively. The impact of discontinuance of coal NPNS designated transactions resulted in a derivative loss of $29 million that is reflected in the cost of operations for the nine months ended September 30, 2009.

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Note 8 — Long-Term Debt
2019 Senior Notes
     On June 5, 2009, NRG issued $700 million aggregate principal amount of 8.5% Senior Notes due 2019, or 2019 Senior Notes, at a discount resulting in a yield of 8.75%. The 2019 Senior Notes were issued under an Indenture, dated February 2, 2006, between NRG and Law Debenture Trust Company of New York, as trustee, as amended through Supplemental Indentures, which is discussed in Note 11, Debt and Capital Leases, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008. The Indentures and the form of the notes provide, among other things, that the 2019 Senior Notes will be senior unsecured obligations of NRG.
     A portion of the net proceeds of $678 million were used to facilitate the early termination of NRG’s obligations pursuant to the CSRA Amendment, which became effective on October 5, 2009, as discussed in Note 20, Subsequent Event, to this Form 10-Q. Interest is payable semi-annually on the 2019 Senior Notes beginning on December 15, 2009, until their maturity date of June 15, 2019. As of September 30, 2009, $700 million in principal was outstanding under the 2019 Senior Notes.
     Prior to June 15, 2012, NRG may redeem up to 35% of the aggregate principal amount of the 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.5% of the principal amount. Prior to June 15, 2014, NRG may redeem all or a portion of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note; or (ii) the excess of the principal amount of the note over the following: the present value of 104.25% of the note, plus interest payments due on the note from the date of redemption through June 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after June 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
         
    Redemption
Redemption Period   Percentage
 
June 15, 2014 to June 14, 2015
    104.25 %
June 15, 2015 to June 14, 2016
    102.83 %
June 15, 2016 to June 14, 2017
    101.42 %
June 15, 2017 and thereafter
    100.00 %
 
Interest Rate Swaps
     In May 2009, NRG entered into a series of forward-starting interest rate swaps. These interest rate swaps become effective on April 1, 2011, and are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, the Company will pay its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on a 1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps is $900 million. The swaps mature on February 1, 2013.
Reliant Energy Acquisition
     See discussion in Note 4, Business Acquisition, to this Form 10-Q, regarding the CSRA entered into as a result of the acquisition of Reliant Energy on May 1, 2009. Further, see discussion in Note 4, Business Acquisition, to this Form 10-Q, regarding the $50 million working capital facility entered into on May 1, 2009. Under the working capital facility, the Company borrowed $25 million on May 1, 2009. On October 5, 2009, $25 million was repaid on the working capital facility, which was terminated in conjunction with the amendment of the CSRA as discussed in Note 20, Subsequent Event, to this Form 10-Q.
Senior Credit Facility
     In March 2009, NRG made a repayment of approximately $197 million to its first lien lenders under the Term Loan Facility. This payment resulted from the mandatory annual offer of a portion of NRG’s excess cash flow (as defined in the Senior Credit Facility) for the prior year.

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TANE Facility
     On February 24, 2009, Nuclear Innovation North America LLC, or NINA, executed an Engineering, Procurement and Construction, or EPC, agreement with Toshiba American Nuclear Energy Corporation, or TANE, which specifies the terms under which STP Units 3 and 4 will be constructed. Concurrent with the execution of the EPC agreement, NINA and TANE entered into a credit facility, or the TANE Facility, wherein TANE has committed up to $500 million to finance purchases of long-lead materials and equipment for the construction of STP Units 3 and 4. The TANE Facility matures on February 24, 2012, subject to two renewal periods, and provides for customary events of default, which include, among others: nonpayment of principal or interest; default under other indebtedness; the rendering of judgments; and certain events of bankruptcy or insolvency. Outstanding borrowings will accrue interest at LIBOR plus 3%, subject to a ratings grid, and are secured by substantially all of the assets of and membership interests in NINA and its subsidiaries. As of September 30, 2009, no amounts have been borrowed under the TANE Facility.
Debt Related to Capital Allocation Program
     Share Lending Agreements — On February 20, 2009, CSF I and CSF II, wholly-owned unrestricted subsidiaries of the Company, entered into Share Lending Agreements with affiliates of CS relating to the shares of NRG common stock currently held by CSF I and II in connection with the CSF Debt originally entered into during the third quarter 2006, by and between CSF I and II and affiliates of CS. The Company entered into Share Lending Agreements due to a lack of liquidity in the stock borrow market for NRG shares and in order to maintain the intended economic benefits of the CSF Debt agreements. As of September 30, 2009, CSF I and II have lent affiliates of CS 12,000,000 shares of the 21,970,903 shares of NRG common stock held by CSF I and II. The Share Lending Agreements permit affiliates of CS to borrow up to the total number of shares of NRG common stock held by CSF I and II.
     Shares borrowed by affiliates of CS under the Share Lending Agreements will be used to replace shares borrowed by affiliates of CS from third parties in connection with CS hedging activities related to the financing agreements.
     The shares are expected to be returned upon the termination of the financing agreements. Until the shares are returned, the shares will be treated as outstanding for corporate law purposes, and accordingly, the holders of the borrowed shares will have all of the rights of a holder of the Company’s outstanding shares, including the right to vote the shares on all matters submitted to a vote of the Company’s stockholders. However, because the CS affiliates must return all borrowed shares (or identical shares), the borrowed shares are not considered outstanding for the purpose of computing and reporting the Company’s basic or diluted earnings per share.
     Adoption of FSP APB 14-1 — As discussed in Note 1, Basis of Presentation, to this Form 10-Q, the Company adopted FSP APB 14-1 on January 1, 2009, which has been incorporated in ASC 470 and ASC 825. The following table summarizes certain information related to the CSF Debt in accordance with ASC 470.
                      
    September 30,   December 31,   
    2009   2008
 
Equity Component
               
Additional Paid-in Capital
  $   14     $   14  
 
Liability Component
               
Principal amount
  $   333     $   333  
Unamortized discount
    (3 )     (8 )
 
Net carrying amount
  $   330     $   325  
 
     The unamortized discount will be amortized through the maturity of the CSF Debt. The CSF I Debt has a maturity date of June 2010 and the CSF II Debt has a maturity date of October 2009. Interest expense for the CSF Debt, including the debt discount amortization for the three and nine months ended September 30, 2009, was $10 million and $28 million, respectively. Interest expense for the CSF Debt, including the debt discount amortization for the three and nine months ended September 30, 2008, was $9 million and $28 million, respectively. The effective interest rate as of September 30, 2009, was 11.4% for the CSF I Debt and 12.1% for the CSF II Debt.
     Subsequent Event — On October 9, 2009, NRG commenced the process of unwinding the CSF II Debt, making a $181.4 million capital contribution to a CSF II cash account, effectively restricting the cash for the benefit of CS. On October 13, 2009, CS began the process of unwinding their hedges in connection with the CSF II structure, which they are required to complete by November 24, 2009. Once complete, CS is scheduled to return 5,400,000 shares of NRG common stock borrowed under the Share Lending Agreements, and release 9,528,930 common shares held as collateral for the CSF II Debt, and the Company will remit payment to CS of the $181.4 million outstanding principal and interest.

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     The CSF II Debt contains an embedded derivative feature, or CFS II CAGR, which requires NRG to pay CS at maturity, either in cash or stock at NRG’s option, the excess of NRG’s then current stock price over a Threshold Price of $40.80 per share. On November 24, 2009, the CSF II CAGR will also be evaluated to determine whether any payment is due to CS, at which point the CSF II CAGR will expire.
     Dunkirk Power LLC Tax-Exempt Bonds — On April 15, 2009, NRG executed a $59 million tax-exempt bond financing through its wholly-owned subsidiary, Dunkirk Power LLC. The bonds were issued by the County of Chautauqua Industrial Development Agency and will be used for construction of emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The bonds initially bear weekly interest based on the Securities Industry and Financial Markets Association, or SIFMA, rate, have a maturity date of April 1, 2042, and are enhanced by a letter of credit under the Company’s Revolving Credit Facility covering amounts drawn on the facility. The proceeds received through September 30, 2009, were $38 million with the remaining balance being released over time as construction costs are paid.
     GenConn Energy LLC related financings — On April 27, 2009, a wholly-owned subsidiary of NRG closed on an equity bridge loan facility, or EBL, in the amount of $121.5 million from a syndicate of banks. The purpose of the EBL is to fund the Company’s proportionate share of the project construction costs required to be contributed into GenConn Energy LLC, or GenConn, a 50% equity method investment of the Company. The EBL, which is fully collateralized with a letter of credit issued under the Company’s Synthetic Letter of Credit Facility covering amounts drawn on the facility, will bear interest at a rate of LIBOR plus 2% on drawn amounts. The EBL will mature on the earlier of the commercial operations date of the Middletown project or July 26, 2011. The EBL also requires mandatory prepayment of the portion of the loan utilized to pay costs of the Devon project, of approximately $56 million, on the earlier of Devon’s commercial operations date or January 27, 2011. The proceeds of the EBL received through September 30, 2009, were $88 million and the remaining amounts will be drawn as necessary to fund construction costs.
     In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a 7-year term loan facility, and also entered into a 5-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the revolving facility. In August 2009, GenConn began to draw under the GenConn Facility to cover costs related to the Devon project and as of September 30, 2009, has drawn $19 million.

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Note 9 — 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, 2009:
                                 
    Authorized   Issued   Treasury   Outstanding
 
Balance as of December 31, 2008
    500,000,000       263,599,200       (29,242,483 )     234,356,717  
Shares issued from LTIP
          268,220             268,220  
Shares issued under NRG Employee Stock Purchase Plan, or ESPP
                81,532       81,532  
Shares borrowed by affiliates of CS
                12,000,000       12,000,000  
2009 Share Repurchases
                (8,919,100 )     (8,919,100 )
4.00% Preferred Stock conversion
          20,650             20,650  
5.75% Preferred Stock conversion
          18,601,201             18,601,201  
 
Balance as of September 30, 2009
    500,000,000       282,489,271       (26,080,051 )     256,409,220  
 
Employee Stock Purchase Plan
     As of September 30, 2009, there were 418,468 shares of treasury stock reserved for issuance under the ESPP.
5.75% Preferred Stock
     Certain holders of the Company’s 5.75% convertible perpetual preferred stock, or 5.75% Preferred Stock, elected to convert their preferred shares into NRG common shares prior to the mandatory conversion date of March 16, 2009, at the minimum conversion rate of 8.2712. As of March 16, 2009, each remaining outstanding share of the 5.75% Preferred Stock automatically converted into shares of common stock at a rate of 10.2564, based upon the applicable market value of NRG’s common stock. These conversions resulted in a decrease in preferred stock of $447 million, and a corresponding increase in Additional Paid-in Capital. The following table summarizes the conversion of the 5.75% Preferred Stock into NRG Common Stock:
                         
    Preferred Stock   Conversion Rate   Common Stock
    Shares   (per share)   Shares
 
Balance as of December 31, 2008
    1,841,680                
Preferred shares converted by the holders prior to March 16, 2009
    144,975       8.2712       1,199,116  
Preferred shares automatically converted as of March 16, 2009
    1,696,705       10.2564       17,402,085  
 
Balance at September 30, 2009
                  18,601,201  
 
4% Preferred Stock
     As of September 30, 2009, 413 shares of the 4% Preferred Stock were converted into 20,650 shares of common stock in 2009.
2009 Capital Allocation Program
     In July 2009, as part of the Company’s 2009 Capital Allocation Program, NRG’s Board of Directors approved an increase to the Company’s previously authorized common share repurchases under its capital allocation plan from the existing $330 million to $500 million. The Company’s repurchases during the period ended September 30, 2009, were $250 million. NRG intends to complete its $500 million of share repurchases by the end of 2009, subject to market prices, financial restrictions under the Company’s debt facilities, and as permitted by securities laws.

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Note 10 — Equity Compensation
Non-Qualified Stock Options, or NQSO’s
     The following table summarizes the Company’s NQSO activity as of September 30, 2009, and changes during the nine months then ended:
                         
            Weighted   Aggregate Intrinsic
            Average   Value
    Shares   Exercise Price   (In millions)
 
Outstanding as of December 31, 2008
    4,008,188     $   25.84          
Granted
    1,402,000       23.62          
Exercised
    (25,000 )     21.41          
Forfeited
    (212,935 )     27.55          
         
Outstanding at September 30, 2009
    5,172,253       25.19     29.71  
Exercisable at September 30, 2009
    2,815,800     21.80     22.98  
 
     The weighted average grant date fair value of NQSO’s granted for the nine months ended September 30, 2009, was $8.63.
Restricted Stock Units, or RSU’s
     The following table summarizes the Company’s non-vested RSU awards as of September 30, 2009, and changes during the nine months then ended:
                 
            Weighted Average
            Grant-Date
    Units   Fair Value Per Unit
 
Non-vested as of December 31, 2008
    1,061,996     32.97  
Granted
    927,000       26.12  
Vested
    (334,752 )     23.24  
Forfeited
    (45,850 )     33.59  
 
Non-vested as of September 30, 2009
    1,608,394     31.03  
 
   Performance Units, or PU’s
     The following table summarizes the Company’s non-vested PU awards as of September 30, 2009, and changes during the nine months then ended:
                 
            Weighted Average
            Grant- Date
    Units   Fair Value Per Unit
 
Non-vested as of December 31, 2008
    659,564     22.81  
Granted
    338,100       22.91  
Forfeited
    (272,864 )     19.44  
 
Non-vested as of September 30, 2009
    724,800     24.29  
 
     In the nine months ended September 30, 2009, there were no performance unit payouts in accordance with the terms of the performance units.
Deferral Stock Units, or DSU’s
     The following table summarizes the Company’s outstanding DSU awards as of September 30, 2009, and changes during the nine months then ended:
                 
            Weighted Average
            Grant- Date
    Units   Fair Value Per Unit
 
Outstanding as of December 31, 2008
    260,768     18.50  
Granted
    65,437       22.77  
Conversions
    (22,156 )     23.69  
 
Outstanding as of September 30, 2009
    304,049     19.34  
 

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Note 11 — Earnings Per Share
     Basic earnings per share attributable to NRG common stockholders is computed by dividing net income attributable to NRG 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. The 12,000,000 shares outstanding under the Share Lending Agreements with CS affiliates are not treated as outstanding for earnings per share purposes because the CS affiliates must return all borrowed shares (or identical shares) upon termination of the Agreements. See Note 8, Long-Term Debt, to this Form 10-Q, for more information on the Share Lending Agreements. Diluted earnings per share attributable to NRG common stockholders 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 attributable to NRG is as follows:
                                 
    Three Months ended     Nine months ended  
    September 30,     September 30,  
(In millions, except per share data)   2009     2008     2009     2008  
 
Basic earnings per share attributable to NRG common stockholders
                               
Numerator:
                               
Income from continuing operations, net of income taxes
  $ 278     $ 778     $ 909     $ 782  
Dividends for preferred shares
    (6 )     (13 )     (27 )     (41 )    
 
Net income available to common stockholders from continuing operations
    272       765       882       741  
Income from discontinued operations, net of income taxes
                      172  
 
Net income attributable to NRG Energy, Inc. available to common stockholders
  $ 272     $ 765     $ 882     $ 913  
 
Denominator:
                               
Weighted average number of common shares outstanding
    249.3       234.8       246.6       235.7  
Basic earnings per share:
                               
Income from continuing operations
  $ 1.09     $ 3.26     $ 3.58     $ 3.14  
Income from discontinued operations, net of income taxes
                      0.73  
 
Net income attributable to NRG Energy, Inc.
  $ 1.09     $ 3.26     $ 3.58     $ 3.87  
 
Diluted earnings per share attributable to NRG common stockholders
                               
Numerator:
                               
Net income available to common stockholders from continuing operations
  $ 272     $ 765     $ 882     $ 741  
Add preferred stock dividends for dilutive preferred stock
    4       11       19       34  
 
Adjusted income from continuing operations
    276       776       901       775  
Income from discontinued operations, net of income taxes
                      172  
 
Net income attributable to NRG Energy, Inc. available to common stockholders
  $ 276     $ 776     $ 901     $ 947  
 
Denominator:
                               
Weighted average number of common shares outstanding
    249.3       234.8       246.6       235.7  
Incremental shares attributable to the issuance of equity compensation (treasury stock method)
    1.5       2.2       1.1       3.0  
Incremental shares attributable to embedded derivatives of 3.625% redeemable perpetual preferred stock (if-converted method)
          2.0             1.8  
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)
    21.0       37.5       26.4       37.5  
 
Total dilutive shares
    271.8       276.5       274.1       278.0  
Diluted earnings per share:
                               
Income from continuing operations
  $ 1.02     $ 2.81     $ 3.29     $ 2.79  
Income from discontinued operations, net of income taxes
                      0.62  
 
Net income attributable to NRG Energy, Inc.
  $ 1.02     $ 2.81     $ 3.29     $ 3.41  
 

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Effects on Earnings per Share
     The following table summarizes NRG’s outstanding equity instruments that were anti-dilutive and not included in the computation of the Company’s diluted earnings per share for the three and nine months ended September 30:
                                 
       Three months ended September 30,         Nine months ended September 30,   
(In millions of shares)   2009   2008   2009   2008
 
Equity compensation (NQSO’s and PU’s)
    4.8       1.8       6.4       1.4  
Embedded derivative of 3.625% redeemable perpetual preferred stock
    16.0       14.0       16.0       14.2  
Embedded derivative of CSF II Debt
    7.6       7.6       7.6       7.6  
 
Total
    28.4       23.4       30.0       23.2  
 
Note 12 — Segment Reporting
     NRG’s segment structure has changed to reflect the Company’s acquisition of Reliant Energy along with the previously reported 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.
     In the second quarter 2009, management changed its method for allocating corporate general and administrative expenses to the segments. Corporate general and administrative expenses had been allocated based on budgeted segment revenues. Beginning in the second quarter 2009, corporate general and administrative expenses have been allocated based on forecasted earnings/(losses) before interest expense, income taxes, depreciation and amortization expense.

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(In millions)           Wholesale Power Generation                
Three months ended   Reliant                   South                        
September 30, 2009   Energy   Texas (a)   Northeast   Central   West   International   Thermal   Corporate   Elimination   Total
 
Operating revenues
  $ 1,790     $ 760     $ 270     $ 143     $ 40     $ 38     $ 33     $ (3 )   $ (155 )   $ 2,916  
Depreciation and amortization
    42       119       29       16       2             2       2             212  
Equity in earnings of unconsolidated affiliates
                            4       2                         6  
Income/(loss) from continuing operations before income taxes
    393       196       50       (34 )     16       7       2       (186 )           444  
Net income/(loss) attributable to NRG Energy, Inc.
  $ 393     $ 196     $ 50     $ (34 )   $ 16     $ 6     $ 2     $ (351 )   $     $ 278  
 
Total assets
  $ 4,048     $ 13,634     $ 1,823     $ 914     $ 278     $ 791     $ 198     $ 22,602     $ (18,334 )   $ 25,954  
 
 
(a)      Includes inter-segment sales of $162 million to Reliant Energy.
     If the Company continued using the 2008 allocation method for corporate general and administrative expenses, the effect to net income/(loss) of each segment for the three months ended September 30, 2009, would have been as follows:
                                                                                 
Net income/(loss) attributable to NRG Energy, Inc. as reported
  $ 393     $ 196     $ 50     $ (34 )   $ 16     $ 6     $ 2     $ (351 )   $     $ 278  
Increase/(decrease) in net income/(loss) attributable to NRG Energy, Inc.
    (19 )     14       6       (1 )           1       (1 )                  
 
Adjusted net income/(loss) attributable to NRG Energy, Inc.
  $ 374     $ 210     $ 56     $ (35 )   $ 16     $ 7     $ 1     $ (351 )   $     $ 278      
 
 
            Wholesale Power Generation                
(In millions)                           South                        
Three months ended September 30, 2008           Texas   Northeast   Central   West   International   Thermal   Corporate   Elimination   Total
 
Operating revenues
          $ 1,637     $ 622     $ 234     $ 40     $ 41     $ 36     $ 3     $ (1 )   $ 2,612  
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
            1,026       296       25       13       25       4       (108 )     (1 )     1,280  
Net income/(loss) attributable to NRG Energy, Inc.
          $ 576     $ 296     $ 25     $ 13     $ 19     $ 4     $ (154 )   $ (1 )   $ 778  
 

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(In millions)           Wholesale Power Generation                
Nine months ended   Reliant                   South                        
September 30, 2009   Energy (a)   Texas (b)   Northeast   Central   West   International   Thermal   Corporate   Elimination   Total
 
Operating revenues
  $ 2,965     $ 2,304     $ 971     $ 444     $ 110     $ 106     $ 103     $ 33     $ (225 )   $ 6,811      
Depreciation and amortization
    85       353       88       50       6             7       5             594  
Equity in earnings/(losses) of unconsolidated affiliates
          (3 )                 8       28                         33  
Income/(loss) from continuing operations before income taxes
    807       681       303       (42 )     32       149       6       (414 )           1,522  
Net income/(loss)
    807       510       303       (42 )     32       143       6       (851 )           908  
Net loss attributable to non-controlling interest
          (1 )                                               (1 )
Net income/(loss) attributable to NRG Energy, Inc.
  $ 807     $ 511     $ 303     $ (42 )   $ 32     $ 143     $ 6     $ (851 )   $     $ 909  
 
(a)    Reliant Energy balances are for the five months ended September 30, 2009.
(b)    Includes inter-segment sales of $228 million to Reliant Energy.
     If the Company continued using the 2008 allocation method for corporate general and administrative expenses, the effect to net income/(loss) of each segment for the nine months ended September 30, 2009, would have been as follows:
                                                                                 
Net income/(loss) attributable to NRG Energy, Inc. as reported
  $ 807     $ 511     $ 303     $ (42 )   $ 32     $ 143     $ 6     $ (851 )   $     $ 909  
Increase/(decrease) in net income/(loss) attributable to NRG Energy, Inc.
    (30 )     22       9       (2 )     1                                
 
Adjusted net income/(loss) attributable to NRG Energy, Inc.
  $ 777     $ 533     $ 312     $ (44 )   $ 33     $ 143     $ 6     $ (851 )   $     $ 909  
 
                                                                                 
(In millions)           Wholesale Power Generation                
                            South                        
Nine months ended September 30, 2008           Texas   Northeast   Central   West   International   Thermal   Corporate   Elimination   Total
 
Operating revenues
          $ 3,037     $ 1,247     $ 585     $ 127     $ 122     $ 114     $ 1     $ (3 )   $ 5,230  
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
            1,107       310       58       38       72       11       (300 )     (11 )     1,285  
Income from discontinued operations, net of income taxes
                                    172                         172  
Net income/(loss) attributable to NRG Energy, Inc.
          $ 626     $ 310     $ 58     $ 38     $ 229     $ 11     $ (307 )   $ (11 )   $ 954  
 

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Note 13 — Income Taxes
Effective Tax Rate
     Income taxes included in continuing operations were as follows:
                 
        Three months ended September 30,    
(In millions except otherwise noted)   2009   2008
 
Income tax expense
  $ 166     $ 502  
Effective tax rate
    37.4 %     39.2 %
 
     For the three months ended September 30, 2009, NRG’s overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to the U.S. taxation of foreign earnings offset by a reduction in the valuation allowance. For the three months ended September 30, 2008, NRG’s effective tax rate was increased primarily due to the impact of state and local income taxes.
     Income taxes included in continuing operations were as follows:
                 
      Nine months ended September 30,  
(In millions except otherwise noted)   2009   2008
 
Income tax expense
  $ 614     $ 503  
Effective tax rate
    40.3 %     39.1 %
 
     For the nine months ended September 30, 2009, NRG’s overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to an increase in the valuation allowance as a result of capital losses generated during the nine months for which there are no projected capital gains or available tax planning strategies. For the nine months ended September 30, 2008, NRG’s overall effective tax rate was increased primarily due to the impact of state and local income taxes.
Deferred tax assets, liabilities and valuation allowance
     On a provisional basis, NRG established deferred tax assets of $1,203 million and deferred tax liabilities of $1,189 million as a result of NRG’s acquisition of Reliant Energy.
     In addition, the Company anticipates reversal of the deferred tax assets and corresponding valuation allowance pertaining to capital losses which will expire on December 31, 2009.
Valuation Allowance
     As of September 30, 2009, the Company’s valuation allowance was increased by approximately $63 million primarily due to losses generated in the period from derivative trading activity which require capital treatment for tax purposes. The Company increased its foreign valuation allowance by approximately $13 million.
Uncertain tax benefits
     As of September 30, 2009, NRG has recorded a $688 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 has accrued interest and penalties related to these unrecognized tax benefits of approximately $11 million for the nine months ended September 30, 2009, and has accrued approximately $19 million since adoption. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense.
     NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to U.S. 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 2002. The Company’s significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2000. The Company continues to be under examination by the Internal Revenue Service.

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Tax Receivable and Payable
     As of September 30, 2009, the Company has recorded a tax receivable of approximately $51 million that represents a domestic federal tax receivable of $9 million and state tax receivable of $42 million, net of $6 million reserve. In addition, the Company has recorded a current payable of approximately $56 million which includes domestic tax payable of approximately $45 million as well as foreign taxes payable of approximately $11 million.
Note 14 — 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 employees. The total amount of employer contributions paid for the nine months ended September 30, 2009, was $22 million. NRG expects to make $5 million in further contributions for the remainder of 2009. The total 2009 planned contribution of $27 million was a decrease of $33 million from the expected contributions as disclosed in Note 12, Benefit Plans and Other Postretirement Benefits, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008. This decrease in the 2009 expected contributions is due to the adoption by the Company in March 2009 of the new funding method options now available. The new methods were made allowable under new IRS guidance on the application of recent Congressional legislation on funding requirements.
     The net periodic pension cost related to all of the Company’s defined benefit pension plans include the following components:
                                 
    Defined Benefit Pension Plans
      Three months  ended September 30,       Nine months ended September 30,  
(In millions)    2009   2008          2009   2008
 
Service cost benefits earned
  4     $    4     $    11     $   11  
Interest cost on benefit obligation
    5       4       15       13  
Prior service cost
                1        
Net gain
                      (1 )
Expected return on plan assets
    (4 )     (4 )     (12 )     (11 )
 
Net periodic benefit cost
  5     $    4     $    15     $   12  
 
     The net periodic cost related to all of the Company’s other postretirement benefits plans includes the following components:
                                 
    Other Postretirement Benefits Plans
        Three months ended September 30,           Nine months ended September 30,    
(In millions)   2009   2008   2009   2008   
 
Service cost benefits earned
  $     $ 1     $   2     $   2  
Interest cost on benefit obligation
    3       1       5       4  
 
Net periodic benefit cost
  $ 3     $ 2     $   7     $   6  
 
STP Defined Benefit Plans
     NRG has a 44% undivided ownership interest in 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, 2009, was $3 million. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plans of $3 million and $2 million for the three months ended September 30, 2009, and 2008, respectively. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plans of $8 million and $6 million for the nine months ended September 30, 2009, and 2008, respectively.

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Note 15 — Commitments and Contingencies
Operating Lease Commitments
     As a result of the acquisition of Reliant Energy, the Company’s operating lease commitments have increased primarily due to additional lease agreements for office space through 2021. As of September 30, 2009, eight additional office space locations were under lease for future commitments of approximately $85 million.
Fuel Commitments
     NRG enters into long-term contractual arrangements to procure fuel and transportation services for the Company’s generation assets. NRG’s total net coal commitments, which span from 2009 through 2012, decreased by approximately $409 million during the nine months ended September 30, 2009, as the 2009 monthly commitments were settled. In addition, NRG’s natural gas purchase commitments decreased by approximately $199 million during the nine months ended September 30, 2009, as the 2009 monthly commitments were settled and average natural gas prices decreased.
Purchased Power Commitments
     As a result of the acquisition of Reliant Energy, NRG is party to purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities. These contracts are not included in the consolidated balance sheet as of September 30, 2009. Minimum purchase commitment obligations under these agreements are as follows as of September 30, 2009:
                 
(In millions)   Fixed Pricing (a)   Variable Pricing (b)
 
Remainder of 2009
  $    23     $      36  
2010
    54       7  
2011
    30       3  
2012
    21       1  
2013
    10        
 
Total
  $      138     $    47  
 
(a)   As of September 30. 2009, the maximum remaining term under any individual purchased power contract is four years.
(b)   For contracts with variable pricing components, estimated prices are based on forward commodity curves as of September 30, 2009.
Other
     As a result of the acquisition of Reliant Energy, the Company acquired the naming rights, including advertising and other benefits, for a football stadium and other convention and entertainment facilities included in the stadium complex in Houston, Texas. Pursuant to this agreement, the Company is required to pay $10 million per year through 2031.
     See discussion in Note 4, Business Acquisition, to this Form 10-Q, regarding the CSRA as a result of the acquisition of Reliant Energy on May 1, 2009.
First and Second Lien Structure
     NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets 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. The Company’s lien counterparties may have a claim on NRG’s assets to the extent market prices exceed the hedged price. As of September 30, 2009, and October 22, 2009, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.
RepoweringNRG Initiatives
     NRG has capitalized $32 million through September 30, 2009, for the repowering of its El Segundo generating facility in California. As a result of permitting delays related to on-going Natural Resource Defense Counsel claims, the El Segundo project will not reach its original completion date of June 1, 2011. The Company is working with the counterparty to consider certain PPA modifications including the commercial operations date.

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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 ASC 450 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. In addition, legal costs are expensed as incurred. 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 vary from its currently recorded reserves and such differences 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.
Exelon Related Litigation
     Delaware Chancery Court
     On November 11, 2008, Exelon and its wholly-owned subsidiary Exelon Xchange filed a complaint against NRG and NRG’s Board of Directors. The complaint alleges, among other things, that NRG’s Board of Directors failed to give due consideration and to take appropriate action in response to the acquisition proposal announced by Exelon on October 19, 2008, in which Exelon offered to acquire all of the outstanding shares of NRG common stock at an exchange ratio of 0.485 Exelon shares for each NRG common share. On November 14, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss Exelon’s complaint on the grounds that it failed to state a claim upon which relief can be granted. On March 16, 2009, prior to responding to the motion to dismiss, Exelon and Exelon Xchange filed an amended complaint. On April 17, 2009, NRG and NRG’s Board of Directors filed a partial motion to dismiss the amended complaint. On July 28, 2009, Exelon, NRG, and NRG’s Board of Directors collectively filed a Stipulation of Dismissal of Exelon’s lawsuit, thereby ending the case.
     On December 11, 2008, the Louisiana Sheriffs’ Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System, on behalf of themselves and all others similarly situated, served a previously filed complaint on NRG and its Board of Directors alleging substantially similar allegations as the Exelon complaint. On December 23, 2008, NRG and NRG’s Board of Directors filed a motion to dismiss the complaint on the grounds that it failed to state a claim upon which relief can be granted. On March 16, 2009, prior to responding to the motion to dismiss, these plaintiffs filed an amended complaint against only NRG’s Board of Directors. On April 17, 2009, the NRG Board of Directors filed a motion to dismiss the amended complaint asserting that it fails to state a claim upon which relief can be granted. On August 4, 2009, the plaintiffs filed a notice and proposed order of dismissal and on August 5, 2009, the court dismissed the lawsuit, thereby ending the case.
     Mercer County, New Jersey Superior Court
     On January 6, 2009, three lawsuits previously filed against NRG and NRG’s Board of Directors on behalf of individual shareholders and all others similarly situated were consolidated into one case in the Law Division of the Superior Court of Mercer County, New Jersey. On January 21, 2009, the plaintiffs filed an Amended Consolidated Complaint in which they allege a single count of breach of fiduciary duty against NRG’s Board of Directors and seek injunctive relief. On February 20, 2009, NRG’s Board of Directors filed a motion to dismiss the amended consolidated complaint for failure to state a claim or, in the alternative, to stay the action in favor of the Delaware Chancery Court proceedings. On March 19, 2009, the plaintiffs filed their response and on April 6, 2009, NRG’s Board of Directors filed its reply. On April 17, 2009, and again on May 7, 2009, oral argument was held and on June 18, 2009, the court found in favor of NRG’s Board of Directors and stayed the consolidated lawsuits pending resolution of the purported class-action lawsuit filed in Delaware Chancery court by the Louisiana Sheriffs’ Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System. On August 10, 2009, the plaintiffs filed a Notice of Voluntary Dismissal, thereby ending the case.

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California Department of Water Resources
     This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the Federal Energy Regulatory Commission, or FERC, abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC’s review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP’s appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008 the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller’s market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-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. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit’s decision agreeing that the case should be remanded to the FERC to clarify the 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. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008 decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-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 that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court’s June 26, 2008 decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand, and on January 28, 2009, WCP and the other seller-defendants filed their reply.
     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 the 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.
     On April 27, 2009, the U.S. Supreme Court granted certiorari in an unrelated proceeding involving the Mobile-Sierra doctrine that may affect the standard of review applied to the CDWR contract on remand before the FERC. Specifically, on March 18, 2008, the U.S. Court of Appeals for the DC Circuit rejected the appeals filed by the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts regarding the settlement that established the current New England capacity market. The settlement, filed with the FERC on March 7, 2006, provides for interim capacity transition payments for all generators in New England for the period starting December 1, 2006 through May 31, 2010 and for the Forward Capacity Market thereafter. The DC Circuit Court of Appeals rejected all substantive challenges to the settlement, but sustained one procedural argument relating to the applicability of the Mobile-Sierra doctrine to non-settling parties. NRG sought certiorari before the U.S. Supreme Court, which was granted on April 27, 2009. Oral argument is scheduled for November 3, 2009.

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Louisiana Generating, LLC
     On February 11, 2009, the U.S. Department of Justice acting at the request of the U.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC in federal district court in the Middle District of Louisiana alleging violations of the Clean Air Act, or CAA, at the Big Cajun II power plant. This is the same matter for which Notices of Violation, or NOVs, were issued to Louisiana Generating, LLC on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990’s, several years prior to NRG’s acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the best available control technology, or BACT, to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint includes a request for an injunction to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA’s Prevention of Significant Deterioration program; (vi) award to the Department of Justice its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.
     On April 27, 2009, Louisiana Generating, LLC made several filings. It filed an objection in the Cajun Electric Cooperative Power, Inc.’s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. It also filed a complaint in the same bankruptcy proceeding in the same court seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for the violations alleged in the February 11, 2009 lawsuit to the extent that such claims are determined to have merit. On June 8, 2009, the parties filed a joint status report setting forth their views of the case and proposing a trial schedule. On June 18, 2009, Louisiana Generating, LLC filed a motion to bifurcate the Department of Justice lawsuit into separate liability and remedy phases, and on June 30, 2009, the Department of Justice filed its opposition. On August 24, 2009, Louisiana Generating, LLC filed a motion to dismiss this lawsuit, and on September 25, 2009, the Department of Justice filed its opposition to the motion to dismiss. A new federal bankruptcy judge was appointed on October 9, 2009.
Citizens for Clean Power
     On November 6, 2008, Citizens for Clean Power, or CCP, filed a notice of its intent to file a lawsuit under the CAA against Indian River Power, LLC, or IRP, seeking to enforce opacity limitations applicable to units 1, 2, 3, and 4. On January 5, 2009, the Delaware Department of Natural Resources and Environmental Control, or DNREC, filed a lawsuit relating to opacity issues against IRP in the Superior Court in Kent County, Delaware. On January 6, 2009, DNREC and IRP agreed to a consent order resolving the DNREC action in which IRP agreed to pay a $5,000 civil penalty and agreed to purchase for DNREC’s use an Ultrafine Particle Monitor for approximately $60,000. The consent order was filed with the court on February 6, 2009, and entered by the court on February 13, 2009, thereby precluding CCP’s ability under the CAA to commence its noticed lawsuit. On February 26, 2009, notwithstanding the entry of the consent order, CCP filed a complaint against IRP in federal district court in Delaware. On March 25, 2009, IRP filed a motion to dismiss the complaint, on April 7, 2009, CCP filed its opposition, and on April 20, 2009, IRP filed its reply. On July 23, 2009, the court dismissed the matter, thereby ending the case.

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Excess Mitigation Credits
     From January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or EMCs, to its monthly charges to retail electric providers as ordered by the Public Utility Commission of Texas, or PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers’ monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI, totaled $385 million for RERS’s “Price to Beat” Customers. It is unclear what the actual number may be. “Price to Beat” was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT’s order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment with the Court of Appeals for the Third District of Texas with the first such appeal filed on the same date as the state district court judgment and the last such appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District reversed the lower court’s decision ruling that CenterPoint Energy’s stranded cost recovery should exclude only EMCs credited to RERS for its “Price to Beat” customers. On June 2, 2008, CenterPoint Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Court agreed to consider the CenterPoint Energy appeal as well as two related petitions for review filed by other entities. Oral argument occurred on October 6, 2009.
     In November 2008, CenterPoint Energy and RRI, on behalf of itself and affiliates including RERS, agreed to suspend unexpired deadlines, if any, related to limitations periods that might exist for possible claims against REI and its affiliates if CenterPoint Energy is ultimately not allowed to include in its stranded cost calculation those EMCs previously credited to RERS. Regardless of the outcome of the Texas Supreme Court proceeding, NRG believes that any possible future CenterPoint Energy claim against RERS for EMCs credited to RERS would lack legal merit. No such claim has been filed.
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. 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.
     As of December 21, 2008, the reserve held approximately $9.8 million in cash and 1,282,783 shares of common stock. On December 21, 2008, the Company issued an instruction letter to The Bank of New York Mellon to distribute all remaining cash and stock in the Disputed Claims Reserve to NRG’s creditors. On January 12, 2009, The Bank of New York Mellon commenced the distribution of all remaining cash and stock in the Disputed Claim Reserve to the Company’s creditors pursuant to NRG’s Chapter 11 bankruptcy plan and on July 13, 2009, that distribution was complete.

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Note 16 — 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 power markets are subject to ongoing legislative and regulatory changes that may impact NRG’s wholesale and retail businesses.
     In addition to the regulatory proceedings noted below, NRG and its subsidiaries are a party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. 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.
     PJM — By Order dated March 17, 2009, the U.S. Court of Appeals for the DC Circuit denied the remaining appeals of the FERC orders establishing the Reliability Pricing Model, or RPM capacity market. In February of 2009, the entities representing load interests, 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, agreed to withdraw their appeals regarding the establishment of the RPM market design.
     On June 18, 2009, FERC denied rehearing of its order dated September 19, 2008, dismissing a complaint filed by the Maryland Public Service Commission, or MDPSC, together with other load interests, against PJM challenging the results of the RPM transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint had sought 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 August 14, 2009, the MDPSC and the New Jersey Board of Public Utilities filed an appeal of FERC’s orders to the U.S. Court of Appeals for the Fourth Circuit, and a successful appeal could disrupt the auction-determined results and create a refund obligation for market participants.
     Retail (Replacement Reserve) — On November 14, 2006, Constellation Energy Commodities Group, or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through September 27, 2006. Specifically, Constellation disputed approximately $4 million in under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong protocol. Reliant Energy Power Supply, or REPS, other market participants, ERCOT, and PUCT staff opposed Constellation’s complaint. On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation’s complaint. On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other. On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the trial court’s decision. If all appeals are unsuccessful, on remand to the PUCT, it would determine the appropriate methodology for giving effect to the trial court’s decision. It is not known at this time whether only Constellation’s under-scheduling charges, the under-scheduling charges of all other QSEs that disputed REPS charges for the same time frame, the entire market, or some other approach would be used for any resettlement.
     Under the PUCT ordered formula, Qualified Scheduling Entities, or QSEs, who under-scheduled capacity within any of ERCOT’s four congestion zones were assessed under-scheduling charges which defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving QSEs. Under the Court’s decision, all RPRS costs would be assigned to all load-serving QSEs based upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled capacity. If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS costs, REPS’s share of the total RPRS costs allocated to QSEs would increase.

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Note 17 — 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 United States. 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 gases, or GHGs, 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 from 2010 through 2013 to meet NRG’s environmental commitments will be approximately $900 million and are primarily associated with controls on the Company’s Big Cajun and Indian River facilities. 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. This estimate reflects anticipated schedules and controls related to the Clean Air Interstate Rule, or CAIR, Maximum Achievable Control Technology, or MACT, for mercury, and the Phase II 316(b) Rule which are under remand to the U.S. EPA, and, as such, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined at this time.
Northeast Region
     NRG operates electric generating units located in Connecticut, Delaware, Maryland, Massachusetts and New York which are subject to RGGI. These units must surrender one allowance for every U.S. ton of CO2 emitted with true up for 2009-2011 occurring in 2012. Allowances are partially allocated only in the state of Delaware. In 2008, NRG emitted approximately 12 million tonnes of CO2 in RGGI states, although 2009 is tracking lower than 2008 year to date. NRG believes that to the extent CO2 will not be fully reflected in wholesale electricity prices, the direct financial impact on the Company is likely to be negative as costs will be incurred in the course of securing the necessary RGGI allowances and offsets at auction and in the market.
     In January 2006, NRG’s Indian River Operations, Inc. received a letter of informal notification from the DNREC stating that the Company may be a potentially responsible party with respect to a historic captive landfill. On October 1, 2007, NRG signed an agreement with the DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, the DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would adequately address shoreline erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study is completed, the Company is unable to predict the impact of any required remediation.
     On May 29, 2008, the DNREC requested that NRG’s Indian River Operations, Inc. 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 assessment phase.
South Central Region
     On February 11, 2009, the U.S. Department of Justice acting at the request of the U.S. EPA commenced a lawsuit against Louisiana Generating, LLC in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to Louisiana Generating, LLC on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be found in Note 15, Commitments and Contingencies, to this Form 10-Q, Louisiana Generating, LLC.

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Note 18 — 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, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. 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. The Company is also obligated with respect to customer deposits associated with Reliant Energy.
     This Note 18 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, 2008.
     In connection with the agreement to sell its 50% ownership interest in Mibrag B.V., NRG executed an agreement guaranteeing the performance of its subsidiary Lambique Beheer under the purchase and sale agreement. This agreement indemnifies the buyer for tax, environmental liability and other matters, as well as breaches of representations and warranties and is limited to EUR 206 million.
     NRG signed a guarantee agreement on behalf of its subsidiary NRG Retail, LLC guaranteeing the payment and performance of its obligations under the LLC Membership Interest Purchase Agreement and related agreements with RRI in connection with the purchase of its retail business, including purchase price and acquired net working capital. In accordance with the LLC Membership Interest Purchase Agreement, on May 1, 2009, NRG signed an agreement guaranteeing payments up to $85 million related to the Restated Power Purchase Agreement with FPL Energy Upton Wind II, LLC. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.
     In connection with the October 5, 2009 amendment of the CSRA, NRG signed guarantee agreements on behalf of its subsidiary NRG Retail, LLC guaranteeing performance under power purchase and sales contracts. See Note 20, Subsequent Event, to this Form 10-Q for further discussion of the CSRA Amendment.

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Note 19 — Condensed Consolidating Financial Information
     As of September 30, 2009, the Company had outstanding $1.2 billion of 7.25% Senior Notes due 2014, $2.4 billion of 7.375% Senior Notes due 2016, $1.1 billion of 7.375% Senior Notes due 2017, and $700 million of 8.50% Senior Notes due 2019. The Senior Notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries. On October 5, 2009, RERH became a guarantor subsidiary as a result of the CSRA Amendment. See Note 20, Subsequent Event, to this Form 10-Q , for a discussion of the CSRA Amendment.
     Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2009:
     
Arthur Kill Power LLC
  NRG Devon Operations Inc.
Astoria Gas Turbine Power LLC
  NRG Dunkirk Operations, Inc.
Berrians I Gas Turbine Power LLC
  NRG El Segundo Operations Inc.
Big Cajun II Unit 4 LLC
  NRG Generation Holdings, Inc.
Cabrillo Power I LLC
  NRG Huntley Operations Inc.
Cabrillo Power II LLC
  NRG International LLC
Chickahominy River Energy Corp.
  NRG Kaufman LLC
Commonwealth Atlantic Power LLC
  NRG Mesquite LLC
Conemaugh Power LLC
  NRG MidAtlantic Affiliate Services Inc.
Connecticut Jet Power LLC
  NRG Middletown Operations Inc.
Devon Power LLC
  NRG Montville Operations Inc.
Dunkirk Power LLC
  NRG New Jersey Energy Sales LLC
Eastern Sierra Energy Company
  NRG New Roads Holdings LLC
El Segundo Power, LLC
  NRG North Central Operations, Inc.
El Segundo Power II LLC
  NRG Northeast Affiliate Services Inc.
GCP Funding Company LLC
  NRG Norwalk Harbor Operations Inc.
Hanover Energy Company
  NRG Operating Services Inc.
Hoffman Summit Wind Project LLC
  NRG Oswego Harbor Power Operations Inc.
Huntley IGCC LLC
  NRG Power Marketing LLC
Huntley Power LLC
  NRG Rocky Road LLC
Indian River IGCC LLC
  NRG Saguaro Operations Inc.
Indian River Operations Inc.
  NRG South Central Affiliate Services Inc.
Indian River Power LLC
  NRG South Central Generating LLC
James River Power LLC
  NRG South Central Operations Inc.
Kaufman Cogen LP
  NRG South Texas LP
Keystone Power LLC
  NRG Texas LLC
Lake Erie Properties Inc.
  NRG Texas C & I Supply LLC
Langford Wind Power, LLC
  NRG Texas Holding Inc.
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
  Reliant Energy Services Texas LLC
NEO Freehold-Gen LLC
  Reliant Energy Texas Retail LLC
NEO Power Services Inc.
  Saguaro Power LLC
New Genco GP LLC
  San Juan Mesa Wind Project II, LLC
Norwalk Power LLC
  Somerset Operations Inc.
NRG Affiliate Services Inc.
  Somerset Power LLC
NRG Arthur Kill Operations Inc.
  Texas Genco Financing Corp.
NRG Asia-Pacific Ltd.
  Texas Genco GP, LLC
NRG Astoria Gas Turbine Operations Inc.
  Texas Genco Holdings, Inc.
NRG Bayou Cove LLC
  Texas Genco LP, LLC
NRG Cabrillo Power Operations Inc.
  Texas Genco Operating Services, LLC
NRG Cadillac Operations Inc.
  Texas Genco Services, LP
NRG California Peaker Operations LLC
  Vienna Operations, Inc.
NRG Cedar Bayou Development Company LLC
  Vienna Power LLC
NRG Connecticut Affiliate Services Inc.
  WCP (Generation) Holdings LLC
NRG Construction LLC
  West Coast Power LLC

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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, the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commission’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. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2009
                                         
                    NRG Energy,            
    Guarantor   Non-Guarantor   Inc.           Consolidated
(In millions)
  Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations (a)   Balance
 
Operating Revenues
                                       
Total operating revenues
  $   1,216     $   1,854     $   (1 )   $   (153 )   $   2,916  
 
Operating Costs and Expenses
                                       
Cost of operations
    749       1,301       (1 )     (156 )     1,893  
Depreciation and amortization
    160       51       1             212  
Selling, general and administrative
    16       78       88             182  
Acquisition-related transaction and integration costs
                6             6  
Development costs
    1       1       10             12  
 
Total operating costs and expenses
    926       1,431       104       (156 )     2,305  
 
Operating Income/(Loss)
    290       423       (105 )     3       611  
Other Income/(Expense)
                                       
Equity in earnings of consolidated subsidiaries
                592       (592 )      
Equity in earnings of unconsolidated affiliates
    3       3                   6  
Other income/(loss), net
    2       2       4       (3 )     5  
Interest expense
    (5 )     (38 )     (135 )           (178 )
 
Total other (expense)/income
          (33 )     461       (595 )     (167 )
 
Income/(Losses) Before Income Taxes
    290       390       356       (592 )     444  
Income tax expense/(benefit)
    (51 )     139       78             166  
 
Net Income/(Loss)
    341       251       278       (592 )     278  
Less: Net loss attributable to noncontrolling interest
                             
 
Net Income/(Loss) attributable to NRG Energy, Inc.
  $   341     $   251     $   278     $   (592 )   $   278  
 
 
(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, 2009
                                         
                    NRG Energy,            
    Guarantor   Non-Guarantor   Inc.           Consolidated
(In millions)
  Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations (a)   Balance
 
Operating Revenues
                                       
Total operating revenues
  $   3,807     $   3,203     $   31     $   (230 )   $   6,811  
 
Operating Costs and Expenses
                                       
Cost of operations
    2,043       2,088       3       (233 )     3,901  
Depreciation and amortization
    475       115       4             594  
Selling general and administrative
    50       132       214             396  
Acquisition-related transaction and integration costs
                41             41  
Development costs
    5       6       23             34  
 
Total operating costs and expenses
    2,573       2,341       285       (233 )     4,966  
 
Operating Income/(Loss)
    1,234       862       (254 )     3       1,845  
Other Income/(Expense)
                                       
Equity in earnings of consolidated subsidiaries
    129             1,466       (1,595 )      
Equity in earnings of unconsolidated affiliates
    7       26                   33  
Gain on sale of equity method investment
          128                   128  
Other income/(loss), net
    5       (17 )     6       (3 )     (9 )
Interest expense
    (71 )     (97 )     (307 )           (475 )
 
Total other income/(expense)
    70       40       1,165       (1,598 )     (323 )
 
Income/(Losses) Before Income Taxes
    1,304       902       911       (1,595 )     1,522  
Income tax expense
    298       314       2             614  
 
Net Income/(Loss)
    1,006       588       909       (1,595 )     908  
Less: Net loss attributable to noncontrolling interest
    (1 )                       (1 )
 
Net Income/(Loss) attributable to NRG Energy, Inc.
  $   1,007     $   588     $   909     $   (1,595 )   $   909  
 
 
(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, 2009
                                         
            Non-                
    Guarantor   Guarantor   NRG Energy, Inc.           Consolidated
(In millions)
  Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations (a)   Balance
 
ASSETS
 
                                       
Current Assets
                                       
Cash and cash equivalents
  $   11     $   418     $   1,821     $       $   2,250  
Funds deposited by counterparties
    293                         293  
Restricted cash
    1       25                   26  
Accounts receivable, net
    355       764                   1,119  
Inventory
    518       15                   533  
Derivative instruments valuation
    2,517       1,010             (328 )     3,199  
Deferred income taxes
    (489 )     248       342             101  
Cash collateral paid in support of energy risk management activities
    222       253                   475  
Prepayments and other current assets
    166       71       243       (265 )     215  
 
Total current assets
    3,594       2,804       2,406       (593 )     8,211  
 
Net property, plant and equipment
    10,597       970       43             11,610  
 
Other Assets
                                       
Investment in subsidiaries
    530       221       16,955       (17,706 )      
Equity investments in affiliates
    35       357                   392  
Capital leases and notes receivable, less current portion
    4,621       507       3,018       (7,639 )     507  
Goodwill
    1,718                         1,718  
Intangible assets, net
    795       1,145       33       (31 )     1,942  
Nuclear decommissioning trust fund
    354                         354  
Derivative instruments valuation
    795       460       9       (225 )     1,039  
Other non-current assets
    37       9       135             181  
 
Total other assets
    8,885       2,699       20,150       (25,601 )     6,133  
 
Total Assets
  $   23,076     $   6,473     $   22,599     $   (26,194 )   $   25,954  
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
                                       
Current portion of long-term debt and capital leases
  $   67     $   505     $   32     $   (67 )   $   537  
Accounts payable
    (625 )     1,111       239             725  
Derivative instruments valuation
    1,971       1,370       4       (328 )     3,017  
Cash collateral received in support of energy risk management activities
    293                         293  
Accrued expenses and other current liabilities
    270       273       291       (198 )     636  
 
Total current liabilities
    1,976       3,259       566       (593 )     5,208  
 
Other Liabilities
                                       
Long-term debt and capital leases
    2,580       890       12,398       (7,639 )     8,229  
Nuclear decommissioning reserve
    296                         296  
Nuclear decommissioning trust liability
    249                         249  
Deferred income taxes
    670       111       791             1,572  
Derivative instruments valuation
    315       679       90       (225 )     859  
Out-of-market contracts
    229       126             (31 )     324  
Other non-current liabilities
    425       26       687             1,138  
 
Total non-current liabilities
    4,764       1,832       13,966       (7,895 )     12,667  
 
Total liabilities
    6,740       5,091       14,532       (8,488 )     17,875  
 
3.625% Preferred Stock
                247             247  
Stockholders’ Equity
    16,336       1,382       7,820       (17,706 )     7,832  
 
Total Liabilities and Stockholders’ Equity
  $   23,076     $   6,473     $   22,599     $   (26,194 )   $   25,954  
 
 
(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, 2009
                                         
            Non-   NRG Energy,              
    Guarantor   Guarantor   Inc.           Consolidated
(In millions)
  Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations (a)   Balance
 
Cash Flows from Operating Activities
                                       
Net income
  $   1,006     $   588     $   909     $   (1,595 )   $   908  
Adjustments to reconcile net income to net cash provided by operating activities:
                                       
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries
    194       (26 )     (1,136 )     935       (33 )
Depreciation and amortization
    475       115       4             594  
Provision for bad debts
          37                   37  
Amortization of nuclear fuel
    28                         28  
Amortization of financing costs and debt discount/premiums
          11       24             35  
Amortization of intangibles and out-of-market contracts
    (65 )     144                   79  
Changes in deferred income taxes and liability for unrecognized tax benefits
    (46 )     6       601             561  
Changes in nuclear decommissioning liability
    19                         19  
Changes in derivatives
    (32 )     (202 )                 (234 )
Changes in collateral deposits supporting energy risk management activities
    266       (253 )                 13  
Loss on sale of assets
    2                         2  
Gain on sale of equity method investment
          (128 )                 (128 )
Gain on sale of emission allowances
    (8 )                       (8 )
Gain recognized on settlement of pre-existing relationship
                (31 )           (31 )
Amortization of unearned equity compensation
                20             20  
Changes in option premiums collected
    (266 )     (12 )                 (278 )
Cash provided by/(used by) changes in other working capital
    614       248       (1,166 )           (304 )
 
Net Cash Provided/(Used) by Operating Activities
    2,187       528       (775 )     (660 )     1,280  
 
Cash Flows from Investing Activities
                                       
Intercompany (loans to)/receipts from subsidiaries
    (1,395 )           159       1,236        
Acquisition of Reliant Energy, net of cash acquired
          (68 )     (288 )           (356 )
Investment in Reliant Energy
          200       (200 )            
Capital expenditures
    (409 )     (149 )     (2 )           (560 )
(Increase)/decrease in restricted cash, net
    6       (16 )                 (10 )
Decrease/(increase) in notes receivable
          (53 )     35             (18 )
Purchases of emission allowances
    (68 )                       (68 )
Proceeds from sale of emission allowances
    20                         20  
Investments in nuclear decommissioning trust fund securities
    (237 )                       (237 )
Proceeds from sales of nuclear decommissioning
trust fund securities
    218                         218  
Proceeds from sale of assets, net
    6                         6  
Other investment
    (1 )           (5 )           (6 )
Proceeds from sale of equity method investment
          284                   284  
 
Net Cash (Used)/Provided by Investing Activities
    (1,860 )     198       (301 )     1,236       (727 )
 
Cash Flows from Financing Activities
                                       
Proceeds from intercompany loans
    (188 )     29       1,395       (1,236 )      
Payment from intercompany dividends
    (330 )     (330 )           660        
Payment of dividends to preferred stockholders
                (27 )           (27 )
Net payments to settle acquired derivatives that include financing elements
    166       (306 )                 (140 )
Payment for treasury stock
                (250 )           (250 )
Proceeds from issuance of common stock, net of issuance costs
                1             1  
Installment proceeds from sale of noncontrolling interest in subsidiary
          50                   50  
Proceeds from issuance of long-term debt
    38       116       689             843  
Payment of deferred debt issuance costs
          (2 )     (27 )           (29 )
Payment of short and long-term debt
          (27 )     (221 )           (248 )
 
Net Cash (Used)/Provided by Financing Activities
    (314 )     (470 )     1,560       (576 )     200  
Effect of exchange rate changes on cash and cash equivalents
          3                   3  
 
Net Increase in Cash and Cash Equivalents
    13       259       484             756  
Cash and Cash Equivalents at Beginning of Period
    (2 )     159       1,337             1,494  
 
Cash and Cash Equivalents at End of Period
  $   11     $   418     $   1,821     $       $   2,250  
 
(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, 2008
                                         
                    NRG Energy,              
    Guarantor   Non-Guarantor   Inc.           Consolidated
(In millions)
  Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations (a)   Balance
 
Operating Revenues
                                       
Total operating revenues
  $   2,519     $   111     $       $   (18 )   $   2,612  
 
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)
    1,434       (11 )     (52 )           1,371  
Other Income/(Expense)
                                       
Equity in earnings/(losses) of consolidated subsidiaries
    52       50       868       (970 )      
Equity in earnings of unconsolidated affiliates
    1       57                   58  
Other income/(loss), net
    4       11       (22 )           (7 )
Interest expense
    (46 )     (17 )     (79 )           (142 )
 
Total other income/(expense)
    11       101       767       (970 )     (91 )
 
Income/(Loss) From Continuing Operations Before Income Taxes
    1,445       90       715       (970 )     1,280  
Income tax expense/(benefit)
    527       38       (63 )           502  
 
Income/(Loss) From Continuing Operations
    918       52       778       (970 )     778  
Net Income/(Loss) attributable to NRG Energy, Inc.
  $   918     $   52     $   778     $   (970 )   $   778  
 
 
(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
  $ 4,942     $ 306     $     $ (18 )   $ 5,230  
 
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)
    1,844       39       (206 )     1       1,678  
Other Income/(Expense)
                                       
Equity in earnings/(losses) of consolidated subsidiaries
    262             1,313       (1,575 )      
Equity in (losses)/earnings of unconsolidated affiliates
    (2 )     37                   35  
Other income/(loss), net
    19       10       (14 )     (1 )     14  
Interest expense
    (148 )     (56 )     (238 )           (442 )
 
Total other income/(expense)
    131       (9 )     1,061       (1,576 )     (393 )
 
Income/(Loss) From Continuing Operations Before Income Taxes
    1,975       30       855       (1,575 )     1,285  
Income tax expense/(benefit)
    694       5       (196 )           503  
 
Income/(Loss) From Continuing Operations
    1,281       25       1,051       (1,575 )     782  
Income/(loss) from discontinued operations, net of income taxes
          269       (97 )           172  
 
Net Income/(Loss) attributable to NRG Energy, Inc.
  $ 1,281     $ 294     $ 954     $ (1,575 )   $ 954  
 
(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, 2008
                                         
            Non-                    
    Guarantor   Guarantor   NRG Energy,           Consolidated
(In millions)   Subsidiaries   Subsidiaries   Inc.   Eliminations (a)   Balance
 
ASSETS
Current Assets
                                       
Cash and cash equivalents
  $ (2 )   $ 159     $ 1,337     $     $ 1,494  
Funds deposited by counterparties
                754             754  
Restricted cash
    7       9                   16  
Accounts receivable, net
    422       42                   464  
Inventory
    443       12                   455  
Derivative instruments valuation
    4,600                         4,600  
Cash collateral paid in support of energy risk management activities
    494                         494  
Prepayments and other current assets
    130       37       278       (230 )     215  
 
Total current assets
    6,094       259       2,369       (230 )     8,492  
 
Net Property, Plant and Equipment
    10,725       791       29             11,545  
 
Other Assets
                                       
Investment in subsidiaries
    651             11,949       (12,600 )      
Equity investments in affiliates
    26       464                   490  
Capital leases and note receivable, less current portion
    598       435       3,177       (3,775 )     435  
Goodwill
    1,718                         1,718  
Intangible assets, net
    797       16       2             815  
Nuclear decommissioning trust fund
    303                         303  
Derivative instruments valuation
    870             15             885  
Other non-current assets
    9       4       112             125  
 
Total other assets
    4,972       919       15,255       (16,375 )     4,771  
 
Total Assets
  $ 21,791     $ 1,969     $ 17,653     $ (16,605 )   $ 24,808  
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
                                       
Current portion of long-term debt and capital leases
  $ 67     $ 235     $ 229     $ (67 )   $ 464  
Accounts payable
    (1,302 )     429       1,324             451  
Derivative instruments valuation
    3,976       3       2             3,981  
Deferred income taxes
    503       31       (333 )           201  
Cash collateral received in support of energy risk management activities
    760                         760  
Accrued expenses and other current liabilities
    507       48       333       (164 )     724  
 
Total current liabilities
    4,511       746       1,555       (231 )     6,581  
 
Other Liabilities
                                       
Long-term debt and capital leases
    2,730       1,014       7,729       (3,776 )     7,697  
Nuclear decommissioning reserve
    284                         284  
Nuclear decommissioning trust liability
    218                         218  
Deferred income taxes
    705       (187 )     672             1,190  
Derivative instruments valuation
    348       46       114             508  
Out-of-market contracts
    291                         291  
Other non-current liabilities
    405       44       220             669  
 
Total non-current liabilities
    4,981       917       8,735       (3,776 )     10,857  
 
Total liabilities
    9,492       1,663       10,290       (4,007 )     17,438  
 
3.625% Preferred Stock
                247             247  
Stockholders’ Equity
    12,299       306       7,116       (12,598 )     7,123  
 
Total Liabilities and Stockholders’ Equity
  $ 21,791     $ 1,969     $ 17,653     $ (16,605 )   $ 24,808  
 
(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
  $ 1,281     $ 294     $ 954     $ (1,575 )   $ 954  
Adjustments to reconcile net income to net cash provided by operating activities
                                       
Distributions and equity (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries
    (260 )     (26 )     (1,313 )     1,575       (24 )
Depreciation and amortization
    454       21       3             478  
Amortization of nuclear fuel
    31                         31  
Amortization of financing costs and debt discount/ premiums
          11       17             28  
Amortization of intangibles and out-of-market contracts
    (226 )                       (226 )
Changes in deferred income taxes and liability for unrecognized tax benefits
    102       (21 )     358             439  
Changes in nuclear decommissioning liability
    8                         8  
Changes in derivatives
    (135 )     (9 )                 (144 )
 
Changes in collateral deposits supporting energy risk management activities
    (320 )                       (320 )
Loss on sale 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  
Changes in option premiums collected
    203                         203  
Cash provided by/(used by) changes in other working capital
    377       52       (479 )           (50 )
 
Net Cash Provided by/(Used) by Operating Activities
    1,476       49       (439 )           1,086  
 
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/(increase) in notes receivable
          35       (15 )           20  
Purchases of emission allowances
    (6 )                       (6 )
Proceeds from sale of emission allowances
    75                         75  
Investments in nuclear decommissioning trust fund securities
    (441 )                       (441 )
Proceeds from sales of nuclear decommissioning trust fund securities
    434                         434  
Proceeds from sale of discontinued operations and assets, net of cash divested
          (59 )     300             241  
Proceeds from sale of assets
    14                         14  
Equity investment in unconsolidated affiliate
                (17 )           (17 )
 
Net Cash (Used)/Provided 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 )
Net payments to settle acquired derivatives that include financing elements
    (49 )                       (49 )
Payment for CSF I CAGR settlement
          (45 )                 (45 )
Payments for treasury stock
                (185 )           (185 )
Proceeds from issuance of common stock, net of issuance costs
                8             8  
Installment proceeds from sale of noncontrolling interest on 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 (Used)/Provided by Financing Activities
    (931 )     197       (422 )     710       (446 )
Change in cash from discontinued operations
          43                   43  
Effect of exchange rate changes on cash and cash equivalents
                             
 
Net Increase in Cash and Cash Equivalents
    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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Note 20 — Subsequent Event
  Unwind of the Merrill Lynch Credit Sleeve
      The Company executed an amendment of the existing CSRA with Merrill Lynch, or CSRA Amendment, which became effective October 5, 2009. The CSRA Amendment removed the first liens associated with the CSRA, and RERH subsequently became a guarantor of the Company’s obligations under its Senior Notes. See Note 19, Condensed Consolidating Financial Information, to this Form 10-Q for further discussion of NRG’s guarantees under its Senior Notes.
      In connection with the CSRA Amendment, NRG net settled or offset certain REPS transactions with counterparties and received $165 million in net cash consideration. Merrill Lynch returned $250 million of previously posted cash collateral and released liens on $322 million of unrestricted cash held at Reliant Energy.
      Pursuant to the CSRA Amendment, the Company was required to post collateral for any net liability derivatives and other static margin associated with supply for Reliant Energy. In connection with this transaction, NRG posted $366 million of cash collateral to Merrill Lynch and other counterparties, returned $53 million of counterparty collateral, issued letters of credit of $206 million, and received $45 million in counterparty collateral. The funds posted by the Company were sourced from a portion of the proceeds from the June 5, 2009 issuance of the 2019 Senior Notes. See Note 8, Long-Term Debt, to this Form 10-Q, for further discussion of the 2019 Senior Notes. In addition, $25 million outstanding under NRG’s $50 million working capital facility with Merrill Lynch was repaid, and the facility was terminated. See Note 4, Business Acquisition, to this Form 10-Q, for further discussion of the working capital facility entered into on May 1, 2009.
     NRG has also paid Merrill Lynch $5 million in connection with the CSRA Amendment, and will make a second payment of $5 million on January 4, 2010. Merrill Lynch has terminated NRG’s contingent equity obligations under the previous credit sleeve. The parties have agreed to settle any outstanding wholesale obligations under the CSRA Amendment by January 29, 2010, and any C&I related Merrill Lynch obligations by April 30, 2010.

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ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     In this discussion and analysis, NRG discusses and explains its financial condition and results of operations, including:
    Factors which affect the Company’s business;
 
    NRG’s earnings and costs in the periods presented;
 
    Changes in earnings and costs between periods;
 
    Impact of these factors on NRG’s overall financial condition;
 
    A discussion of new and ongoing initiatives that may affect NRG’s future results of operations and financial condition;
 
    Expected future expenditures for capital projects; and
 
    Expected sources of cash for future operations and capital expenditures.
     As you read this discussion and analysis, refer to the Company’s Condensed Consolidated Statements of Operations, which present the results of operations for the three and nine months ended September 30, 2009, and 2008. NRG analyzes and explains the differences between periods in the specific line items of NRG’s Condensed Consolidated Statements of Operations. Also refer to NRG’s 2008 Annual Report on Form 10-K, which includes detailed discussions of various items impacting the Company’s business, results of operations and financial condition, including:
    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 and Estimates section.
The discussion and analysis below has been organized as follows:
    Executive Summary, including introduction and overview, business strategy, and changes to the business environment during the period including regulatory and environmental matters;
 
    Results of operations beginning with an overview of the Company’s consolidated results, followed by a more detailed discussion of those results by operating segment;
 
    Financial condition addressing liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements; and
 
    Known trends that may affect NRG’s results of operations and financial condition in the future, including the Reliant Energy acquisition and the disposition of the MIBRAG investment.
Executive Summary
Introduction and Overview
     NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company with a significant presence in major competitive power markets in the United States, as well as a major retail electricity franchise in the ERCOT (Texas) market. NRG is engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, the trading of energy, capacity and related products in the United States and select international markets, and supply of electricity and energy services to retail electricity customers in the Texas market.
     As of September 30, 2009, NRG had a total global generation portfolio of 187 active operating fossil fuel and nuclear generation units, at 46 power generation plants, with an aggregate generation capacity of approximately 24,100 MW, and approximately 550 MW under construction which includes partners’ interests of 200 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in two operating wind farms representing an aggregate generation capacity of 270 MW, which includes partner interests of 75 MW. Within the U.S., NRG has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 23,095 MW of fossil fuel and nuclear generation capacity in 179 active generating units at 42 plants. The Company’s power generation facilities are most heavily concentrated in Texas (approximately 11,190 MW, including 195 MW from the two wind farms), the Northeast (approximately 7,015 MW), South Central (approximately 2,840 MW), and West (approximately 2,130 MW) regions of the U.S., and approximately 115 MW of additional generation capacity from the Company’s thermal assets.

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     NRG’s principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired, nuclear and wind facilities, representing approximately 46%, 32%, 16%, 5% and 1% of the Company’s total domestic generation capacity, respectively. In addition, 11% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option.
     NRG’s domestic generation facilities consist of intermittent, baseload, intermediate and peaking power generation facilities, the ranking of which is referred to as Merit Order, and include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company’s revenues and provides a stable source of cash flow. 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.
     On May 1, 2009, NRG acquired Reliant Energy, which is the second largest mass market electricity provider to residential and commercial customers in Texas. Based on metered locations, as of September 30, 2009, Reliant Energy had approximately 1.6 million Mass customers and approximately 0.1 million C&I customers. Reliant Energy arranges for the transmission and delivery of electricity to customers, bills customers, collects payments for electricity sold and maintains call centers to provide customer service.
NRG’s Business Strategy
     NRG’s business strategy is intended to maximize shareholder value over time through the production and the sale of safe, reliable and affordable power to its customers and in the markets served by the Company, while aggressively pursuing sustainable energy solutions for the future. The key to successful implementation of this strategy is the Company’s sizable fleet of wholesale power generation assets in the U.S., its leading retail franchise in Texas and, increasingly, its position as an industry leader in the development of various types of low and no carbon generation technologies and integrated solutions aimed at satisfying the Company’s customers’ increasing demand for sustainable energy lifestyles. In addition, NRG utilizes its asset base as a platform for growth and development and as a source of cash flow generation which can be used for the return of capital to debt and equity holders. More specifically, the Company’s strategy is focused on: (i) top decile operating performance of its existing operating assets and enhanced operating performance of the Company’s commercial operations and hedging program; (ii) repowering of power generation assets at existing sites and development of new power generation projects; (iii) empowering retail customers with distinctive products and services that transform how they use, manage, and value energy; (iv) investment in energy-related new businesses and new technologies being developed and deployed in response to the twin societal dynamics to foster sustainability and combat climate change; and (v) engaging in a proactive capital allocation plan focused on achieving the regular return of capital to stockholders within the dictates of prudent balance sheet management. This strategy is supported by the Company’s five major initiatives (FORNRG, RepoweringNRG, econrg, Future NRG and NRG Global Giving) which are designed to enhance the Company’s competitive advantages in these strategic areas and enable the Company to convert the challenges faced by the power industry in the coming years into opportunities for financial growth. This strategy is being implemented by focusing on the following principles, which are more fully described in the Company’s 2008 Annual Report on Form 10-K:
     Operational Performance — The Company is focused on increasing value from its existing assets, primarily through the Company’s FORNRG 2.0 initiative, commercial operations strategy, achieving synergies between the Company’s retail and wholesale business in Texas, and maintaining of appropriate levels of liquidity, debt and equity in order to ensure continued access to capital through all economic and financial cycles.
     Development NRG is favorably positioned to pursue growth opportunities through expansion of its existing generating capacity and development of new generating capacity at its existing facilities, primarily through the Company’s RepoweringNRG initiative. NRG expects that these efforts will provide some or all of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; improved ability to dispatch economically across the regional general portfolio; increased technological and fuel diversity; and reduced environmental impacts, including facilities that either have near zero GHG emissions or can be equipped to capture and sequester GHG emissions. In addition, several of the Company’s original RepoweringNRG projects or projects commenced under that initiative since its inception may qualify for financial support under the infrastructure financing component of the American Recovery and Reinvestment Act and NRG has several applications pending or contemplated.

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     New Businesses and New Technology NRG is focused on the development and investment in energy-related new businesses and new technologies where the benefits of such investments represent significant commercial opportunities and create a comparative advantage for the Company, including low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, photovoltaic, “clean” coal and gasification, and the retrofit of post-combustion carbon capture technologies. A primary focus of this strategy is supported by the econrg initiative whereby NRG is pursuing investments in new generating facilities and technologies that are expected to be highly efficient and will employ no and low carbon technologies to limit CO2 emissions and other air emissions. While the Company’s effort in this regard to date has focused on businesses and technologies applicable to the centralized power station, the acquisition of Reliant Energy has put the Company in a position to consider and pursue sustainable energy lifestyles, such as smart meters, electric vehicle ecosystems, and distributed “clean” solutions.
     Company-Wide Initiatives — In addition, the Company’s overall strategy is also supported by Future NRG and NRG Global Giving initiatives, which address workforce planning and community involvement and support, respectively.
     Finally, NRG will continue to pursue selective acquisitions, joint ventures and divestitures to enhance its asset mix and competitive position in the Company’s core markets. NRG intends to concentrate on opportunities that present attractive risk-adjusted returns. NRG will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures.
Business Environment
Financial Credit Market Availability
     Power generation companies are capital intensive and, as such, rely on the credit markets for liquidity and for the financing of power generation investments. During the first nine months of 2009, the nation’s credit markets have recovered to some extent although credit continued to be tight relative to years prior to 2008. As evidence of the markets’ improvement, in April 2009, GenConn Energy, a joint venture of NRG and the United Illuminating Company, closed on a $534 million project financing and NRG was able to issue $700 million of bonds in June 2009, with a 10 year maturity at a yield to maturity of 8.75%. NRG has a diversified liquidity program, with $3.9 billion in total liquidity as of September 30, 2009, excluding funds deposited by counterparties, 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 transacts with a diversified pool of counterparties and actively manages the Company’s exposure to any single counterparty. See Part I, Item 2 — Liquidity and Capital Resources, and Part I, Item 3 — Quantitative and Qualitative Disclosures about Market Risk for further discussion.
     The addition of Reliant Energy to NRG’s existing generation business may provide opportunities to match generation to load directly which should reduce hedging and credit costs that both businesses would incur if hedged separately. Reliant Energy, which expects to lock in its wholesale supply in order to secure its margin as load is contracted, should also benefit from having better access to nonstandard products necessary to meet load. NRG expects to continue hedging its wholesale production consistent with its prior practice, but now will benefit from having an additional outlet for its range of generation products.
Proposed Over-the-Counter Derivative Legislation
     Congress is currently considering legislative proposals that would significantly increase the regulation of over-the-counter derivatives including those related to energy commodities, through the amendment of the Commodity Exchange Act. While NRG cannot predict at this time the outcome of any of the legislative efforts, many of the proposals generally contemplate mandatory clearing of such derivatives through clearing organizations and the increased standardization of contracts, products, and collateral requirements. Such changes could negatively impact NRG’s ability to hedge its portfolio in an efficient, cost-effective manner, and, among other things, may limit NRG’s ability to utilize liens as collateral. Such changes may also result in a decrease in liquidity in the commodity markets.

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Unsolicited Exelon Proposal
     On October 19, 2008, the Company received an unsolicited proposal from Exelon Corporation to acquire all of the outstanding shares of the Company and on November 12, 2008, Exelon announced a tender offer for all of the Company’s outstanding common stock. NRG’s Board of Directors, after carefully reviewing the proposal, unanimously concluded that the proposal was not in the best interests of the stockholders and recommended that NRG stockholders not tender their shares. In addition, on June 17, 2009, Exelon filed a Definitive Proxy Statement with the SEC with respect to their proposals for the Company’s 2009 Annual Meeting of Stockholders, which consisted of: (i) consideration of Exelon’s four nominees as Class III directors; (ii) consideration of the expansion of NRG’s Board of Directors to 19 directors; (iii) if the Exelon board expansion is approved, consideration of five additional Exelon nominees; and (iv) consideration of repealing any amendments to the NRG Bylaws after February 26, 2008. NRG’s Board of Directors recommended a vote against each of the proposals. On July 2, 2009, Exelon revised their unsolicited proposal and NRG’s Board of Directors, after carefully reviewing the proposal, unanimously concluded that the proposal was not in the best interests of the stockholders and recommended that NRG stockholders not tender their shares. On July 21, 2009, based on the preliminary vote count at NRG’s 2009 Annual Meeting of Stockholders, stockholders voted to re-elect all of the Company’s director nominees to the NRG Board of Directors. In addition, NRG’s stockholders rejected Exelon’s proposal to expand NRG’s Board with its own slate of five Director nominees. On July 21, 2009, Exelon Corporation announced that in light of the vote results, effective immediately, it terminated its offer to acquire all of the outstanding shares of NRG. On July 29, 2009, IVS Associates, Inc., the independent inspector of elections, certified the final results. The total defense costs associated with Exelon’s unsolicited proposal was approximately $39 million for the period October 1, 2008, through September 30, 2009, of which $31 million was for the nine months ended September 30, 2009.
Environmental Matters
Climate Change
     Senators Kerry and Boxer introduced climate legislation based on The American Clean Energy and Security Act of 2009 which passed the House of Representatives in June 2009. The Senate bill proposes a multi-sector, market based greenhouse gas cap-and-trade system starting in 2012. It provides for a declining cap in U.S. GHG emissions and provides for the allocation of allowances to merchant coal generators, the use of both international and domestic offsets to local distribution companies , and a transition from already existing state programs, all of which are important to the electric generation industry. It proposes requirements for new coal-fueled power plants to implement, based on commercial availability, carbon capture and sequestration to reduce CO2 emissions. NRG will continue to provide input as a leading energy company and member of the U.S. Climate Action Partnership, or USCAP, in support of federal legislation.
     In 2008, NRG emitted 60 million metric tonnes of CO2 from its domestic operations. If climate change legislation or some other federal comprehensive climate change bill were to pass both Houses of Congress and be enacted into law, the actual impact on the Company’s financial performance would depend on a number of factors, including the overall level of GHG reductions required under any final legislation, the degree to which offsets may be used for compliance and their price and availability, and the extent to which NRG would be entitled to receive CO2 emissions allowances without having to purchase them in an auction or on the open market. Thereafter, the impact would depend on the level of success of the Company’s multifold strategy, which includes (i) shaping public policy with the objective being constructive and effective federal GHG regulatory policy; and (ii) pursuing its RepoweringNRG and econrg programs. The Company’s multifold strategy is discussed in greater detail in Part I, Item 1 — Business, Carbon Update in NRG’s 2008 Annual Report on Form 10-K.
     On April 24, 2009, the U.S. EPA published a proposed endangerment finding that stated that the mix of six key GHGs, including CO2, threaten the public health and welfare. On September 28, 2009, U.S.EPA and Department of Transportation, or DOT published “Proposed GHG Emissions Standards for Motor Vehicles”. These actions are in response to the Supreme Court’s decision in Massachusetts v. U.S. EPA, which requires the U.S. EPA to decide under the CAA’s mobile source title whether GHGs contribute to climate change, and if so, promulgate appropriate regulations. Under the CAA, these regulations when final, would render GHGs regulated pollutants and subject them to other existing requirements that affect stationary sources, including power plants. The primary impact on NRG would be a statutory requirement to install BACT determined on a case-by-case basis, for major modifications or improvements at power plants if they cause GHG emissions to increase by the statutory Prevention of Significant Deterioration, or PSD limits of 100 tons per year. The U.S. EPA also released, on September 30, 2009, a draft PSD tailoring rule for GHGs that would increase the major stationary source threshold of 25,000 tons per year of carbon dioxide equivalents. This threshold level would be used to determine (i) if an existing source would be required to obtain a Title V operating permit and (ii) if a new facility or a major modification at an existing facility would trigger PSD permitting requirements. Existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit and install BACT. The timing of the final motor vehicle rule, acceptance of the PSD tailoring rule and EPA’s approach to BACT for GHGs could affect the level of impact to NRG’s plants and future repowering projects.

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Federal Environmental Initiatives
     A number of regulations are under review by U.S. EPA including CAIR, MACT, National Ambient Air Quality Standards, or NAAQS, for ozone, nitrogen dioxide, SO2, small particle matter, or PM2.5, and the Phase II 316(b) Rule. These rules address air emissions and best practices for units with once-through-cooling. In addition, the U.S. EPA has announced that it is considering new rules regarding the handling and disposition of coal combustion byproducts. While the Company cannot predict the requirements in the final versions nor the ultimate effect that the changing regulations will have on NRG’s business, NRG’s planned environmental capital expenditures include 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 Phase II 316(b) Rule. NRG continues to explore cost-effective alternatives that can achieve desired results. This planned investment reflects anticipated schedules and controls related to CAIR, MACT for mercury, and the Phase II 316(B) Rule which are under remand to the U.S. EPA and, as such, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined at this time.
     On April 24, 2009, the U.S. EPA granted petitions to reconsider three NSR rules; Fugitive Emissions, PM2.5 Implementation, and Reasonable Possibility. A Notice for reconsideration of the PM2.5 Implementation Rule was published in the Federal Register on May 1, 2009. While none of these actions directly impact NRG at this point, it is unknown if any such final rules will impact future projects.
     The U.S. Supreme Court released its decision in the Phase II 316(b) Rule case on April 1, 2009, in which it concluded that the U.S. EPA does have the authority to allow a cost-benefit analysis in the evaluation of Best Technology Available, or BTA. This ruling is favorable for the industry and NRG as it improves the U.S. EPA’s ability to include alternatives to closed-loop cooling in its redraft of the Phase II 316(b) Rules. In the absence of federal regulations, some states in which NRG operates, such as California, Connecticut, Delaware and New York, are moving ahead with guidance for more stringent requirements for once through cooled units which may have an impact on future operations.
Regional Environmental Initiatives
     Northeast Region — NRG operates electric generating units located in Connecticut, Delaware, Maryland, Massachusetts and New York which are subject to RGGI. The RGGI CO2 cap-and-trade program went into effect on January 1, 2009. An allowance must be surrendered for every U.S. ton of CO2 emitted with true up for 2009-2011 occurring in 2012. NRG’s emissions under RGGI were approximately 12 million tonnes in 2008.
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. NRG is also subject to regulatory requirements as a competitive retail electric service provider in Texas. The 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.
West Region
     California — The CAISO Market Redesign and Technology Update, or MRTU, commenced April 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 generally be a positive development for its assets in the region, but additional time is needed to assess the impact of MRTU.

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Texas Region
     On October 6, 2008, as part of its determination of Competitive Renewable Energy Zones, or CREZ, the PUCT issued its final order approving 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 transmission expansion plan is composed of approximately 2,300 miles of new 345 kV lines and 42 miles of new 138 kV lines. In January 2009, Texas Industrial Energy Consumers, a trade organization composed of large industrial customers, appealed the PUCT’s CREZ plan in state district court, seeking reversal of the final order. On March 30, 2009, the PUCT issued a final order designating the transmission utilities that plan to construct the various CREZ transmission component projects. A large number of separate transmission licensing proceedings will be required prior to construction of the CREZ facilities. In July of 2009, the PUCT approved schedules for utilities to file applications to license several of the CREZ transmission projects (to obtain certificates of convenience and necessity, or CCNs). If the CREZ projects are completed as currently anticipated, the transmission upgrades and associated wind generation could impact wholesale energy and ancillary service prices in ERCOT. As part of the normal ERCOT five-year planning process, transmission utilities are also planning other system improvements, 2,800 circuit miles of transmission and more than 17,000 MVA of autotransformer capacity, intended to support increasing power demand and to address transmission congestion in the ERCOT Region.
Changes in Accounting Standards
     See Note 2, Summary of Significant Accounting Policies, to the condensed consolidated financial statements of this Form 10-Q as found in Item 1 for a discussion of recent accounting developments.

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     Consolidated Results of Operations
     The following table provides selected financial information for the Company:
                                                 
    Three months ended September 30,   Nine months ended September 30,
(In millions except otherwise noted)   2009   2008   Change %   2009   2008   Change %
Operating Revenues
                                               
Energy revenue
  771     1,373       (44 )%   2,383     3,671       (35 )%   
Capacity revenue
    278       356       (22 )     791       1,037       (24 )
Retail revenue
    1,876             N/A       3,126             N/A  
Risk management activities
    6       744       (99 )     431       27       N/A  
Contract amortization
    (60 )     76       (179 )     (92 )     233       (139 )
Thermal revenue
    22       26       (15 )     77       85       (9 )
Other revenues
    23       37       (38 )     95       177       (46 )
 
Total operating revenues
    2,916       2,612       12       6,811       5,230       30  
Operating Costs and Expenses
                                               
Cost of sales
    1,628       780       109       3,256       2,133       53  
Risk management activities
    (16 )           N/A       (152 )           N/A  
Other cost of operations
    281       217       29       797       679       17  
 
Total cost of operations
    1,893       997       90       3,901       2,812       39  
Depreciation and amortization
    212       156       36       594       478       24  
Selling, general and administrative
    182       75       143       396       233       70  
Acquisition-related transaction and integration costs
    6             N/A       41             N/A  
Development costs
    12       13       (8 )     34       29       17  
 
Total operating costs and expenses
    2,305       1,241       86       4,966       3,552       40  
 
Operating Income
    611       1,371       (55 )     1,845       1,678       10  
Other Income/(Expense)
                                               
Equity in earnings of unconsolidated affiliates
    6       58       (90 )     33       35       (6 )
Gain on sale of equity method investments
                      128             N/A  
Other income/(loss), net
    5       (7 )     171       (9 )     14       (164 )
Interest expense
    (178 )     (142 )     25       (475 )     (442 )     7  
 
Total other expense
    (167 )     (91 )     84       (323 )     (393 )     (18 )
 
Income from Continuing Operations before income tax expense
    444       1,280       (65 )     1,522       1,285       18  
Income tax expense
    166       502       (67 )     614       503       22  
 
Income from Continuing Operations
    278       778       (64 )     908       782       16  
Income from discontinued operations, net of income taxes
                            172       N/A  
 
Net Income
    278       778       (64 )     908       954       (5 )
 
Less: Net loss attributable to noncontrolling interest
                      (1 )           N/A  
 
Net income attributable to NRG Energy, Inc.
  278     778       (64 )   909     954       (5 )
 
Business Metrics
                                               
 
Average natural gas price - Henry Hub ($/MMBtu)
    3.15       9.11       (65 )%     3.80       9.67       (61 )%
 
 
N/A —  Not Applicable

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Management’s discussion of the results of operations for the three months ended September 30, 2009, and 2008:
     For the benefit of the following discussions, the table below represents the results of NRG excluding the impact of Reliant Energy during the three months ended September 30, 2009:
                                              
    Three months ended September 30,
            2009           2008    
                    Total excluding        
(In millions)   Consolidated   Reliant Energy   Reliant Energy   Consolidated   Change %
     
Operating Revenues
                                       
Energy revenue
  771         771     1,373       (44 )%
Capacity revenue
    278             278       356       (22 )
Retail revenue
    1,876       1,876                    
Risk management activities
    6       (1 )     7       744       (99 )
Contract amortization
    (60 )     (85 )     25       76       (67 )
Thermal revenue
    22             22       26       (15 )
Other revenues
    23             23       37       (38 )
     
Total operating revenues
    2,916       1,790       1,126       2,612       (57 )
Operating Costs and Expenses
                                       
Cost of sales
    1,628       1,203       425       780       (46 )
Risk management activities
    (16 )           (16 )           N/A  
Other operating costs
    281       60       221       217       2  
     
Total cost of operations
    1,893       1,263       630       997       (37 )
Depreciation and amortization
    212       42       170       156       9  
Selling, general and administrative
    182       76       106       75       41  
Acquisition-related transaction and integration costs
    6             6             N/A  
Development costs
    12             12       13       (8 )
     
Total operating costs and expenses
    2,305       1,381       924       1,241       (26 )
     
Operating Income
  611     409     202     1,371       (85 )%
        
Operating Revenues
     Operating revenues, excluding risk management activities, increased by $1.0 billion during the three months ended September 30, 2009, compared to the same period in 2008.
   
Retail revenue — the acquisition of Reliant Energy contributed $1.9 billion of retail revenue during the three months ended September 30, 2009. Retail revenue includes mass revenues of $1.2 billion, C&I revenues of $620 million, and supply management revenues of $99 million.
 
   
Energy revenue — decreased $602 million during the three months ended September 30, 2009, compared to the same period in 2008:
  o  
Texas — energy revenue decreased by $201 million, with $177 million of the decrease driven by lower energy prices and $24 million of the decrease driven by a reduction in generation. The average realized energy price decreased by 21%, driven by a 53% decrease in merchant prices offset by a 21% increase in contract prices. Generation decreased by 3% driven by an 11% decrease in coal plant generation and an 8% decrease in nuclear plant generation, offset by a 47% increase in gas plant generation, as well as generation from the recently constructed Cedar Bayou 4 gas plant and Elbow Creek wind farm, which was not in operation in 2008. Coal plant generation was adversely affected by lower energy prices driven by a 64% decrease in average natural gas prices.
 
  o  
Northeast — energy revenue decreased by $201 million, with $120 million driven by lower energy prices and $99 million attributable to a reduction in generation offset by an $18 million increase from higher net contract revenue. Average merchant energy prices were lower by 52%. The lower energy prices reduced the Company’s net cost incurred to meet obligations under load serving contracts in the PJM market. Generation decreased by 30% with a 34% decrease in coal generation and a 9% decrease in oil and gas generation. Weakened demand for power combined with lower gas prices resulting in reduced merchant energy prices. Lower merchant energy prices combined with higher costs of production from the introduction of RGGI resulting in increased hours where the coal plants were uneconomical to dispatch.

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  o  
South Central — energy revenue decreased by $55 million due to a $24 million decline in contract revenue coupled with a decrease of $31 million in merchant energy revenues. The decline in contract energy price was driven by a $7 million decrease in fuel cost pass through from the cooperatives and a $17 million decrease due to the expiration of a contract with a regional utility. Total MWh sales to the region’s contract customers were down 7% while the average realized price on contract energy sales was $22.83 per MWh in 2009 compared to $29.19 per MWh in 2008. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower average prices resulting in a $31 million decline in revenue. Megawatt hours sold to the merchant market increased by 18% as increased use of the region’s tolled facility provided additional energy to the merchant market while prices fell by 61%.
  o  
Intercompany energy revenue — intercompany sales of $144 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.
   
Capacity revenue — decreased $78 million during the three months ended September 30, 2009, compared to the same period in 2008:
  o  
Texas — capacity revenue decreased by $79 million due to a lower proportion of baseload contracts which contained a capacity component.
 
  o  
South Central — capacity revenue increased by a $12 million primarily resulting from a new capacity agreement.
 
  o  
Intercompany capacity revenue — intercompany sales of $18 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.
   
Contract amortization revenue — decreased by $136 million in the three months ended September 30, 2009, as compared to the same period in 2008. The decrease includes $85 million in amortization expense of net in-market C&I contracts related to the Reliant Energy acquisition in 2009 and a reduction of $52 million in revenue from the Texas Genco acquisition due to the lower volume of contracted energy.
 
   
Other revenues — decreased by $14 million driven by $15 million in lower ancillary revenue and $13 million in lower emissions revenues. These decreases were offset by a $12 million increase in fuels trading.
Cost of Operations
     Cost of operations, excluding risk management activities, increased $912 million during the three months ended September 30, 2009, compared to the same period in 2008.
   
Cost of sales — increased $848 million during the three months ended September 30, 2009, compared to the same period in 2008 due to:
  o  
Retail — Reliant Energy incurred $1.2 billion of cost of energy during the three months ended September 30, 2009. Supply costs were $837 million which included $162 million of intercompany supply costs. Transmission and distribution charges totaled $392 million for the period. These costs were offset by $11 million of contract amortization for net out-of-market supply contracts.
 
  o  
Texas — cost of energy decreased $81 million due to lower natural gas and coal costs. Natural gas costs decreased $84 million, reflecting a 64% decline in average natural gas per MMBtu prices offset by a 47% increase in gas-fired generation. Coal costs decreased $7 million due to 11% lower generation. In addition, a $19 million decrease in ancillary service costs was offset by a $13 million increase in purchased energy and other fuel costs.
 
  o  
Northeast — cost of energy decreased $86 million due to a $53 million reduction in natural gas and oil costs and a $39 million reduction in coal costs. Natural gas and oil costs decreased due to 67% lower average natural gas prices and 9% lower generation. Coal costs decreased by $33 million due to 34% lower coal generation and by $6 million due to lower prices. These decreases were offset by a $6 million increase in costs related to RGGI which became effective in 2009.
 
  o  
South Central — cost of energy decreased $52 million primarily due to a $35 million decrease in purchased energy reflecting lower fuel costs associated with energy from the region’s tolled facility and a $14 million decrease in natural gas costs reflecting 88% lower generation and 61% lower average gas prices.
 
  o  
Intercompany cost of sales — intercompany purchases of $162 million by Reliant Energy from the Company’s Texas region is eliminated in consolidation.

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Other cost of operations — increased $64 million during the three months ended September 30, 2009, compared to the same period in 2008. Reliant Energy incurred $37 million related to customer service operations and $24 million in gross receipt tax on revenue.
Risk Management Activities
     Risk management activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total derivative gains decreased by $722 million during the three months ended September 30, 2009, compared to the same period in 2008. The breakdown of changes by region follows:
                                                                 
    Three months ended September 30, 2009
    Reliant                   South                
(In millions)   Energy   Texas   Northeast   Central   West   Thermal   Elimination   Total
 
Net gains/(losses) on settled positions, or financial income in revenues
      116     118     (2 )   (3 )   2     (8 )   223  
 
Mark-to-market results in revenues
                                                               
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
          (4 )     (27 )           1                   (30 )
Reversal of gain positions acquired as part of the Reliant Energy acquisition as of May 1, 2009
    (1 )                                         (1 )
Reversal of previously recognized unrealized gains on settled positions related to trading activity
          (8 )     (4 )     (9 )                       (21 )
Net unrealized gains/(losses) on open positions related to economic hedges
          (95 )     (70 )           (7 )     1       15       (156 )
Net unrealized gains/(losses) on open positions related to trading activity
          5       2       (16 )                       (9 )
 
Subtotal mark-to-market results
    (1 )     (102 )     (99 )     (25 )     (6 )     1       15       (217 )
 
Total derivative gain/(loss) included in revenues
  (1 )   14     19     (27 )   (9 )   3     7     6  
 
                                                 
    Three months ended September 30, 2009
    Reliant                   South        
(In millions)   Energy   Texas   Northeast   Central   Elimination   Total
 
Net gains/(losses) on settled positions, or financial expense in cost of operations
  (202 )   (4 )   (1 )   (1 )   21     (187 )
 
Mark-to-market results in cost of operations
                                               
Reversal of previously recognized unrealized losses on settled positions related to economic hedges
          11       20                   31  
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009
    239                               239  
Net unrealized gains/(losses) on open positions related to economic hedges
    (21 )     (18 )     3       (16 )     (15 )     (67 )
 
Subtotal mark-to-market results
    218       (7 )     23       (16 )     (15 )     203  
 
Total derivative gain/(loss) included in cost of operations
  16     (11 )   22     (17 )   6     16  
 
                                 
    Three months ended September 30, 2008
                    South    
(In millions)   Texas   Northeast   Central   Total
 
Net losses on settled positions, or financial income
  (44 )   (43 )   (4 )   (91 )
 
Mark-to-market results
                               
Reversal of previously recognized unrealized gains on settled positions related to economic hedges
    (5 )     (2 )           (7 )
Reversal of previously recognized unrealized gains on settled positions related to trading activity
          (6 )     (3 )     (9 )
Net unrealized gains on open positions related to economic hedges
    590       201             791  
Net unrealized gains on open positions related to trading activity
    11       18       31       60  
 
Subtotal mark-to-market results
    596       211       28       835  
 
Total derivative gain included in revenue
    552       168       24       744  
 
Total derivative gain included in cost of operations
               
 

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     NRG’s third quarter 2009 net gain of $22 million was comprised of $14 million of mark-to-market losses and $36 million in settled gains. Of the $14 million of mark-to-market losses, there was a loss of $217 million in revenue and a gain of $203 million in expense. The $217 million loss in revenue included a $51 million loss from the reversal of mark-to-market gains recognized during 2008 and loss of $165 million due to the decrease in value of forward purchases and sales of electricity and fuel due to higher forward power and gas prices. The $203 million of mark-to-market gains in expense included a gain of $31 million from the reversal of mark-to-market losses recognized during 2008, a $67 million loss due to the decrease in value of forward purchases and sales of electricity and fuel due to higher forward power and gas prices, and a $239 million from the roll-off of Reliant Energy loss positions. The Reliant Energy loss positions were acquired as of May 1, 2009 and valued using forward prices on that date. The $239 million roll-off amounts were offset by realized losses at settled prices and are reflected in the cost of operations during the same period.
     NRG’s third quarter 2008 net gain of $744 million was comprised of mark-to-market gains of $835 million and $91 million in settled losses, or financial income. The realized losses were primarily driven by increases in settled power and gas prices. The mark-to-market gains were primarily driven by decreases in forward power and gas prices, and gains from a reduction in hedge accounting ineffectiveness.
     Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of operations, the changes in such results should not be viewed in isolation, but rather should be taken together with the effects of pricing and cost changes on energy revenue and costs. During and prior to 2009, NRG hedged a portion of the Company’s 2008 and 2009 generation. During the third quarter 2009, the settled prices of electricity and natural gas decreased resulting in the recognition of realized gains while the forward prices of electricity and natural gas increased resulting in the recognition of unrealized mark-to-market losses. During the third quarter 2008, the settled prices for power and gas increased resulting in the recognition of realized losses while decreasing forward prices of electricity and natural gas resulted in recognition of unrealized mark-to-market gains.
     The following table represents the results of the Company’s financial and physical trading of energy commodities for the three months ended September 30, 2009 and 2008. The realized financial trading results and unrealized financial and physical trading results are included in the risk management activities above, while the realized physical trading results are included in energy revenue.
                 
    Three months ended  
    September 30,  
(In millions)   2009     2008  
 
Trading gains/(losses)
               
Realized
  $ 27     $ 13  
Unrealized
    (30 )     52  
 
Total trading gains/(losses)
    (3 )     65  
 
Depreciation and Amortization
     NRG’s depreciation and amortization expense increased by $56 million for the three months ended September 30, 2009, compared to the same period in 2008. Reliant Energy’s depreciation and amortization expense for the three month period was $42 million principally for amortization of customer relationships. The balance of the increase was due to depreciation on the baghouse projects in western New York and the Elbow Creek project which came online in late 2008, and the Cedar Bayou 4 project which came online in the second quarter 2009.
Selling, General and Administrative Expenses
     Selling, general and administrative expenses increased by $107 million for the three months ended September 30, 2009, compared to the same period in 2008. The increase was due to:
   
Retail selling, general and administrative expense — totaled $76 million, including $28 million of bad debt expense incurred during the three months ended September 30, 2009.
 
   
Consultant costs — increased $18 million consisting of non-recurring costs related to Exelon’s exchange offer and proxy contest efforts of $21 million offset by a decrease in other consulting costs of $3 million.
 
   
Wage and benefits expense — increased $13 million.
Acquisition-Related Transaction and Integration Costs
     NRG incurred Reliant Energy acquisition-related transaction costs of $2 million and integration costs of $4 million for the three months ended September 30, 2009.

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Equity in Earnings of Unconsolidated Affiliates
     NRG’s equity earnings from unconsolidated affiliates decreased by $52 million for the three months ended September 30, 2009, compared to the same period in 2008. During the three months ended September 30, 2009, there was no equity earnings from the Sherbino I Wind Farm LLC, or Sherbino, investment. In the three months ended September 30, 2008, Sherbino recognized a $40 million mark-to-market gain on a natural gas swap executed to hedge its future power generation. Additionally, in 2009, the Company’s share in its former MIBRAG investments and Gladstone Power Station decreased $10 million and $4 million, respectively, while the Company’s share in NRG Saguaro LLC earnings increased by $2 million.
Other Income/(Loss), Net
     NRG’s other income/(loss), net increased $12 million for the three months ended September 30, 2009, compared to the same period in 2008. The 2009 interest income was lower compared to 2008 due to reduced interest rates. The effect of lower interest income in 2009 was offset by the effect of $19 million impairment charge in 2008 to restructure distressed investments in commercial paper.
Interest Expense
     NRG’s interest expense increased by $36 million for the three months ended September 30, 2009, compared to the same period in 2008. This increase was primarily due to a $15 million increase in fees incurred on the CSRA facility which began in May 2009, a $15 million increase in interest expense as a result of the 2019 Senior Notes issued in June 2009, a $4 million increase related to ineffective portion of the interest rate cash flow hedge on the Company’s Term Loan Facility and a $5 million increase in the amortization of deferred financing costs. These increases were offset by a $7 million decrease in interest expense on the Company’s Term Loan Facility due to a decrease in the outstanding notional amount and lower interest rates related to the unhedged portion of the Term Loan and fair value portion of the Senior Notes.
Income Tax Expense
     NRG’s income tax expense decreased by $336 million for the three months ended September 30, 2009, compared to the same period in 2008. The decrease in income tax expense was primarily due to a decrease in income. The effective tax rate was 37.4% and 39.2% for the three months ended September 30, 2009, and 2008, respectively.
     For the three months ended September 30, 2009, NRG’s overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to the U.S. taxation of foreign earnings offset by a reduction in the valuation allowance. For the three months ended September 30, 2008, NRG’s effective tax rate was increased primarily due to the impact of state and local income taxes.

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Management’s discussion of the results of operations for the nine months ended September 30, 2009, and 2008:
     For the benefit of the following discussions, the table below represents the results of NRG excluding the impact of Reliant Energy during the nine months ended September 30, 2009:
                                              
    Nine months ended September 30,
            2009           2008    
                    Total excluding        
(In millions)   Consolidated   Reliant Energy   Reliant Energy   Consolidated   Change %
     
Operating Revenues
                                       
Energy revenue
  $   2,383     $       $   2,383     $   3,671       (35 )%
Capacity revenue
    791             791       1,037       (24 )
Retail revenue
    3,126       3,126                    
Risk management activities
    431       (1 )     432       27       N/A  
Contract amortization
    (92 )     (160 )     68       233       (71 )
Thermal revenue
    77             77       85       (9 )
Other revenues
    95             95       177       (46 )
     
Total operating revenues
    6,811       2,965       3,846       5,230       (26 )
Operating Costs and Expenses
                                       
Cost of sales
    3,256       2,022       1,234       2,133       (42 )
Risk management activities
    (152 )     (205 )     53             N/A  
Other operating costs
    797       101       696       679       3  
     
Total cost of operations
    3,901       1,918       1,983       2,812       (29 )
Depreciation and amortization
    594       85       509       478       6  
Selling, general and administrative
    396       125       271       233       16  
Acquisition-related transaction and integration costs
    41             41             N/A  
Development costs
    34             34       29       17  
     
Total operating costs and expenses
    4,966       2,128       2,838       3,552       (20 )
     
Operating Income
  $   1,845     $   837     $   1,008     $   1,678       (40 )%
     
Operating Revenues
     Operating revenues, excluding risk management activities, increased $1.2 billion during the nine months ended September 30, 2009, compared to the same period in 2008.
   
Retail revenue — the acquisition of Reliant Energy contributed $3.1 billion of retail revenue during the five months ended September 30, 2009. Retail revenue includes mass revenues of $1.9 billion, C&I revenues of $1.1 billion, and supply management revenues of $151 million.
 
   
Energy revenue — decreased $1.3 billion during the nine months ended September 30, 2009, compared to the same period in 2008:
  o  
Texas — energy revenue decreased by $478 million, with $373 million driven by lower average realized energy prices and a $105 million decrease driven by a reduction in generation. The average realized energy price decreased by 17%, driven by a 52% decrease in merchant prices, offset by a 23% increase in contract prices. Lower merchant prices were driven by the combination of lower gas prices in 2009 and unusually high pricing events that occurred in 2008 that did not repeat in 2009. Generation decreased by 5% driven by a 9% decrease in coal plant generation offset by a 6% increase in gas plant generation, and generation from the recently constructed Cedar Bayou 4 gas plant and Elbow Creek wind farm, which was not in operation in 2008. Coal plant generation was adversely affected by lower energy prices driven by a 66% decrease in average natural gas prices in combination with increased wind generation which shifted the coal unit’s position in the bid stack, negatively affecting coal plant generation.
 
  o  
Northeast — energy revenue decreased by $490 million, with $231 million driven by lower energy prices and $312 million attributable to a reduction in generation offset by a $53 million increase from higher net contract revenue. Merchant energy prices were lower by an average of 40%. The lower energy prices reduced the Company’s net cost incurred to meet obligations under load serving contracts in the PJM market. Generation decreased by 35%, with a 36% decrease in coal generation and a 28% decrease in oil and gas generation. Weakened demand for power combined with lower gas prices resulted in reduced merchant energy prices. Lower merchant energy prices combined with higher costs of production from the introduction of RGGI resulted in increased hours where the coal plants were uneconomical to dispatch. The decline in oil and gas generation is attributable to fewer reliability run hours at the Connecticut plants.

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  o  
South Central — decreased by $108 million due to a $66 million decline in contract revenue coupled with a $42 million decrease in merchant energy revenues. Contract customer sales volumes were down 10%. The decline in contract energy price was driven by a $12 million decrease in fuel cost pass through to the cooperatives. Also contributing to the decline in contract revenue was $48 million due to the expiration of a contract with a regional utility. Average realized price on contract energy sales was $23.04 per MWh in 2009 compared to $28.89 per MWh in 2008. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower average prices resulting in a $42 million decline in revenue. Megawatt hours sold to the merchant market increased by 41%, while prices fell by 50%. Increased use of the region’s tolled facility provided additional energy to the merchant market.
 
  o  
Intercompany energy revenue — intercompany sales of $199 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.
   
Capacity revenue — decreased $246 million during the nine months ended September 30, 2009, compared to the same period in 2008:
  o  
Texas — capacity revenue decreased by $222 million due to a lower proportion of baseload contracts which contained a capacity component.
 
  o  
Northeast — capacity revenue decreased by $12 million due to lower capacity prices in the NYISO.
 
  o  
South Central — capacity revenue increased by $30 million resulting primarily from a new capacity agreement.
 
  o  
Intercompany capacity revenue — intercompany sales of $29 million by the Company’s Texas region to Reliant Energy were eliminated in consolidation.
   
Contract amortization revenue — decreased by $325 million in the nine months ended September 30, 2009, as compared to the same period in 2008. The decrease includes a reduction of $166 million in revenue from the Texas Genco acquisition due to the lower volume of contracted energy and $160 million in amortization expense of net in-market C&I contracts related to the Reliant Energy acquisition in 2009.
 
   
Other revenues — decreased by $82 million driven by $45 million in lower ancillary revenue, $46 million in lower emissions revenue, and a $26 million decrease in fuels trading. These decreases were offset by the recognition of a $31 million non-cash gain related to settlement of a pre-existing in-the-money contract with Reliant Energy.
Cost of Operations
     Cost of operations, excluding risk management activities, increased $1.2 billion during the nine months ended September 30, 2009, compared to the same period in 2008.
   
Cost of sales — increased $1.1 billion during the nine months ended September 30, 2009, compared to the same period in 2008 due to:
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Retail — Reliant Energy incurred $1.8 billion of cost of energy during the five months ended September 30, 2009, which included $228 million of intercompany supply costs.
 
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Texas — cost of energy decreased $331 million due to lower natural gas, coal, purchased energy and ancillary services costs. Natural gas costs decreased $281 million, reflecting a 66% decline in average natural gas per MMBtu prices offset by a 6% increase in gas-fired generation. Coal costs decreased $17 million as the 2008 expense included a $15 million loss reserve related to a coal contract dispute and $6 million resulting from reduced generation. Ancillary service costs decreased by $41 million due to a decrease in purchased ancillary services costs incurred to meet contract obligations.
 
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Northeast — cost of energy decreased $254 million due to a $160 million reduction in natural gas and oil costs and a $108 million reduction in coal costs. Natural gas and oil costs decreased due to 28% lower generation and 60% lower average natural gas prices. Coal costs decreased due to 36% lower coal generation. These decreases were offset by a $15 million increase in costs related to RGGI which became effective in 2009.

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South Central — cost of energy decreased $71 million due to a $52 million decrease in purchased energy reflecting lower fuel costs associated with the region’s tolled facility and lower market energy prices, a $13 million decrease in natural gas cost, a $4 million decrease in coal costs and a $5 million decrease in transmission expense due to transmission line outages. The decrease in natural gas cost is attributable to a 32% decrease in gas generation and a 58% decrease in natural gas prices. The coal cost decreased due to a 7% decrease in generation offset by a 5% increase in price.
 
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West — cost of energy decreased $8 million due to a 43% decline in average natural gas per MMBtu prices offset by a 7% increase in natural gas consumption and a $2 million increase in fuel oil expense resulting from a write-down to market of fuel oil inventory no longer used in the production of energy.
 
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Intercompany cost of energy — intercompany purchases of $228 million by Reliant Energy from the Company’s Texas region were eliminated in consolidation.
   
Other cost of operations — increased $118 million during the nine months ended September 30, 2009, compared to the same period in 2008. Reliant Energy incurred $101 million which includes $62 million for customers service operations and $39 million for gross receipt tax on revenue. Further, operating and maintenance expenses increased by $6 million and property taxes increased by $11 million.
Risk Management Activities
     Risk management activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total derivative gains increased by $556 million during the nine months ended September 30, 2009, compared to the same period in 2008. The breakdown of changes by region follows:
                                                                 
    Nine months ended September 30, 2009  
    Reliant                     South                          
(In millions)   Energy     Texas     Northeast     Central     West     Thermal     Elimination     Total  
 
Net gains/(losses) on settled positions, or financial income in revenues
  $     $ 259     $ 274     $ 9     $ (6 )   $ 4     $ (9 )   $ 531  
 
Mark-to-market results in revenues
                                                               
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
          (41 )     (90 )           1       (2 )           (132 )
Reversal of gain positions acquired as part of the Reliant Energy acquisition as of May 1, 2009
    (1 )                                         (1 )
Reversal of previously recognized unrealized gains on settled positions related to trading activity
          (51 )     (27 )     (47 )                       (125 )
Net unrealized gains/(losses) on open positions related to economic hedges
          59       89       (4 )     (1 )     2       14       159  
Net unrealized gains/(losses) on open positions related to trading activity
          (3 )     6       (4 )                       (1 )
 
Subtotal mark-to-market results
    (1 )     (36 )     (22 )     (55 )                 14       (100 )
 
Total derivative gain/(loss) included in revenues
  $ (1 )   $ 223     $ 252     $ (46 )   $ (6 )   $ 4     $ 5     $ 431