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: JuneSeptember 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) 41-1724239
(I.R.S. Employer
Identification No.)
   
211 Carnegie Center Princeton, New Jersey
08540
(Address of principal executive offices) 08540
(Zip Code)
(609) 524-4500
(Registrant’s telephone number, including area code)
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such 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.
Yesþ   Noo
     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).
Yesoþ   Noo
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,”filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
       
Large accelerated filerþ
 Accelerated filero Non-accelerated filero Smaller reporting companyo
    (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).
Yeso   Noþ
     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.
Yesþ   Noo
      As of JulyOctober 28, 2009, there were 265,276,841256,409,300 shares of common stock outstanding, par value $0.01 per share.
 
 

 

 

TABLE OF CONTENTS

Index
     
Page No.
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
  3 
GLOSSARY OF TERMS
  4 
PART I — FINANCIAL INFORMATION
  89 
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
  89 
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
  5761 
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
105
ITEM 4 — CONTROLS AND PROCEDURES
  110 
ITEM 4 — CONTROLS AND PROCEDURES
115
PART II — OTHER INFORMATION
  111116 
ITEM 1 — LEGAL PROCEEDINGS
  111116 
ITEM 1A — RISK FACTORS
  111116 
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
  112116 
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
  112116 
ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  112116 
ITEM 5 — OTHER INFORMATION
  112117 
ITEM 6 — EXHIBITS
113
SIGNATURES
  114118 
SIGNATURES
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

2

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”,“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 thisthe 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;
•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 itsRepoweringNRG 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 itsFORNRG 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.
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 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.

3

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
 
ASCThe FASB Accounting Standards Codification, which the FASB has established as the source of authoritative U.S. GAAP
ASUAccounting 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
 
BACTBest Available Control Technology
BTA Best Technology Available
 
BTU British Thermal Unit
 
CAA Clean Air Act
CAGRCompound 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/institutionsinstitutional
 
CL&P The Connecticut Light & Power Company
 
CO2
 Carbon dioxide
 
CREZCompetitive Renewable Energy Zones
CS Credit Suisse Group
 
CSF I NRG Common Stock Finance I LLC
 
CSF II NRG Common Stock Finance II LLC
CSF CAGRsEmbedded derivatives within the CSF debt, individually referred to as CSF I CAGR and CSF II CAGR
CSF DebtCSF 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
 
EITF 07-5 EITF No. 07-5, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock”
EITF 08-5EITF No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement”
EITF 08-6EITF No. 08-6, “Equity Method Investment Accounting Considerations”
EITF 09-1EITF No. 09-1, “Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing”
 
EPC Engineering, Procurement and Construction
 
ERCOT Electric Reliability Council of Texas, the Independent System Operator and the Regional Reliability Coordinator of the various electricity systems within Texas
 
ESPP Employee Stock Purchase Plan
 
Exchange Act The Securities Exchange Act of 1934, as amended
 
FASB Financial Accounting Standards Board — the designated organization for establishing standards for financial accounting and reporting
 
FERC Federal Energy Regulatory Commission
 
FIN FASB Interpretation
FIN 46RFIN No. 46(R),“Consolidation of Variable Interest Entities (revised 2003)—an interpretation of ARB No. 51”
FIN 48FIN No. 48, “Accounting for Uncertainty in Income Taxes”
Fresh StartReporting requirements as defined by SOP 90-7
 
FSP FASB Staff Position
GHGGreenhouse Gases

4

   
  GLOSSARY OF TERMS (continued)
  
FSP FAS 107-1 and APB 28-1FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments”
FSP FAS 115-2 and FAS 124-2FSP No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”
FSP FAS 132R-1FSP No. FAS 132(R)-1,“Employers’ Disclosures about Postretirement Benefit Plan Assets”
FSP FAS 141R-1FSP No. FAS 141(R)-1,“Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”
FSP FAS 142-3FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Asset”
FSP FAS 157-2FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157”
FSP FAS 157-4FSP 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”
GHGGreenhouse Gases
Gross GenerationThe total amount of electric energy produced by generating units and measured at the generating terminal in kWh’s or MWh’s
 
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 BoardAtomic Licensing and Safety Board
LTIP Long-Term Incentive Plan
 
MACT Maximum Achievable Control Technology
 
Market usage adjustments The revenues and the related energy supply costs in the Reliant Energy segment includes the Company’s estimates of customer usage based on initial usage information provided by the independent system operators and the distribution companies. The Company revises these estimates and records any changes in the period as additional settlement information becomes available.
 
Mass Residential and small business
MDPSCMaryland 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
 
NEPOOL New England Power Pool

5

GLOSSARY OF TERMS (continued)
Net Capacity FactorThe net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.
 
Net Exposure Counterparty credit exposure to NRG, net of collateral
 
Net Generation The net amount of electricity produced, expressed in kWh’s or MWh’s, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation.
 
NINA Nuclear Innovation North America LLC
 
NOx
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
 
Padoma Padoma Wind Power LLC
 
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

5

 
PMIGLOSSARY 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
 
REPSReliant Energy Power Supply, LLC
RERHRERH 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
 
S&P Standard & Poor’s, a credit rating agency
 
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

6

   
SIFMA GLOSSARY OF TERMS (continued)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
 
SFAS 133 SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities”as amended
SFAS 141RSFAS No. 141 (revised 2007), “Business Combinations”
SFAS 157SFAS No. 157,“Fair Value Measurement”
SFAS 160SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements”
SFAS 161SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133”
SFAS 165SFAS No. 165, “Subsequent Events”
SFAS 167SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”
SFAS 168SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”
SherbinoSherbino I Wind Farm LLC
SO2
Sulfur dioxide
SOPStatement of Position issued by the American Institute of Certified Public Accountants
SOP 90-7Statement of Position 90-7,“Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”
 
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
 
Uprate A sustainable increase in the electrical rating of a generating facility
 
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.

6

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 105ASC-105,Generally Accepted Accounting Principles; incorporates:
•SFAS 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles
ASC 270ASC-270,Interim Reporting; incorporates:
•FSP FAS 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial Instruments
ASC 275ASC-275,Risks and Uncertainties,incorporates:
•FSP FAS 142-3,Determination of the Useful Life of Intangible Assets
ASC 320ASC-320,Investments-Debt and Equity Securities; incorporates:
•FSP FAS 115-2 and FAS 124-2,Recognition and Presentation of Other-Than-Temporary Impairments
ASC 323ASC-323,Investments-Equity Method and Joint Ventures; incorporates:
•EITF 08-6,Equity Method Investment Accounting Considerations
ASC 350ASC-350,Intangibles-Goodwill and Others; incorporates:
•FSP FAS 142-3,Determination of the Useful Life of Intangible Assets
ASC 450ASC-450,Contingencies
ASC 470ASC-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 715ASC-715,Compensation-Retirement Benefits,incorporates:
•FSP FAS 132 (R)-1,Employers’ Disclosures about Postretirement Benefit Plan Assets
ASC 718ASC-718,Compensation-Stock Compensation; incorporates:
•EITF 07-5,Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock
ASC 740ASC-740,Income Taxes
ASC 805ASC-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 810ASC-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 815ASC-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 820ASC-820,Fair Value Measurements and Disclosures; incorporates:
•FSP FAS 157-2,Effective Date of FASB Statement No. 157
•FSP FAS 157-4Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

7

•
EITF 08-5,Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement
ASC 825ASC-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 855ASC-855,Subsequent Events; incorporates:
•
SFAS 165,Subsequent Events
ASU 2009-5ASU 2009-5,Fair Value Measurement and Disclosures: Measuring Liabilities at Fair Value
ASU 2009-15ASU 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

8

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 June 30, Six months ended June 30, 
(In millions, except for per share amounts)
 2009  2008   2009  2008 
 
Operating Revenues
                 
Total operating revenues $2,237  $1,316   $3,895  $2,618 
 
Operating Costs and Expenses
                 
Cost of operations  1,242   1,011    2,008   1,815 
Depreciation and amortization  213   161    382   322 
Selling, general and administrative  131   83    214   158 
Acquisition-related transaction and integration costs  23   —    35   — 
Development costs  9   4    22   16 
 
Total operating costs and expenses  1,618   1,259    2,661   2,311 
Operating Income
  619   57    1,234   307 
 
Other Income/(Expense)
                 
Equity in earnings/(losses) of unconsolidated affiliates  5   (19)   27   (23)
Gain on sale of equity method investment  128   —    128   — 
Other (loss)/income, net  (11)  12    (14)  21 
Interest expense  (159)  (144)   (297)  (300)
 
Total other expense  (37)  (151)   (156)  (302)
 
Income/(Losses) From Continuing Operations Before Income Taxes
  582   (94)   1,078   5 
Income tax expense/(benefit)  150   (53)   448   1 
 
Income/(Losses) From Continuing Operations
  432   (41)   630   4 
Income from discontinued operations, net of income taxes  —   168    —   172 
 
Net Income
  432   127    630   176 
Less: Net loss attributable to noncontrolling interest  (1)  —    (1)  — 
 
Net income attributable to NRG Energy, Inc.
  433   127    631   176 
 
Dividends for preferred shares  7   14    21   28 
 
Income Available for NRG Energy, Inc. Common Stockholders
 $426  $113   $610  $148 
 
                  
Earnings per share attributable to NRG Energy, Inc. Common Stockholders
                 
Weighted average number of common shares outstanding — basic  253   236    245   236 
Income/(losses) from continuing operations per weighted average common share — basic $1.68  $(0.23)  $2.49  $(0.10)
Income from discontinued operations per weighted average common share — basic  —   0.71    —   0.73 
 
Net Income per Weighted Average Common Share — Basic
 $1.68  $0.48   $2.49  $0.63 
 
Weighted average number of common shares outstanding — diluted  275   236    275   236 
Income/(losses) from continuing operations per weighted average common share — diluted $1.56  $(0.23)  $2.27  $(0.10)
Income from discontinued operations per weighted average common share — diluted  —   0.71    —   0.73 
 
Net Income per Weighted Average Common Share — Diluted
 $1.56  $0.48   $2.27  $0.63 
 
                  
Amounts attributable to NRG Energy, Inc.:
                 
Income/(losses) from continuing operations, net of income taxes $433  $(41)  $631  $4 
Income from discontinued operations, net of income taxes  —   168    —   172 
 
Net Income
 $433  $127   $631  $176 
 
See notes to condensed consolidated financial statements.

8

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
          
 June 30, 2009  December 31, 2008 
(In millions, except shares)
 (unaudited)      
 
ASSETS
         
Current Assets
         
Cash and cash equivalents $2,282   $1,494 
Funds deposited by counterparties  468    754 
Restricted cash  19    16 
Accounts receivable, less allowance for doubtful accounts of $12 and $3, respectively  1,186    464 
Inventory  530    455 
Derivative instruments valuation  4,394    4,600 
Cash collateral paid in support of energy risk management activities  243    494 
Prepayments and other current assets  210    215 
 
Total current assets  9,332    8,492 
 
Property, plant and equipment, net of accumulated depreciation of $2,689 and $2,343, respectively
  11,609    11,545 
 
Other Assets
         
Equity investments in affiliates  363    490 
Capital leases and note receivable, less current portion  483    435 
Goodwill  1,718    1,718 
Intangible assets, net of accumulated amortization of $327 and $335, respectively  2,111    815 
Nuclear decommissioning trust fund  316    303 
Derivative instruments valuation  1,188    885 
Other non-current assets  185    125 
 
Total other assets  6,364    4,771 
 
Total Assets
 $27,305   $24,808 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
         
Current Liabilities
         
Current portion of long-term debt and capital leases $453   $464 
Accounts payable  857    451 
Derivative instruments valuation  4,196    3,981 
Deferred income taxes  46    201 
Cash collateral received in support of energy risk management activities  468    760 
Accrued expenses and other current liabilities  618    724 
 
Total current liabilities  6,638    6,581 
 
Other Liabilities
         
Long-term debt and capital leases  8,294    7,697 
Nuclear decommissioning reserve  292    284 
Nuclear decommissioning trust liability  217    218 
Deferred income taxes  1,564    1,190 
Derivative instruments valuation  906    508 
Out-of-market contracts  378    291 
Other non-current liabilities  914    669 
 
Total non-current liabilities  12,565    10,857 
 
Total Liabilities
  19,203    17,438 
 
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)  247    247 
Commitments and Contingencies
         
Stockholders’ Equity
         
Preferred stock (at liquidation value, net of issuance costs)  406    853 
Common stock  3    3 
Additional paid-in capital  4,561    4,350 
Retained earnings  3,033    2,423 
Less treasury stock, at cost — 17,200,777 and 29,242,483 shares, respectively  (532)   (823)
Accumulated other comprehensive income  372    310 
Noncontrolling interest  12    7 
 
Total Stockholders’ Equity
  7,855    7,123 
 
Total Liabilities and Stockholders’ Equity
 $27,305   $24,808 
 
                 
       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.

9

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)BALANCE SHEETS
         
(In millions)
      
Six months ended June 30,
 2009  2008 
 
Cash Flows from Operating Activities
        
Net income $631  $176 
Adjustments to reconcile net income to net cash provided by operating activities:        
Distributions and equity in (earnings)/losses of unconsolidated affiliates  (27)  32 
Depreciation and amortization  382   322 
Provision for bad debts  9   — 
Amortization of nuclear fuel  19   30 
Amortization of financing costs and debt discount/premiums  21   19 
Amortization of intangibles and out-of-market contracts  15   (147)
Changes in deferred income taxes and liability for unrecognized tax benefits  445   96 
Changes in nuclear decommissioning trust liability  15   17 
Changes in derivatives  (368)  669 
Changes in collateral deposits supporting energy risk management activities  245   (328)
(Gain)/loss on sale of assets  (1)  2 
Gain on sale of equity method investment  (128)  — 
Gain on sale of discontinued operations  —   (270)
Gain on sale of emission allowances  (9)  (42)
Gain recognized on settlement of pre-existing relationship  (31)  — 
Amortization of unearned equity compensation  13   14 
Changes in option premiums collected, net of acquisition  (270)  99 
Cash used by changes in other working capital, net of acquisition  (239)  (253)
 
Net Cash Provided by Operating Activities
  722   436 
 
Cash Flows from Investing Activities
        
Acquisition of Reliant Energy, net of cash acquired  (345)  — 
Capital expenditures  (374)  (409)
Increase in restricted cash, net  (3)  (1)
(Increase)/decrease in notes receivable  (11)  21 
Purchases of emission allowances  (52)  (4)
Proceeds from sale of emission allowances  15   61 
Investments in nuclear decommissioning trust fund securities  (172)  (285)
Proceeds from sales of nuclear decommissioning trust fund securities  157   269 
Proceeds from sale of discontinued operations and assets, net of cash divested  —   229 
Proceeds from sale of assets, net  6   14 
Proceeds from sale of equity method investment  284   — 
Other investment  (5)  — 
Equity investment in unconsolidated affiliates  —   (17)
 
Net Cash Used by Investing Activities
  (500)  (122)
 
Cash Flows from Financing Activities
        
Payment of dividends to preferred stockholders  (21)  (28)
Payment of financing element of acquired derivatives  (22)  (28)
Payment for treasury stock  —   (55)
Proceeds from issuance of common stock, net of issuance costs  —   8 
Proceeds from sale of noncontrolling interest in subsidiary  50   50 
Proceeds from issuance of long-term debt  820   10 
Payment of deferred debt issuance costs  (29)  (2)
Payments for short and long-term debt  (233)  (188)
 
Net Cash Provided by/(Used by) Financing Activities
  565   (233)
 
Change in cash from discontinued operations  —   43 
Effect of exchange rate changes on cash and cash equivalents  1   7 
 
Net Increase in Cash and Cash Equivalents
  788   131 
Cash and Cash Equivalents at Beginning of Period
  1,494   1,132 
 
Cash and Cash Equivalents at End of Period
 $2,282  $1,263 
 
         
    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.

10

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.

11

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 JuneSeptember 30, 2009, the results of operations for the three and sixnine months ended JuneSeptember 30, 2009, and 2008, and cash flows for the sixnine months ended JuneSeptember 30, 2009, and 2008. These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through July 30,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)
 

12

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 JuneSeptember 30, 2009, arewere predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.
Other Cash Flow Information
     NRG’s non-cash investing activities for the six months ended June 30, 2009 includeddo not include non-cash capital expenditures of $46$43 million for which the associated liability is reflected withinwere accrued expenses.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 3,4,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 12,13,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.

11

     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.

13

     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. This statement amends ARB No. 51 to establishSFAS 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) do not fall within the scope of paragraph 12 of Accounting Principles Board Opinion No. 14,Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants, and specifies that issuers of such instruments should separately account for the liability 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 an embedded derivativederivatives, 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 its embedded derivativeCSF CAGRs are accounted for under the guidance in ASC 470. Upon adoption of FSP APB 14-1. The14-1, the fair value of the embedded derivativeCSF 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 Six months ended  Three months ended Nine months ended 
 June 30, June 30,  September 30, September 30, 
(In millions, except per share amounts)
 2009 2008 2009 2008  2009 2008 2009 2008 
Increase/(decrease):  
Interest Expense $2   $2   $3   $5    $2 $(44) $5 $(39)
Income From Continuing Operations  (2)    (2)    (3)    (5)    (2) 44  (5) 39 
Net Income attributable to NRG Energy, Inc.  (2)    (2)    (3)    (5)    (2) 44  (5) 39 
Basic Earnings Per Share $(0.01) $(0.01) $(0.01) $(0.02) $(0.01) $0.19 $(0.02) $0.16 
Diluted Earnings Per Share $(0.01) $(0.01) $(0.01) $(0.02) $— $0.16 $(0.02) $0.14 

12

     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 SFAS Statement No. 157,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 will beis 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.

14

     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 amends FASB Statement No. 107,Disclosures about Fair Value of Financial Instruments,to requirerequires disclosures about fair value of financial instruments for interim and annual reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28,Interim Financial Reporting,to require those disclosures in summarized financial information at interim reporting periods. This FSP applies to all financial instruments withinending after the scopeFSP’s effective date of FSP 107-1 held by publicly traded companies, as defined by Opinion 28. This FSP is effective for interim reporting periods ending after June 15, 2009. FSP FAS 107-1 and APB 28-1 do not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures only for periods ending after initial adoption. 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 areis effective for interim and annual reporting periods ending after June 15, 2009. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this FSP requires comparative disclosures2009, and its disclosure requirements apply only forto periods ending after initial adoption.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.
     SFAS 168— In June 2009, the FASB issued SFAS No. 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, or SFAS 168. This guidance establishes the FASB Accounting Standards Codification, or Codification, as the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. In addition, SFAS 168 also specifies that rules and interpretive releases of the Securities and Exchange Commission under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. All guidance contained in the Codification carries an equal level of authority. SFAS 168 is effective for financial statements issued for interim and annual reporting periods that end after September 15, 2009.

13

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.

15

     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 23 — Comprehensive Income/(Loss)
     The following table summarizes the components of the Company’s comprehensive income/(loss), net of tax:
                 
  Three months ended  Six months ended 
  June 30,  June 30, 
(In millions)
 2009  2008  2009  2008 
 
Net income $433  $127  $631  $176 
 
Changes in derivative activity, net of tax  (109)  (698)  64   (1,000)
Foreign currency translation adjustment, net of tax  36   (7)  18   35 
Reclassification adjustment for translation (gain)/loss realized upon sale of foreign investments  (22)  15   (22)  15 
Unrealized gain on available-for-sale securities, net of tax  1   1   2   3 
 
Other comprehensive (loss)/income, net of tax  (94)  (689)  62   (947)
 
Comprehensive income/(loss) attributable to NRG Energy, Inc. $339  $(562) $693  $(771)
 
                 
  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  $310 
Changes in derivative activity 64   (9)
Foreign currency translation adjustment 18  38 
Reclassification adjustment for translation gain realized upon sale of foreign investment  (22)  (22)
Unrealized gain on available-for-sale securities 2  3 
Accumulated other comprehensive income as of June 30, 2009 $372 
Accumulated other comprehensive income as of September 30, 2009 $320 

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Note 34 — Business Acquisition
General
     On May 1, 2009, NRG, through its wholly ownedwholly-owned subsidiary NRG Retail LLC, acquired Reliant Energy, which consisted of all of the entire Texas electric retail business operations of RRI, including the exclusive use of the trade name “Reliant”.“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,Mass, customers in Texas, with approximately 1.6 million massMass customers as of JuneSeptember 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 JuneSeptember 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 will beis 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, which will provide for an efficient credit structure.exposures. This will also allowcombination of generation and retail allows for a reduction in actual and contingent collateral, which will be achieved 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 platformcustomer interface with the scale that is important to build on the entire classsuccessful 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 Merrill Lynch novated somemoved $522 million of NRG’s in-the-money trades to movecash collateral fromheld by NRG to Merrill Lynch, thereby reducing Merrill Lynch’s actual and contingent collateral supporting Reliant Energy out-of-money positions. As a result, $522 million of cash collateral held byAt September 30, 2009, these trades with counterparties were still open, thus there was no impact on NRG’s consolidated financial statements, and NRG was moved to Merrill Lynch on the novation dates. NRG continuescontinued to record unrealized and realized gains/losses for these novated trades in its Texas and Northeast segments. The CSRA is scheduled to provide collateral support for Reliant Energy until November 1, 2010. NRG will also have two potential additional cash contribution obligations: (i) in October 2009 of $250 million if the actual collateral posted by Merrill Lynch exceeded the predetermined threshold as set forth in the CSRA; and (ii) in October 2010 for up to $400 million at the scheduled sleeve unwind. The monthly fee for the CSRA iswas 5.875% on an annualized basis of the predetermined exposure. As a result of the CSRA, NRG has significant credit risk with Merrill Lynch.
     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 requiresrequired that the Company comply with all terms of the CSRA. The maturity date is November 1, 2010, and NRG initially drew $25 million under the facility. These funds accrueaccrued 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. TheThrough October 5, 2009, the obligations of Reliant Energy under the CSRA arewere secured by first liens on substantially all of the assets of RERH. TheRERH, and the obligations of RERH under the CSRA arewere non-recourse to NRG and its other non-pledgor subsidiaries. The CSRA agreement (a) restrictsrestricted 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) requiresrequired NRG to manage risks related to commodity prices. RERH iswas 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 JuneSeptember 30, 2009, the cash balance at RERH was $294$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.

1517

Acquisition method of accounting
     The acquisition of Reliant Energy is accounted for under the acquisition method of accounting in accordance with SFAS 141R.ASC-805. Accordingly, NRG has conducted a preliminaryan assessment of net assets acquired and has recognized provisional amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, which are preliminary at June 30, 2009, 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 as more detailed analysesuntil 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,hand. NRG also made payments to RRI of $63 million on June 15, 2009, and will$11 million on July 24, 2009, as initial remittances of acquired net working capital. In addition, the Company expects to remit approximately $82$9 million of acquired net working capital to RRI overin the eight months followingfourth quarter of 2009, bringing the closing, bringingtotal cash consideration to approximately $370 million. On June 15, 2009, NRG paid $63 million to RRI as an initial remittance of acquired net working capital. 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 SFAS 141R,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  $635 
Property, plant and equipment 72  72 
Intangible assets subject to amortization:  
In-market customer contracts 733  790 
Customer relationships 481  399 
Trade names 178  178 
In-market energy supply contracts 37  54 
Other 6  6 
Derivative assets 1,942  1,942 
Deferred tax asset, net 11  14 
Goodwill —  — 
Total assets acquired 4,095  4,090 
 
Liabilities
  
Current and non-current liabilities 550  550 
Derivative liabilities 2,996  2,996 
Out-of-market energy supply and customer contracts 148  143 
Total liabilities assumed 3,694  3,689 
Net assets acquired $401  $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.

16

     The Company, through its acquisition of Reliant Energy, is subject to material contingencies relating to Excess Mitigation Credits (see Note 14,15,Commitments and Contingencies,)to this Form 10-Q) and Retail Replacement Reserve (see Note 15,16,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 SFAS No. 5,ASC-450,Accounting for Contingencies,, or SFAS 5,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 17,18,Guarantees,to this Form 10-Q for further discussion.

18

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 SFAS No. 157,Fair Value Measurement, or SFAS 157.ASC 820. Significant inputs were as follows:
 • 
Customer contracts— The fair valuevalues of the customer contracts, representing those with Reliant Energy’s C&I customers, waswere 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 residential and small businessMass customer base, or Mass, 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 valuevalues of the in-market and out-of-market energy supply contracts waswere determined in accordance with SFAS 157.ASC 820. These contracts are amortized over periods ranging through 2016, based on the expected delivery under the respective contracts.

19

 • 
Property, plant and equipment— The fair value of property, plant and equipment werewas 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 valuevalues of derivative assets and liabilities as of the acquisition date were determined in accordance with FAS 157.ASC 820. The breakdown of Level 1, 2 and 3 areis 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 
 

17

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  Customer Customer Trade Energy Supply  
(in millions) Contracts Relationships Names Contracts 
(In millions) Contracts Relationships Names Contracts
 
2009 (six months) $178 $118 $6 $12 
2009 (three months) $99 $44 $3 $— 
2010 208 106 12 —  225 81 12 3 
2011 134 63 12 2  152 57 12 4 
2012 93 47 12 3  104 44 12 5 
2013 45 33 12 4  49 31 12 6 
2014 — 26 12 4  — 24 12 6 
     The following table presents the estimated amortization related to the acquired out-of-market contracts for 2009 — 2014:
        
 Energy Supply     Energy Supply   
Year Ended December 31, and Customer  and Customer
(in millions) Contracts 
(In millions) Contracts
 
2009 (six months)  $        49 
2009 (three months) $  23 
2010 51  48 
2011 18  18 
2012 7  7 
2013 3  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 $1,175$2,965 million of operating revenues and $233$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 June 30, Six months ended June 30,  Three months ended September 30, Nine months ended September 30,
(In millions, except per share amounts)
 2009 2008 2009 2008  2009 2008 2009 2008
Operating revenues $2,672 $3,497 $5,716 $6,513  $  2,911 $  5,122 $  8,625 $  11,633 
Net income attributable to NRG Energy, Inc. 493 268 578 548 
Net income/(loss) attributable to NRG Energy, Inc. 282  (322) 878 245 
Earnings per share attributable to NRG common stockholders:  
Basic $1.92 $1.08 $2.27 $2.20  $  1.11 $  (1.43) $  3.45 $  1.60 
Diluted $1.78 $0.97 $2.07 $1.91  $  1.04 $  (1.43) $  3.17 $  1.49 

20

     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;acquisition, however, there can be no assurance that these cost savings will be achieved. These pro forma results do not purport to be indicative of the results that would have actually been obtained if the acquisition occurred at the beginning of the respective reporting periods, nor does the pro forma data intend to be a projection of results that may be obtained in the future.

18

Significant Accounting Policies
     The following pertains to Reliant Energy, in addition to NRG’s significant accounting policies referred to in Note 12,Summary of Significant Accounting Policies, to this Form 10-Q:
 • 
Revenues—Gross revenues for energy sales and services to massMass 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, and other hedging activities, which were $52$151 million for the two monthsperiod ended JuneSeptember 30, 2009. These revenues represent a sale of excess supply to third parties in the market.
   As of JuneSeptember 30, 2009, Reliant Energy recorded unbilled revenues of $433$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.
 The revenues and the related energy supply costs include the estimates of customer usage based on initial usage information provided by the independent system operators and the distribution companies. Reliant Energy revises these estimates and records any changes in the period as additional settlement information becomes available (collectively referred to as market usage adjustments).
 • 
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 ($9368 million as of JuneSeptember 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. See the discussion above regarding market usage adjustments.
 • 
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 agingsaging 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 two monthsperiod ended JuneSeptember 30, 2009, Reliant Energy’s revenues and cost of operations included gross receipts taxes of $16$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.

1921

Note 45 — 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 SeveročSeveroćeské 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 ($284 million at an exchange rate of 1.40 US$U.S.$/EUR), net of transaction costs. During the three and sixnine months ended JuneSeptember 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 three and sixnine months ended JuneSeptember 30, 2009, NRG recorded an exchange loss of $15 million and $24 million respectively, on the contract within “Other income/(loss)/income,, net.”
     NRG provided certain indemnities in connection with its share of the transaction. See Note 17,18,Guarantees,to this Form 10-Q for further discussion.
Note 56 — 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  Carrying Amount Fair Value
 December 31, December 31,  September 30, December 31, September 30, December 31,
 June 30, 2009 2008 June 30, 2009 2008  2009 2008 2009 2008
 (In millions)  (In millions)
Cash and cash equivalents $2,282 $1,494 $2,282 $1,494  $  2,250 $  1,494 $  2,250 $ 1,494 
Funds deposited by counterparties 468 754 468 754  293 754 293 754 
Restricted cash 19 16 19 16  26 16 26 16 
Cash collateral paid in support of energy risk management activities 243 494 243 494  475 494 475 494 
Investment in available-for-sale securities (classified within other non-current assets):  
Debt securities 7 7 7 7  8 7 8 7 
Marketable equity securities 4 2 4 2  4 2 4 2 
Trust fund investments 318 305 318 305  356 305 356 305 
Notes receivable 190 156 204 166  214 156 221 166 
Derivative assets 5,582 5,485 5,582 5,485  4,238 5,485 4,238 5,485 
Long-term debt, including current portion 8,619 8,019 8,267 7,475  8,636 8,019 8,422 7,475 
Cash collateral received in support of energy risk management activities 468 760 468 760  293 760 293 760 
Derivative liabilities 5,102 4,489 5,102 4,489  3,876 4,489 3,876 4,489 

2022

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 Fair Value
As of June 30, 2009 Level 1 Level 2 Level 3 Total 
As of September 30, 2009 Level 1 Level 2 Level 3 Total
Cash and cash equivalents $ 2,282 $ — $ — $ 2,282  $ 2,250 $ — $  — $ 2,250 
Funds deposited by counterparties 468 — — 468  293 —  — 293 
Restricted cash 19 — — 19  26 —  — 26 
Cash collateral paid in support of energy risk management activities 243 — — 243  475 —  — 475 
Investment in available-for-sale securities (classified within other non-current assets):  
Debt securities — — 7 7  — —  8 8 
Marketable equity securities 4 — — 4  4 —  — 4 
Trust fund investments 183 101 34 318  203 113  40 356 
Derivative assets 1,063 4,394 125 5,582  964 3,171  103 4,238 
Total assets $ 4,262 $ 4,495 $ 166 $ 8,923  $ 4,215 $ 3,284 $  151 $ 7,650 
Cash collateral received in support of energy risk management activities $ 468 $ — $ — $ 468  $ 293 $ — $  — $ 293 
Derivative liabilities 1,043 3,984 75 5,102  956 2,747  173 3,876 
Total liabilities $ 1,511 $ 3,984 $ 75 $ 5,570  $ 1,249 $ 2,747 $  173 $ 4,169 
     The following table reconciles for the six months ended June 30, 2009, 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 Fair Value Measurement Using Significant Unobservable Inputs
(Level 3) (Level 3)
(In millions) Trust Fund     Trust Fund    
Six months ended June 30, 2009 Debt Securities Investments Derivatives Total
Nine months ended September 30, 2009 Debt Securities Investments Derivatives Total
Beginning balance as of January 1, 2009 $  7 $  31 $  49 $  87  $ 7 $ 31 $ 49 $ 87 
Total gains/(losses) (realized and unrealized)  
Included in earnings — —  (30)  (30) 1 —  (110)  (109)
Included in nuclear decommissioning obligations — 2 — 2  — 8 — 8 
Purchases/(sales), net — 1  (4) (3) — 1  (3)  (2)
Transfer into Level 3 — — 35 35 
Transfers out of Level 3 — —  (6)  (6)
Ending balance as of June 30, 2009
 $  7 $  34 $  50 $  91 
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 June 30, 2009 $  — $  — $  28 $  28 
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 JuneSeptember 30, 2009, the credit reserve resulted in a $23$18 million increase in fair value which is composed of a $1$4 million lossgain in other comprehensive income, or OCI, and a $24$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.

2123

Note 67 — Accounting for Derivative Instruments and Hedging Activities
     SFAS 133ASC 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 other comprehensive income, or OCI until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.
     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 SFAS 133,ASC 815, certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. SFAS 133ASC 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 SFAS 133.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 buy or sell a commodity.
•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.
•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.

2224

     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.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 JuneSeptember 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 JuneSeptember 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 JuneSeptember 30, 2009
Commodity
 Units (In millions)
 
EmissionsShort Ton1
Coal Short Ton  6760 
Natural Gas MMBtu  (572582)
Power(a)
 MWH  (3027)
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 JuneSeptember 30, 2009:
                
 Fair Value Fair Value
(In millions) Derivatives Asset Derivatives Liability Derivatives Asset Derivatives Liability
Derivatives Designated as Cash Flow or Fair Value Hedges:
  
Interest rate contracts current $  — $  6  $  — $  4 
Interest rate contracts long term 11 119  9 123 
Commodity contracts current 337 7  278 13 
Commodity contracts long term 414 47  378 30 
Total Derivatives Designated as Cash Flow or Fair Value Hedges
 762 179  665 170 
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
  
Commodity contracts current 4,057 4,183  2,921 3,000 
Commodity contracts long term 763 740  652 706 
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges
 4,820 4,923  3,573 3,706 
Total Derivatives
 $  5,582 $  5,102  $  4,238 $  3,876 
Impact of Derivative Instruments on the Statement of Financial PerformanceOperations
     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 Six months ended Three months ended Nine months ended
(In millions) June 30, 2009 June 30, 2009 September 30, 2009 September 30, 2009
Derivative $  (7) $  (8) $  3 $  (5)
Senior Notes (hedged item) $  7 $  8  $  (3) $  5 

2325

     The following table summarizes the location and amount of gain/(loss) resulting from cash flow hedges:
                                        
 Location of Amount of Location of Amount of
 Amount of Location of Amount of gain/(loss) gain/(loss) Amount of Location of Amount of gain/(loss) gain/(loss)
 gain/(loss) gain/(loss) gain/(loss) recognized in recognized in gain/(loss) gain/(loss) gain/(loss) recognized in recognized in
 recognized in OCI reclassified from reclassified from income income recognized in OCI reclassified from reclassified from income income
(In millions) (effective portion) Accumulated Accumulated (ineffective (ineffective (effective portion) Accumulated Accumulated (ineffective (ineffective
Three months ended June 30, 2009 after tax OCI into Income OCI into Income portion) portion)
Three months ended September 30, 2009 after tax OCI into Income OCI into Income portion) portion)
Interest rate contracts $  13 Interest expense $  1 Interest expense $  —  $ (2) Interest expense $ — Interest expense $ 4 
Commodity contracts  (122) Operating revenue 76 Operating revenue  (3)  (71) Operating revenue 75 Operating revenue 16 
Total $  (109) $  77 $  (3) $ (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
Six months ended June 30, 2009 after tax OCI into Income OCI into Income portion) portion)
Interest rate contracts $  25 Interest expense $  — Interest expense $  — 
Commodity contracts 39 Operating revenue 323 Operating revenue 1 
Total $  64 $  323 $  1 
                     
              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 Six months ended Three months ended Nine months ended
(In millions) June 30, 2009 June 30, 2009 September 30, 2009 September 30, 2009
Location of gain/(loss) recognized in income for derivatives:  
Operating revenue $ (207) $ 116  $ (233) $ (117)
Cost of operations $ 325 $ 273  $ 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. ThereThe 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 wasis approximately $87$24 million as of JuneSeptember 30, 2009. The aggregate fair value of all derivative instruments with credit rating contingent features that are in a net liability position as of June 30, 2009 was $54 million. The aggregate fair value of all derivative instruments that have adequate assurance clauses that are in a net liability position as of June 30, 2009 was $18 million.
     Under the CSRA, Merrill Lynch providesprovided guarantees and the posting of collateral to the Company’s counterparties in supply transactions for the Company’s retail energy business. In the event of any unwind of the CSRA with Merrill Lynch, NRG will have to post collateral for any existing out-of-money hedging transactions that support the retail operation. The level of collateral posting would be determined based on the timing of the unwind, and the volume and pricing of the commodity hedging agreements. As of JuneSeptember 30, 2009, Merrill Lynch was providing $630$163 million in credit support to various counterparties. Ifcounterparties (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 experiencesand other counterparties, returned $53 million of counterparty collateral, issued letters of credit deterioration, NRG’s suppliers may require varying collateral amounts depending on Merrill Lynch’s credit rating, not to exceed $630 million.of $206 million, and received $45 million of counterparty collateral.

2426

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.
     UnderSince the current economic downturncredit crisis began in the U.S. and overseas, the Companylate 2008, NRG has heightened its management and mitigation of counterpartytaken several additional steps to mitigate credit risk by using credit limits,including the use of netting agreements,arrangements, entering contracts with collateral thresholds, setting volumetric limits with certain counterparties and other mitigation measures,restricting trading relationships with counterparties where available.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 JuneSeptember 30, 2009, total credit exposure to substantially all counterparties was $2.1$1.8 billion and NRG held collateral (cash and letters of credit) against those positions of $469$280 million resulting in a net exposure of $1.7 billion, compared with a net exposure of $1.3 billion as of March 31, 2009. This increase is due to Merrill Lynch’s position as credit provider to Reliant Energy and the exposure resulting from novated trades that were completed as part of the acquisition of Reliant Energy, as discussed in Note 3 —Business Acquisition.$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 normal purchase and sale,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
  Juneas of September 30, 2009
Category
 (% of Total)
 
Financial institutions  8281%
Utilities, energy, merchants, marketers and other  1413 
Coal suppliers  23 
ISOs  3
Total100%
Net Exposure(a)(b)
as of September 30, 2009
Category(% of Total)
Investment grade93%
Non-Investment grade2
Non-rated5 
 
Total  100%
 
Net Exposure(a)(b) as of
June 30, 2009
Category
(% of Total)
Investment grade94%
Non-Investment grade—
Non-rated6
Total100%
(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 tabledo not include non-affiliate third party exposure under the CSRA.CSRA which was amended on October 5, 2009. The gross credit exposure to third parties under the CSRA is $410was $385 million, and the cash collateral held by Merrill Lynch against this exposure is $312was $304 million.

25

     NRG has credit risk exposure to certain counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $707$704 million. NRG has significant credit risk concentration with Merrill Lynch primarily due to cash collateral held by Merrill Lynch for positions under the CSRA. NRG expects this risk to be significantly reduced when the Company unwinds the CSRA. Approximately 85%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.

27

     NRG is exposed to retail credit risk through our competitive electricity supply business, which serves commercial and industrialC&I customers and the massMass 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 SFAS 133ASC 815 on NRG’s accumulated OCI balance attributable to hedged derivatives, net of tax:
                       
(In millions) Energy Interest   Energy Interest  
Three months ended June 30, 2009 Commodities Rate Total
Three months ended September 30, 2009 Commodities Rate Total
Accumulated OCI balance at March 31, 2009 $567 $(79) $488 
Accumulated OCI balance at June 30, 2009 $  445 $  (66) $  379 
Realized from OCI during the period:  
— Due to realization of previously deferred amounts  (76)  (1)  (77)  (75) —  (75)
Mark-to-market of cash flow hedge accounting contracts  (46) 14  (32) 4  (2) 2 
Accumulated OCI balance at June 30, 2009 $445 $(66) $379 
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 $181 tax $303 $(3) $300 
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 June 30, 2008
 Commodities Rate Total
Accumulated OCI balance at March 31, 2008 $(493) $(74) $(567)
Realized from OCI during the period: 
— Due to realization of previously deferred amounts 21 — 21 
Mark-to-market of cash flow hedge accounting contracts  (763) 44  (719)
Accumulated OCI balance at June 30, 2008 $(1,235) $(30) $(1,265)
(In millions)
 Energy Interest 
Six months ended June 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  (188) —  (188)
— Due to discontinuance of cash flow hedge accounting  (135) —  (135)
Mark-to-market of cash flow hedge accounting contracts 362 25 387 
Accumulated OCI balance at June 30, 2009 $445 $(66) $379 
 Energy Interest 
(In millions)
 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 6 — 6 
Mark-to-market of cash flow hedge accounting contracts  (1,007) 1  (1,006)
Accumulated OCI balance at June 30, 2008 $(1,235) $(30) $(1,265)

26

             
(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 JuneSeptember 30, 2009, the net balance in OCI relating to SFAS 133ASC 815 was an unrecognized gain of approximately $379$306 million, which is net of $233$189 million in income taxes. As of JuneSeptember 30, 2008, the net balance in OCI relating to SFAS 133ASC 815 was an unrecognized loss of approximately $1,265$153 million, which was net of $829$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. SinceOn April 1, 2009, the required correlation threshold for cash flow hedge accounting was achieved for these transactions, on April 1, 2009,and accordingly, these hedges were re-designated as cash flow hedges.

28

     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 SFAS 133,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 June 30, Six months ended June 30,  Three Months ended September 30, Nine months ended September 30,
(In millions)
 2009 2008 2009 2008  2009 2008 2009 2008
Unrealized mark-to-market results
  
Reversal of previously recognized unrealized losses/(gains) on
settled positions related to economic hedges
 $192 $(15) $176 $(25) $  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
  (35)  (7)  (104)  (12)  (21)  (9)  (125)  (20)
Net unrealized (losses)/gains on open positions related to economic
hedges
  (40)  (162) 309  (259)  (239) 439 70 180 
(Losses)/gains on ineffectiveness associated with open positions
treated as cash flow hedges
  (3)  (333) 1  (378)
Net unrealized gains on open positions related to trading activity 1 15 8 31 
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 gains/(losses)
 $115 $(502) $390 $(643)
Total unrealized (losses)/gains
 $  (14) $  835 $  376 $  192 
    Six months ended                 
  Three months ended June 30,    June 30,  Three months ended September 30, Nine months ended September 30,
(In millions)
 2009 2008 2009 2008  2009 2008 2009 2008
Revenue from operations — energy commodities $(210) $(502) $117 $(643) $  (217) $  835 $  (100) $  192 
Cost of operations 325 — 273 —  203 — 476 — 
Total impact to statement of operations
 $115 $(502) $390 $(643) $  (14) $  835 $  376 $  192 

29

     For the sixnine months ended JuneSeptember 30, 2009, the unrealized gain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $390$376 million was comprised of $309gains of $70 million offrom fair value increases in forward sales and purchases of natural gas, electricity and fuel, $1$17 million gain from ineffectiveness, $72$158 million gainloss from the reversal of mark-to-market lossesgains, $448 million roll-off of Reliant Energy loss positions acquired as of May 1, 2009, and $8$1 million of gainslosses associated with the Company’s trading activity. The $309$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 $92a $147 million of increase in value of forward purchases and sales of natural gas, electricity and fuel due to decrease in forward power and gas prices. The $1$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.

27

     The reversal of previously recognized unrealized losses on settledReliant Energy’s loss positions related to economic hedges of $192 million and $176 million for the three months and six months ended June 30, 2009, includes $210 million in gains from Reliant Energy representing roll-off of positionswere acquired as of May 1, 2009 at the acquisition date’sand valued using forward prices. These gains areprices on that date. The $448 million roll-off amounts were offset by therealized losses at the settled prices and are reflected in the cost of operations during the same period.
     For the sixnine months ended JuneSeptember 30, 2008, the unrealized lossgain associated with changes in the fair value of derivative instruments not accounted for as hedge derivatives of $643$192 million was comprised of $259$180 million of fair value decreasesincreases in forward sales of electricity and fuel, a $378$27 million loss due to the ineffectiveness associated with financial forward contracted electric and gas sales, $37$52 million from the reversal of mark-to-market gains which ultimately settled as financial revenues of which $25$32 million was related to economic hedges and $12$20 million was related to trading activity. These decreases were partially offset by $31$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 expected 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 sixnine months ended JuneSeptember 30, 2009.
     Discontinued Normal Purchase and Sale for Coal Purchases— Due to the decline in commodity priceslower coal-fired generation during the first quarter of 2009, the Company’s coal consumption was lower than forecasted, and the Company built-up inventory due to lower baseload plant generation.forecasted. The Company expected to net settlesettled 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 sixnine months ended JuneSeptember 30, 2009.

30

Note 78 — 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.
     TheA portion of the net proceeds of $678 million are intended to bewere used to facilitate the early termination of NRG’s obligations pursuant to the CSRA anticipatedAmendment, which became effective on October 5, 2009, as discussed in the late third or early fourth quarter 2009. PriorNote 20, Subsequent Event, to the termination, or in the event NRG does not reach agreement on acceptable terms with either Merrill Lynch or its counterparties, the net proceeds will be available for general corporate purposes.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 JuneSeptember 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:

28

     
  Redemption
Redemption Period
 Percentage
 
June 15, 2014 to June 14, 2015  104.25%104.25%
June 15, 2015 to June 14, 2016  102.83%102.83%
June 15, 2016 to June 14, 2017  101.42%101.42%
June 15, 2017 and thereafter  100.00%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 3,4,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 3,4,Business Acquisition, to this Form 10-Q, regarding the $50 million working capital facility entered into on May 1, 2009, of which2009. Under the working capital facility, the Company borrowed $25 million is outstandingon 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 of June 30, 2009.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.

31

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 JuneSeptember 30, 2009, no amounts have been borrowed under the TANE Facility. NINA will be required to repay all outstanding amounts associated with its existing $20 million non-recourse revolving credit facility before borrowing 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 Credit Suisse Group, or CS relating to the shares of NRG common stock currently held by CSF I and II in connection with the CSF I and CSF II issued notes and preferred interests agreements, or 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 the currenta 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 JuneSeptember 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.

29

     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’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, 2009.2009, which has been incorporated in ASC 470 and ASC 825. The following table summarizes certain information related to the CSF Debt in accordance with FSP APB 14-1:ASC 470.
                     
 June 30, December 31,  September 30, December 31,   
 2009 2008  2009 2008
Equity Component
  
Additional Paid-in Capital $14    $14  $  14 $  14 
Liability Component
  
Principal amount $333    $333  $  333 $  333 
Unamortized discount  (5)  (8)   (3)  (8)
Net carrying amount
 $328    $325  $  330 $  325 
     The unamortized discount will be amortized through the maturity of the CSF Debt. The CSF I debtDebt has a maturity date of June 2010 and the CSF II debtDebt has a maturity date of October 2009. Interest expense for the CSF Debt, including the debt discount amortization for the three and sixnine months ended JuneSeptember 30, 2009, was $9$10 million and $18$28 million, respectively. Interest expense for the CSF Debt, including the debt discount amortization for the three and sixnine months ended JuneSeptember 30, 2008, was $9 million and $19$28 million, respectively. The effective interest rate as of JuneSeptember 30, 2009, was 11.4% for the CSF I debtDebt and 12.1% for the CSF II debt.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.

32

     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 ownedwholly-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 JuneSeptember 30, 2009, were $34$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 ownedwholly-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 JuneSeptember 30, 2009, were $70$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.

3033

Note 89 — Changes in Capital Structure
     The following table reflects the changes in NRG’s common stock issued and outstanding during the sixnine months ended JuneSeptember 30, 2009:
                                
 Authorized Issued Treasury Outstanding Authorized Issued Treasury Outstanding
Balance as of December 31, 2008
 500,000,000 263,599,200  (29,242,483) 234,356,717  500,000,000 263,599,200  (29,242,483) 234,356,717 
Shares issued from LTIP — 216,741 — 216,741  — 268,220 — 268,220 
Shares issued under NRG Employee Stock Purchase Plan, or ESPP — — 41,706 41,706  — — 81,532 81,532 
Shares borrowed by affiliates of CS — — 12,000,000 12,000,000  — — 12,000,000 12,000,000 
2009 Share Repurchases — —  (8,919,100)  (8,919,100)
4.00% Preferred Stock conversion — 20,650 — 20,650  — 20,650 — 20,650 
5.75% Preferred Stock conversion — 18,601,201 — 18,601,201  — 18,601,201 — 18,601,201 
Balance as of June 30, 2009
 500,000,000 282,437,792  (17,200,777) 265,237,015 
Balance as of September 30, 2009
 500,000,000 282,489,271  (26,080,051) 256,409,220 
Employee Stock Purchase Plan
     As of JuneSeptember 30, 2009, there were 458,294418,468 shares of treasury stock reserved for issuance under the ESPP. In July 2009, 39,826 shares of common stock were issued to employee accounts from treasury stock.
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 Preferred Stock Conversion Rate Common Stock
 Shares (per share) Shares Shares (per share) Shares
Balance as of December 31, 2008
 1,841,680 —  1,841,680 — 
Preferred shares converted by the holders prior to March 16, 2009 144,975 8.2712 1,199,116  144,975 8.2712 1,199,116 
Preferred shares automatically converted as of March 16, 2009 1,696,705 10.2564 17,402,085  1,696,705 10.2564 17,402,085 
Balance at June 30, 2009
 — 18,601,201 
Balance at September 30, 2009
 — 18,601,201 
4% Preferred Stock
     As of JuneSeptember 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.

3134

Note 910 — Equity Compensation
Non-Qualified Stock Options, or NQSO’s
     The following table summarizes the Company’s NQSO activity as of JuneSeptember 30, 2009, and changes during the sixnine months then ended:
                        
 Weighted Aggregate Intrinsic Weighted Aggregate Intrinsic
 Average Value Average Value
 Shares Exercise Price (In millions) Shares Exercise Price (In millions)
Outstanding as of December 31, 2008
 4,008,188 $   25.84  4,008,188 $  25.84 
Granted 1,297,300 23.37  1,402,000 23.62 
Exercised  (25,000) 21.41 
Forfeited  (103,768) 27.18   (212,935) 27.55 
   
Outstanding at June 30, 2009
 5,201,720 25.20 $22 
Exercisable at June 30, 2009
 2,862,448 $21.87 18 
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 sixnine months ended JuneSeptember 30, 2009, was $8.48.$8.63.
Restricted Stock Units, or RSU’s
     The following table summarizes the Company’s non-vested RSU awards as of JuneSeptember 30, 2009, and changes during the sixnine months then ended:
                
 Weighted Average Weighted Average
 Grant-Date Grant-Date
 Units Fair Value Per Unit Units Fair Value Per Unit
Non-vested as of December 31, 2008
 1,061,996 $   32.97  1,061,996 $ 32.97 
Granted 160,100 23.35  927,000 26.12 
Vested  (293,312) 23.76   (334,752) 23.24 
Forfeited  (36,040) 33.00   (45,850) 33.59 
Non-vested as of June 30, 2009
 892,744 $34.27 
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 JuneSeptember 30, 2009, and changes during the sixnine months then ended:
                
 Weighted Average Weighted Average
 Grant- Date Grant- Date
 Units Fair Value Per Unit Units Fair Value Per Unit
Non-vested as of December 31, 2008
 659,564 $   22.81  659,564 $ 22.81 
Granted 310,800 22.52  338,100 22.91 
Forfeited  (262,864) 19.33   (272,864) 19.44 
Non-vested as of June 30, 2009
 707,500 $24.15 
Non-vested as of September 30, 2009
 724,800 $ 24.29 
     In the first half ofnine 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 JuneSeptember 30, 2009, and changes during the sixnine months then ended:
                
 Weighted Average Weighted Average
 Grant- Date Grant- Date
 Units Fair Value Per Unit Units Fair Value Per Unit
Outstanding as of December 31, 2008
 260,768 $   18.50  260,768 $ 18.50 
Granted 65,437 22.77  65,437 22.77 
Conversions  (22,156) 23.69   (22,156) 23.69 
Outstanding as of June 30, 2009
 304,049 $19.34 
Outstanding as of September 30, 2009
 304,049 $ 19.34 

3235

Note 1011 — 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 7 –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
June 30,		 Six months ended
June 30,
(In millions, except per share data) 2009 2008 2009 2008
 
Basic earnings per share attributable to NRG common stockholders
                
Numerator:
                
Income/(loss) from continuing operations, net of income taxes $433  $(41) $631  $4 
Dividends for preferred shares  (7)  (14)  (21)  (28)
 
Net income/(loss) available to common stockholders from continuing operations  426   (55)  610   (24)
Income from discontinued operations, net of income taxes  —   168   —   172 
Net income attributable to NRG Energy, Inc. available to common stockholders $426  $113  $610  $148 
 
Denominator:
                
Weighted average number of common shares outstanding     253.2      235.9      245.2      236.1 
Basic earnings per share:
                
Income/(loss) from continuing operations $1.68  $(0.23) $2.49  $(0.10)
Income from discontinued operations, net of income taxes  —   0.71   —   0.73 
 
Net income attributable to NRG Energy, Inc. $1.68  $0.48  $2.49  $0.63 
 
Diluted earnings per share attributable to NRG common stockholders
                
Numerator:
                
Net income/(loss) available to common stockholders from continuing operations $426  $(55) $610  $(24)
Add preferred stock dividends for dilutive preferred stock  4   —   14   — 
 
Adjusted income/(loss) from continuing operations  430   (55)  624   (24)
Income from discontinued operations, net of income taxes  —   168   —   172 
 
Net income attributable to NRG Energy, Inc. available to common stockholders $430  $113  $624  $148 
 
Denominator:
                
Weighted average number of common shares outstanding  253.2   235.9   245.2   236.1 
Incremental shares attributable to the issuance of equity compensation (treasury stock method)  1.0   —   1.0   — 
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)  21.0   —   29.1   — 
 
Total dilutive shares  275.2   235.9   275.3   236.1 
Diluted earnings per share:
                
Income/(loss) from continuing operations $1.56  $(0.23) $2.27  $(0.10)
Income from discontinued operations, net of income taxes  —   0.71   —   0.73 
 
Net income attributable to NRG Energy, Inc. $1.56  $0.48  $2.27  $0.63 
 
     For the three and six months ended June 30, 2008, basic and diluted per share amounts were the same within each period reported because potential common shares had an anti-dilutive effect on loss from continuing operations available to common shares and were excluded from the computation.
                 
  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 
 

3336

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 sixnine months ended JuneSeptember 30:
                                
 Three months ended June 30, Six months ended June 30,    Three months ended September 30,       Nine months ended September 30,   
(In millions of shares) 2009 2008 2009 2008 2009 2008 2009 2008
Equity compensation (NQSO’s and PU’s) 5.3 7.5 5.3 7.5  4.8 1.8 6.4 1.4 
4.0% convertible preferred stock — 21.0 — 21.0 
5.75% convertible preferred stock — 16.5 — 16.5 
Embedded derivative of 3.625% redeemable perpetual preferred stock 16.0 16.0 16.0 16.0  16.0 14.0 16.0 14.2 
Embedded derivative of CSF preferred interests and notes 7.6 18.3 7.6 18.3 
Embedded derivative of CSF II Debt 7.6 7.6 7.6 7.6 
Total 28.9 79.3 28.9 79.3  28.4 23.4 30.0 23.2 
Note 1112 — 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 Corporatecorporate 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, Corporatecorporate general and administrative expenses arehave been allocated based on forecasted earnings/(losses) before interest expense, income taxes, depreciation and amortization expense.

34

                                         
      Wholesale Power Generation            
(In millions)             South                  
Three months ended June 30, 2009 Reliant Energy(a)     Texas(b)    Northeast   Central     West International   Thermal   Corporate   Elimination   Total
 
Operating revenues $1,175  $619  $237  $139  $42  $34  $28  $32  $(69) $2,237 
Depreciation and amortization  43   117   30   17   2   —   3   1   —   213 
Equity in earnings/(loss) of unconsolidated affiliates  —   (7)  —   —   3   9   —   —   —   5 
Income/(loss) from continuing operations before income taxes  414   107   42   (9)  19   128   —   (119)  —   582 
 
Net income/(loss)  233   98   42   (9)  19   125   —   (76)  —   432 
Net loss attributable to non-controlling interest  —   (1)  —   —   —   —   —   —   —   (1)
 
Net income/(loss) attributable to
NRG Energy, Inc.
 $233  $99  $42  $(9) $19  $125  $—  $(76) $—  $433 
 
Total assets
 $ 4,405  $ 13,680  $ 1,788  $ 929  $ 268  $766  $ 197  $ 22,809  $(17,537) $ 27,305 
 
(a)Reliant Energy balances are for the two months ended June 30, 2009.
(b)Includes inter-segment sales of $66 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 June 30, 2009 would have been as follows:
                                         
Net income/(loss) attributable to
NRG Energy, Inc. as reported		 $233  $99  $42  $(9) $19  $125  $—  $(76) $—  $433 
Increase/(decrease) in net income/(loss) attributable to
NRG Energy, Inc.		  (11)  8   4   (1)  —   —   —   —   —   — 
 
Adjusted net income/(loss) attributable to
NRG Energy, Inc.
 $222  $107  $46  $(10) $19  $125  $—  $(76) $—  $433 
 
                                     
  Wholesale Power Generation            
(In millions)             South                  
Three months ended June 30, 2008     Texas     Northeast     Central     West International     Thermal     Corporate   Elimination   Total
 
Operating revenues $751  $265  $172  $49  $43  $34  $3  $(1) $1,316 
Depreciation and amortization  113   25   17   3   —   2   1   —   161 
Equity in (losses)/earnings of
unconsolidated affiliates
  (32)  —   —   (1)  14   —   —   —   (19)
Income/(loss) from continuing operations before income taxes  14   (45)  (6)  13   23   2   (85)  (10)  (94)
Income from discontinued operations, net of income taxes  —   —   —   —   168   —   —   —   168 
Net income/(loss) attributable to
NRG Energy, Inc.
 $13  $(45) $(6) $13  $186  $2  $(26) $(10) $127 
 

3537

     
                                         
      Wholesale Power Generation            
(In millions)             South                  
Six months ended June 30, 2009 Reliant Energy(a)   Texas(b)    Northeast   Central       West International   Thermal   Corporate   Elimination   Total
 
Operating revenues $ 1,175  $ 1,544  $ 701  $ 301  $ 70  $68  $ 70  $ 36  $(70) $ 3,895 
Depreciation and amortization  43   234   59   34   4   —   5   3   —   382 
Equity in earnings/(losses) of unconsolidated affiliates  —   (3)  —   —   4   26   —   —   —   27 
Income/(loss) from continuing operations before income taxes  414   485   253   (8)  16   142   4   (228)  —   1,078 
 
Net income/(loss)  233   315   253   (8)  16   137   4   (320)  —   630 
Net loss attributable to non-controlling interest  —   (1)  —   —   —   —   —   —   —   (1)
 
Net income/(loss) attributable to
NRG Energy, Inc.
 $233  $316  $253  $(8) $16  $137  $4  $(320) $—  $631 
 
                                         
(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 
 

38

(a)Reliant Energy balances are for the two months ended June 30, 2009.
(b)Includes inter-segment sales of $66 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 six months ended June 30, 2009 would have been as follows:
                                         
Net income/(loss) attributable to
NRG Energy, Inc. as reported		 $233  $316  $253  $(8) $16  $137  $4  $(320) $—  $631 
Increase/(decrease) in net income/(loss) attributable to NRG Energy, Inc.  (11)  8   4   (1)  —   —   —   —   —   — 
 
Adjusted net income/(loss) attributable to
NRG Energy, Inc.
 $222  $324  $257  $(9) $16  $137  $4  $(320) $—  $631 
 
                                        
(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:
(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 
                                    
 Wholesale Power Generation                                                
(In millions) South              Wholesale Power Generation        
Six months ended June 30, 2008   Texas   Northeast   Central       West   International   Thermal   Corporate   Elimination   Total
 South            
Nine months ended September 30, 2008 Texas Northeast Central West International Thermal Corporate Elimination Total
Operating revenues $1,400 $625 $351 $87 $81 $78 $(2) $(2) $2,618  $3,037 $1,247 $585 $127 $122 $114 $1 $(3) $5,230 
Depreciation and amortization 226 51 34 4 — 5 2 — 322  334 77 50 6 — 8 3 — 478 
Equity in (losses)/earnings of
unconsolidated affiliates
  (50) — —  (3) 30 — — —  (23)  (10) — —  (2) 47 — — — 35 
Income/(loss) from continuing operations before income taxes 81 14 33 25 47 7  (192)  (10) 5  1,107 310 58 38 72 11  (300)  (11) 1,285 
Income from discontinued operations, net of income taxes — — — — 172 — — — 172  — — — — 172 — — — 172 
Net income/(loss) attributable to
NRG Energy, Inc.
 $50 $14 $33 $25 $210 $7 $(153) $(10) $176  $626 $310 $58 $38 $229 $11 $(307) $(11) $954 

3639

Note 1213 — Income Taxes
Effective Tax Rate
     Income taxes included in continuing operations were as follows:
                
 Three months ended June 30,     Three months ended September 30,    
(In millions except otherwise noted) 2009 2008 2009 2008
Income tax expense (benefit) $150 $(53)
Income tax expense $166 $502 
Effective tax rate  25.8%  56.4%  37.4%  39.2%
     For the three months ended JuneSeptember 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 state and local income tax rate as a result of the Reliant Energy acquisition and the sale of the MIBRAG facility.valuation allowance. For the three months ended JuneSeptember 30, 2008, NRG’s effective tax rate was increased primarily due to the movementimpact of the valuation allowance established as result of capital losses generated in the period for which there is no projected capital gain or available tax planning strategies.state and local income taxes.
     Income taxes included in continuing operations were as follows:
                
 Six months ended June 30,   Nine months ended September 30,  
(In millions except otherwise noted) 2009 2008 2009 2008
Income tax expense $448 $1  $614 $503 
Effective tax rate  41.5%  20.0%  40.3%  39.1%
     For the sixnine months ended JuneSeptember 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 induring the six month periodnine months for which there are no projected capital gains or available tax planning strategies. Furthermore, the effective tax rate is decreased by the sale of the MIBRAG facility as well as a reduction of the state and local income tax rate as a result of the Reliant Energy acquisition. For the sixnine months ended JuneSeptember 30, 2008, NRG’s overall effective tax rate was reducedincreased primarily by foreign earnings that are taxed at rates in foreign jurisdictions lower thandue to the U.S. statutory rate.

impact of state and local income taxes.
Deferred tax assets, liabilities and valuation allowance
     On a provisional basis, NRG established deferred tax assets of $1,205$1,203 million and deferred tax liabilities of $1,194$1,189 million as a result of NRG’s acquisition of Reliant Energy.

37

     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 JuneSeptember 30, 2009, the Company’s valuation allowance was increased by approximately $80$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 $10$13 million.
Uncertain tax benefits
     As of JuneSeptember 30, 2009, NRG has recorded a $463$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 $9$11 million for the sixnine months ended JuneSeptember 30, 2009, and has accrued approximately $17$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.

40

Tax Receivable and Payable
     As of JuneSeptember 30, 2009, the Company has recorded a tax receivable of approximately $49$51 million that represents a domestic federal tax receivable of $9 million and state tax receivable of $40$42 million, net of $6 million reserve. In addition, the Company has recorded a current payable of approximately $13$56 million which includes domestic tax payable of approximately $1$45 million as well as foreign taxes payable of approximately $12$11 million.

38

Note 1314 — 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 sixnine months ended JuneSeptember 30, 2009, was $14$22 million. NRG expects to make $16$5 million in further contributions for the remainder of 2009. The total 2009 planned contribution of $30$27 million was a decrease of $30$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  Defined Benefit Pension Plans
 Three months ended June 30, Six months ended June 30,    Three months  ended September 30,     Nine months ended September 30,  
(In millions) 2009 2008 2009 2008  2009 2008        2009 2008
Service cost benefits earned  $ 3  $ 3  $ 7  $ 7  $ 4 $   4 $   11 $  11 
Interest cost on benefit obligation 5 4 10 9  5 4 15 13 
Prior service cost 1 — 1 —  — — 1 — 
Net gain —  (1) —  (1) — — —  (1)
Expected return on plan assets  (4)  (3)  (8)  (7)  (4)  (4)  (12)  (11)
Net periodic benefit cost  $ 5  $ 3  $ 10  $ 8  $ 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 June 30, Six months ended June 30, 
(In millions) 2009 2008 2009 2008
Service cost benefits earned $1 $— $2 $1 
Interest cost on benefit obligation 1 2 3 3 
Net periodic benefit cost $2 $2 $5 $4 
     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 South Texas Project, or STP. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. The total amount of employer contributions reimbursed to STPNOC for the sixnine months ended JuneSeptember 30, 2009, was $2$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 both the three months ended JuneSeptember 30, 2009, and 2008, respectively. The Company recognized net periodic costs related to its 44% interest in STP defined benefits plans of $5$8 million and $4$6 million for the sixnine months ended JuneSeptember 30, 2009, and 2008, respectively.

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Note 1415 — 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 JuneSeptember 30, 2009, eight additional office space locations were under lease for future commitments of approximately $89$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 $266$409 million during the sixnine months ended JuneSeptember 30, 2009, as the 2009 monthly commitments were settled. In addition, NRG’s natural gas purchase commitments decreased by approximately $162$199 million during the sixnine months ended JuneSeptember 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 JuneSeptember 30, 2009. Minimum purchase commitment obligations under these agreements are as follows as of JuneSeptember 30, 2009:
                
(In millions) Fixed Pricing(a) Variable Pricing(b) Fixed Pricing(a) Variable Pricing(b)
Remainder of 2009 $46  $  85  $   23 $     36 
2010  42  8 54 7 
2011  24  —   30 3 
2012  20  —   21 1 
2013  10  —   10 — 
Total
 $142  $  93  $     138 $   47 
(a) As of June 30,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 JuneSeptember 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 3,4,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 JuneSeptember 30, 2009, and July 23,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 JuneSeptember 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 contemplatingworking 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 SFAS No. 5,Accounting for Contingencies,or SFAS 5,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. The amended complaint seeks, among other things, declaratory and injunctive relief: (i) declaring that NRG and its Board of Directors breached its fiduciary duties by summarily rejecting the October 19, 2008 Exelon offer, by resorting to defensive measures to interfere with Exelon’s tender offer, and by making false and misleading statements to NRG stockholders; (ii) compelling NRG and its Board of Directors to approve the Exelon tender offer by waiving the application of Section 203 of the Delaware General Corporation Law; (iii) compelling NRG and its Board of Directors from taking any actions with respect to regulatory authorities that would thwart or interfere with the Exelon tender offer; and (iv) compelling NRG and its Board of Directors to correct any false and misleading statements to NRG stockholders and to disclose all material facts necessary for NRG stockholders to make informed decisions regarding the October 19, 2008 Exelon offer. On April 17, 2009, NRG and NRG’s Board of Directors filed a partial motion to dismiss the amended complaint asserting that many of the claims are subject to the business judgment rule, are premature, and should be dismissed for failure to state a claim upon which relief can be granted. Briefing on the motion commenced on June 12, 2009, and concluded on July 24, 2009.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. The amended complaint seeks, among other things, declaratory and injunctive relief: (i) declaring that it is a proper class action; (ii) declaring that the NRG Board of Directors breached its fiduciary duties by summarily rejecting the October 19, 2008 Exelon offer and by resorting to defensive measures designed to prevent any potential acquirer from entering into a value-maximizing transaction with NRG; (iii) compelling NRG’s Board of Directors to engage in a dialogue with Exelon to more fully understand the October 19, 2008 offer and to determine the potential for any improvement thereon; (iv) enjoining NRG from proceeding with the acquisition of Reliant Energy’s retail business; (v) enjoining the NRG’s Board of Directors from taking any actions designed to block a transaction with Exelon; and (vi) awarding plaintiffs their costs and fees. 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. BriefingOn August 4, 2009, the plaintiffs filed a notice and proposed order of dismissal and on August 5, 2009, the motion commenced on June 11, 2009, and will conclude on a date to be determined at a July 31, 2009, hearing.court dismissed the lawsuit, thereby ending the case.

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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: (i) declaring that the action is a class action and certifying plaintiffs as class plaintiffs and counsel as class counsel; (ii) declaring that defendants breached their fiduciary duties by summarily rejecting the Exelon offer; (iii) ordering defendants to negotiate with respect to the Exelon offer or with respect to another transaction to maximize shareholder value; (iv) ordering defendants to exempt Exelon’s offer from Section 203 of the Delaware General Corporations Law; (v) awarding compensatory damages including interest; (vi) awarding plaintiffs costs and fees; and (vii) granting other relief the Court deems proper.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 theMobile-Sierrastandard 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 theMobile-Sierrapublic 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 theMobile-Sierrapresumption 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 theMobile-Sierradoctrine 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.

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     On April 27, 2009, the U.S. Supreme Court grantedcertiorariin an unrelated proceeding involving theMobile-Sierradoctrine 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 theMobile-Sierradoctrine to non-settling parties. NRG soughtcertioraribefore the U.S. Supreme Court, which was granted on April 27, 2009, and on July 8, 2009, NRG submitted its brief.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. First, itIt 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. Second, itIt 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. Last, it filed in the federal district court for the Middle District of Louisiana a Motion for an Extension of Time to File Responsive Pleadings arguing that the court should extend the May 11, 2009, deadline to respond to the February 11, 2009 lawsuit until such time as directed by the court following resolution of Louisiana Generating, LLC’s Motion for Stay of Proceedings Pending Resolution of Certain Bankruptcy Actions filed concurrently with the Motion for an Extension of Time. On May 4, 2009, the Department of Justice filed its opposition to the Motion for Stay. On June 4, 2009, after the recusal of the federal bankruptcy judge in this matter, the federal district court for the Middle District of Louisiana issued an order recommending that another bankruptcy judge be appointed to hear the matter. The decision, by the Chief Judge of the U.S. Court of Appeals for the Fifth Circuit, has yet to be made. 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.

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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. The complaint seeks injunctive and declarative relief in addition to civil penalties: (i) declaring that IRP violated the CAA through 6,304 opacity violations between 2004 and 2008; (ii) seeking civil penalties of up to $32,500 for each such violation; (iii) enjoining IRP from violating the CAA; (iv) ordering IRP to assess and mitigate any environmental injuries caused by its emissions; and (v) awarding CCP its fees and costs. 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 casematter, thereby ending the matter.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 will occuroccurred 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. To the extent the aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the funded claims reserve, NRG will be obligated to provide additional cash and common stock to satisfy the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the reserves is held by an escrow agent to complete the distribution and settlement process. Since NRG has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG recognized the issuance of the common stock as of December 6, 2003, and removed the cash amounts from the balance sheet. Similarly, NRG removed the obligations relevant to the claims from the balance sheet when the common stock was issued and cash contributed.

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     On April 3, 2006, the Company made a supplemental distribution to creditors under the Company’s Chapter 11 bankruptcy plan, totaling $25 million in cash and 5,082,000 shares of common stock. On December 18, 2008, NRG filed with the U.S. Bankruptcy Court for the Southern District of New York a Closing Report and an Application for Final Decree Closing the Chapter 11 Case for NRG Energy, Inc. et al and on December 29, 2008, the court entered the Final Decree.     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 1516 — 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,prices. On August 14, 2009, the MDPSC and thus the auction prices are expectedNew Jersey Board of Public Utilities filed an appeal of FERC’s orders to be realized.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 Staffstaff 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 1617 — 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 U.S.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 to be incurred during the remainder of 2009from 2010 through 2013 to meet NRG’s environmental commitments will be approximately $1.1 billion$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 14 — 15,Commitments and Contingencies, to this Form 10-Q,Louisiana Generating, LLC.

4648

Note 1718 — 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 1718 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.

4749

Note 1819 — Condensed Consolidating Financial Information
     As of JuneSeptember 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. These notesThe 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 JuneSeptember 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(a)
Langford Wind Power, LLC(a)
 NRG Texas Holding Inc.(a)
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(a)
NEO Freehold-Gen LLC Reliant Energy Texas Retail LLC(a)
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
(a)
Added as guarantors to the 2019 Notes on July 14, 2009.

4850

     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.

49

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended June 30, 2009
                     
          NRG Energy,      
  Guarantor Non-Guarantor Inc.     Consolidated
(In millions)
 Subsidiaries Subsidiaries (Note Issuer) Eliminations (a) Balance
 
Operating Revenues
                    
Total operating revenues $   1,025  $1,254  $32  $(74) $   2,237 
 
Operating Costs and Expenses
                    
Cost of operations  596   719   1   (74)  1,242 
Depreciation and amortization  157   54   2   —   213 
Selling, general and administrative  17   51   63   —   131 
Acquisition related transaction and integration costs  —   —   23   —   23 
Development costs  2   3   4   —   9 
 
Total operating costs and expenses  772   827   93   (74)  1,618 
 
Operating Income/(Loss)
  253   427   (61)  —   619 
Other Income/(Expense)
                    
Equity in earnings of consolidated subsidiaries  120   —   477   (597)  — 
Equity in earnings of unconsolidated affiliates  3   2   —   —   5 
Gain on sale of equity method investment  —   128   —   —   128 
Other income/(loss), net  2   (12)  (1)  —   (11)
Interest expense  (18)  (38)  (103)  —   (159)
 
Total other income/(expense)  107   80   373   (597)  (37)
 
Income/(Losses) Before Income Taxes
  360   507   312   (597)  582 
Income tax expense/(benefit)  97   174   (121)  —   150 
 
Net Income
  263   333   433   (597)  432 
Less: Net loss attributable to noncontrolling interest  (1)  —   —   —   (1)
 
Net Income attributable to NRG Energy, Inc.
 $   264  $333  $433  $(597) $   433 
 
(a)
All significant intercompany transactions have been eliminated in consolidation.

50

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Six Months Ended June 30, 2009
                     
          NRG Energy,      
  Guarantor Non-Guarantor Inc.     Consolidated
(In millions)
 Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance
 
Operating Revenues
                    
Total operating revenues $   2,591  $1,349  $32  $   (77) $   3,895 
 
Operating Costs and Expenses
                    
Cost of operations  1,294   787   4   (77)  2,008 
Depreciation and amortization  315   64   3   —   382 
Selling general and administrative  34   54   126   —   214 
Acquisition related transaction and integration costs  —   —   35   —   35 
Development costs  4   5   13   —   22 
 
Total operating costs and expenses  1,647   910   181   (77)  2,661 
 
Operating Income/(Loss)
  944   439   (149)  —   1,234 
Other Income/(Expense)
                    
Equity in earnings of consolidated subsidiaries  129   —   874   (1,003)  — 
Equity in earnings of unconsolidated affiliates  4   23   —   —   27 
Gain on sale of equity method investment  —   128   —   —   128 
Other income/(loss), net  3   (19)  2   —   (14)
Interest expense  (66)  (59)  (172)  —   (297)
 
Total other income/(expense)  70   73   704   (1,003)  (156)
 
Income/(Losses) Before Income Taxes
  1,014   512   555   (1,003)  1,078 
Income tax expense/(benefit)  349   175   (76)  —   448 
 
Net Income
  665   337   631   (1,003)  630 
Less: Net loss attributable to noncontrolling interest  (1)  —   —   —   (1)
 
Net Income attributable to NRG Energy, Inc.
 $   666  $337  $631   $(1,003) $   631 
 
(a)
All significant intercompany transactions have been eliminated in consolidation.

51

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 2009
                     
  Guarantor Non-Guarantor NRG Energy, Inc.     Consolidated
(In millions)
 Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance
 
ASSETS
Current Assets
                    
Cash and cash equivalents $   8  $   433  $   1,841  $  —  $   2,282 
Funds deposited by counterparties  468   —   —   —   468 
Restricted cash  1   18   —   —   19 
Accounts receivable, net  372   814   —   —   1,186 
Inventory  514   16   —   —   530 
Derivative instruments valuation  3,360   1,308   —   (274)  4,394 
Cash collateral paid in support of energy risk management activities  214   29   —   —   243 
Prepayments and other current assets  133   78   200   (201)  210 
 
Total current assets  5,070   2,696   2,041   (475)  9,332 
 
Net property, plant and equipment
  10,653   927   29   —   11,609 
 
Other Assets
                    
Investment in subsidiaries  421   221   16,467   (17,109)  — 
Equity investments in affiliates  31   332   —   —   363 
Capital leases and notes receivable, less current portion  4,113   483   3,018   (7,131)  483 
Goodwill  1,718   —   —   —   1,718 
Intangible assets, net  800   1,308   34   (31)  2,111 
Nuclear decommissioning trust fund  316   —   —   —   316 
Derivative instruments valuation  864   547   11   (234)  1,188 
Other non-current assets  32   10   143   —   185 
 
Total other assets  8,295   2,901   19,673   (24,505)  6,364 
 
Total Assets
 $   24,018  $   6,524  $   21,743  $  (24,980) $   27,305 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
                    
Current portion of long-term debt and capital leases $   73  $   421  $   32  $�� (73) $   453 
Accounts payable  (583)  1,010   430   —   857 
Derivative instruments valuation  2,593   1,871   6   (274)  4,196 
Deferred income taxes  575   (220)  (309)  —   46 
Cash collateral received in support of energy risk management activities  468   —   —   —   468 
Accrued expenses and other current liabilities  176   283   287   (128)  618 
 
Total current liabilities  3,302   3,365   446   (475)  6,638 
 
Other Liabilities
                    
Long-term debt and capital leases  2,576   953   11,896   (7,131)  8,294 
Nuclear decommissioning reserve  292   —   —   —   292 
Nuclear decommissioning trust liability  217   —   —   —   217 
Deferred income taxes  684   124   756   —   1,564 
Derivative instruments valuation  275   776   89   (234)  906 
Out-of-market contracts  259   150   —   (31)  378 
Other non-current liabilities  419   29   466   —   914 
 
Total non-current liabilities  4,722   2,032   13,207   (7,396)  12,565 
 
Total liabilities
  8,024   5,397   13,653   (7,871)  19,203 
 
3.625% Preferred Stock  —   —   247   —   247 
Stockholders’ Equity
  15,994   1,127   7,843   (17,109)  7,855 
 
Total Liabilities and Stockholders’ Equity
 $   24,018  $   6,524  $   21,743  $  (24,980) $   27,305 
 
(a)
All significant intercompany transactions have been eliminated in consolidation.

52

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Six Months Ended June 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 $   666  $   337  $   631  $ (1,003) $   631 
Adjustments to reconcile net income to net cash provided by operating activities:                    
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries  197   (23)  (544)  343   (27)
Depreciation and amortization  315   64   3   —   382 
Provision for bad debts  —   9   —   —   9 
Amortization of nuclear fuel  19   —   —   —   19 
Amortization of financing costs and debt discount/premiums  —   7   14   —   21 
Amortization of intangibles and out-of-market contracts  (49)  64   —   —   15 
Changes in deferred income taxes and liability for unrecognized tax benefits  100   14   331   —   445 
Changes in nuclear decommissioning liability  15   —   —   —   15 
Changes in derivatives  (198)  (170)  —   —   (368)
Changes in collateral deposits supporting energy risk management activities  274   (29)  —   —   245 
Gain on sale of equity method investment  —   (128)  —   —   (128)
Gain on sale of assets  (1)  —   —   —   (1)
Gain on sale of emission allowances  (9)  —   —   —   (9)
Gain recognized on settlement of pre-existing relationship  —   —   (31)  —   (31)
Amortization of unearned equity compensation  —   —   13   —   13 
Changes in option premium collected, net of acquisition  (265)  (5)  —   —   (270)
Cash provided by/(used by) changes in other working capital, net of acquisition  532   170   (941)  —   (239)
 
Net Cash Provided/(Used) by Operating Activities
  1,596   310   (524)  (660)  722 
 
Cash Flows from Investing Activities
                    
Intercompany loans to from subsidiaries  (901)  —   160   741   — 
Acquisition of Reliant Energy, net of cash acquired  —   (57)  (288)  —   (345)
Investment in Reliant Energy  —   200   (200)  —   — 
Capital expenditures  (263)  (109)  (2)  —   (374)
(Increase)/decrease in restricted cash, net  6   (9)  —   —   (3)
Decrease/(increase) in notes receivable  —   (47)  36   —   (11)
Purchases of emission allowances  (52)  —   —   —   (52)
Proceeds from sale of emission allowances  15   —   —   —   15 
Investment in nuclear decommissioning trust fund securities  (172)  —   —   —   (172)
Proceeds from sales of nuclear decommissioning trust fund securities  157   —   —   —   157 
Proceeds from sale of assets, net  6   —   —   —   6 
Other investment  —   —   (5)  —   (5)
Proceeds from sale of equity method investment  —   284   —   —   284 
 
Net Cash Used by Investing Activities
  (1,204)  262   (299)  741   (500)
 
Cash Flows from Financing Activities
                    
Proceeds from intercompany loans  (188)  28   901   (741)  — 
Payment from intercompany dividends  (330)  (330)  —   660   — 
Payment of dividends to preferred stockholders  —   —   (21)  —   (21)
Receipt from/(payment of) financing element of acquired derivatives  102   (124)  —   —   (22)
Proceeds from sale of noncontrolling interest in subsidiary  —   50   —   —   50 
Proceeds from issuance of long-term debt  34   98   688   —   820 
Payment of deferred debt issuance costs  (1)  (1)  (27)  —   (29)
Payment of short and long-term debt  —   (20)  (213)  —   (233)
 
Net Cash (Used)/Provided by Financing Activities
  (383)  (299)  1,328   (81)  565 
Effect of exchange rate changes on cash and cash equivalents  —   1   —   —   1 
 
Net Decrease in Cash and Cash Equivalents
  10   274   504   —   788 
Cash and Cash Equivalents at Beginning of Period
  (2)  159   1,337   —   1,494 
 
Cash and Cash Equivalents at End of Period
 $   8  $   433  $   1,841  $   —  $ 2,282 
 
(a)
All significant intercompany transactions have been eliminated in consolidation.

53

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended JuneSeptember 30, 20082009
                                            
 NRG Energy,    NRG Energy,  
 Guarantor Non-Guarantor Inc. Consolidated  Guarantor Non-Guarantor Inc. Consolidated
(In millions)
 Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance  Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance
Operating Revenues
  
Total operating revenues     $  1,222     $  94     $  —     $  —     $  1,316  $  1,216 $  1,854 $  (1) $  (153) $  2,916 
Operating Costs and Expenses
  
Cost of operations 946 65 1  (1) 1,011  749 1,301  (1)  (156) 1,893 
Depreciation and amortization 153 8 — — 161  160 51 1 — 212 
General and administrative 18  (7) 72 — 83 
Selling, general and administrative 16 78 88 — 182 
Acquisition-related transaction and integration costs — — 6 — 6 
Development costs  (5) 1 8 — 4  1 1 10 — 12 
Total operating costs and expenses 1,112 67 81  (1) 1,259  926 1,431 104  (156) 2,305 
Operating Income/(Loss)
 110 27  (81) 1 57  290 423  (105) 3 611 
Other Income/(Expense)
  
Equity in earnings/(losses) of consolidated subsidiaries 138  (32) 303  (409) — 
Equity in losses of unconsolidated affiliates  (1)  (18) — —  (19) 
Other income, net 14  (4) 3  (1) 12 
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  (51)  (18)  (75) —  (144)   (5)  (38)  (135) —  (178)
Total other income/(expense) 100  (72) 231  (410)  (151) 
Total other (expense)/income —  (33) 461  (595)  (167)
Income/(Loss) From Continuing Operations Before Income Taxes
 210  (45) 150  (409)  (94) 
Income tax (benefit)/expense 46  (25)  (74) —  (53) 
Income/(Losses) Before Income Taxes
 290 390 356  (592) 444 
Income tax expense/(benefit)  (51) 139 78 — 166 
Income/(Loss) From Continuing Operations
 164  (20) 224  (409)  (41) 
Income from discontinued operations, net of income taxes — 265  (97) — 168 
Net Income/(Loss)
 341 251 278  (592) 278 
Less: Net loss attributable to noncontrolling interest — — — — — 
Net Income/(Loss) attributable to
NRG Energy, Inc.
     $  164     $  245     $  127 $(409)     $  127  $  341 $  251 $  278 $  (592) $  278 
(a) 
All significant intercompany transactions have been eliminated in consolidation.

5452

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the SixNine Months Ended JuneSeptember 30, 20082009
                                        
 NRG Energy,   NRG Energy,  
 Guarantor Non-Guarantor Inc. Consolidated Guarantor Non-Guarantor Inc. Consolidated
(In millions)
 Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance
Operating Revenues
  
Total operating revenues     $  2,423     $  195     $  —     $  —     $  2,618  $  3,807 $  3,203 $  31 $  (230) $  6,811 
Operating Costs and Expenses
  
Cost of operations 1,681 132 3  (1) 1,815  2,043 2,088 3  (233) 3,901 
Depreciation and amortization 306 14 2 — 322  475 115 4 — 594 
General and administrative 31  (4) 131 — 158 
Selling general and administrative 50 132 214 — 396 
Acquisition-related transaction and integration costs — — 41 — 41 
Development costs  (5) 3 18 — 16  5 6 23 — 34 
Total operating costs and expenses 2,013 145 154  (1) 2,311  2,573 2,341 285  (233) 4,966 
Operating Income/(Loss)
 410 50  (154) 1 307  1,234 862  (254) 3 1,845 
Other Income/(Expense)
  
Equity in earnings/(losses) of consolidated subsidiaries 210  (50) 445  (605) — 
Equity in losses of unconsolidated affiliates  (3)  (20) — —  (23)
Other income, net 15  (1) 8  (1) 21 
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  (102)  (39)  (159) —  (300)  (71)  (97)  (307) —  (475)
Total other income/(expense) 120  (110) 294  (606)  (302) 70 40 1,165  (1,598)  (323)
Income/(Loss) From Continuing Operations Before Income Taxes
 530  (60) 140  (605) 5 
Income tax expense/(benefit) 167  (33)  (133) — 1 
Income/(Losses) Before Income Taxes
 1,304 902 911  (1,595) 1,522 
Income tax expense 298 314 2 — 614 
Income/(Loss) From Continuing Operations
 363  (27) 273  (605) 4 
Income from discontinued operations, net of income taxes — 269  (97) — 172 
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.
     $  363     $  242     $  176 $(605)     $  176  $  1,007 $  588 $  909 $  (1,595) $  909 
(a) 
All significant intercompany transactions have been eliminated in consolidation.

5553

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2008September 30, 2009
                                        
 Non-     Non-    
 Guarantor Guarantor NRG Energy, Consolidated Guarantor Guarantor NRG Energy, Inc. Consolidated
(In millions)
 Subsidiaries Subsidiaries Inc. Eliminations (a) Balance Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance
ASSETS
ASSETS
ASSETS
 
Current Assets
  
Cash and cash equivalents $(2)     $  159     $  1,337     $  —     $  1,494  $  11 $  418 $  1,821 $  — $  2,250 
Funds deposited by counterparties — — 754 — 754  293 — — — 293 
Restricted cash 7 9 — — 16  1 25 — — 26 
Accounts receivable, net 422 42 — — 464  355 764 — — 1,119 
Inventory 443 12 — — 455  518 15 — — 533 
Derivative instruments valuation 4,600 — — — 4,600  2,517 1,010 —  (328) 3,199 
Deferred income taxes  (489) 248 342 — 101 
Cash collateral paid in support of energy risk management activities 494 — — — 494  222 253 — — 475 
Prepayments and other current assets 130 37 278  (230) 215  166 71 243  (265) 215 
Total current assets 6,094 259 2,369  (230) 8,492  3,594 2,804 2,406  (593) 8,211 
Net Property, Plant and Equipment
 10,725 791 29 — 11,545 
Net property, plant and equipment
 10,597 970 43 — 11,610 
Other Assets
  
Investment in subsidiaries 651 — 11,949  (12,600) —  530 221 16,955  (17,706) — 
Equity investments in affiliates 26 464 — — 490  35 357 — — 392 
Capital leases and note receivable, less current portion 598 435 3,177  (3,775) 435 
Capital leases and notes receivable, less current portion 4,621 507 3,018  (7,639) 507 
Goodwill 1,718 — — — 1,718  1,718 — — — 1,718 
Intangible assets, net 797 16 2 — 815  795 1,145 33  (31) 1,942 
Nuclear decommissioning trust fund 303 — — — 303  354 — — — 354 
Derivative instruments valuation 870 — 15 — 885  795 460 9  (225) 1,039 
Other non-current assets 9 4 112 — 125  37 9 135 — 181 
Total other assets 4,972 919 15,255  (16,375) 4,771  8,885 2,699 20,150  (25,601) 6,133 
Total Assets
     $  21,791     $  1,969     $  17,653 $(16,605)     $  24,808  $  23,076 $  6,473 $  22,599 $  (26,194) $  25,954 
LIABILITIES AND STOCKHOLDERS’ EQUITY
LIABILITIES AND STOCKHOLDERS’ EQUITY
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
  
Current portion of long-term debt and capital leases     $  67     $  235     $  229 $(67)     $  464  $  67 $  505 $  32 $  (67) $  537 
Accounts payable  (1,302) 429 1,324 — 451   (625) 1,111 239 — 725 
Derivative instruments valuation 3,976 3 2 — 3,981  1,971 1,370 4  (328) 3,017 
Deferred income taxes 503 31  (333) — 201 
Cash collateral received in support of energy risk management activities 760 — — — 760  293 — — — 293 
Accrued expenses and other current liabilities 507 48 333  (164) 724  270 273 291  (198) 636 
Total current liabilities 4,511 746 1,555  (231) 6,581  1,976 3,259 566  (593) 5,208 
Other Liabilities
  
Long-term debt and capital leases 2,730 1,014 7,729  (3,776) 7,697  2,580 890 12,398  (7,639) 8,229 
Nuclear decommissioning reserve 284 — — — 284  296 — — — 296 
Nuclear decommissioning trust liability 218 — — — 218  249 — — — 249 
Deferred income taxes 705  (187) 672 — 1,190  670 111 791 — 1,572 
Derivative instruments valuation 348 46 114 — 508  315 679 90  (225) 859 
Out-of-market contracts 291 — — — 291  229 126 —  (31) 324 
Other non-current liabilities 405 44 220 — 669  425 26 687 — 1,138 
Total non-current liabilities 4,981 917 8,735  (3,776) 10,857  4,764 1,832 13,966  (7,895) 12,667 
Total liabilities
 9,492 1,663 10,290  (4,007) 17,438  6,740 5,091 14,532  (8,488) 17,875 
3.625% Preferred Stock
 — — 247 — 247  — — 247 — 247 
Stockholders’ Equity
 12,299 306 7,116  (12,598) 7,123  16,336 1,382 7,820  (17,706) 7,832 
Total Liabilities and Stockholders’ Equity
     $  21,791     $  1,969     $  17,653 $(16,605)     $  24,808  $  23,076 $  6,473 $  22,599 $  (26,194) $  25,954 
(a) 
All significant intercompany transactions have been eliminated in consolidation.

5654

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the SixNine Months Ended JuneSeptember 30, 20082009
                     
      Non- NRG Energy,      
  Guarantor Guarantor Inc.     Consolidated
(In millions)
 Subsidiaries Subsidiaries (Note Issuer) Eliminations(a) Balance
 
Cash Flows from Operating Activities
                    
Net income     $  363      $  242      $  176  $(605)     $  176 
Adjustments to reconcile net income to net cash provided by operating activities                    
Distributions and equity (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries  (207)  79   (445)  605   32 
Depreciation and amortization  306   14   2   —   322 
Amortization of nuclear fuel  30   —   —   —   30 
Amortization of financing costs and debt discount/premiums  —   8   11   —   19 
Amortization of intangibles and out-of-market contracts  (147)  —   —   —   (147)
Changes in deferred income taxes and liability for unrecognized tax benefits  (159)  (52)  307   —   96 
Changes in nuclear decommissioning liability  17   —   —   —   17 
Changes in derivatives  664   5   —   —   669 
Changes in collateral deposits supporting energy risk management activities  (328)  —   —   —   (328)
Loss on disposal and sale of assets  2   —   —   —   2 
Gain on sale of discontinued operations  —   (270)  —   —   (270)
Gain on sale of emission allowances  (42)  —   —   —   (42)
Amortization of unearned equity compensation  —   —   14   —   14 
Changes in option premium collected  99   —   —   —   99 
Cash provided by/(used by) changes in other working capital, net of dispositions affects  185   96   (534)  —   (253)
 
Net Cash Provided by/Used by Operating Activities
  783   122   (469)  —   436 
 
Cash Flows from Investing Activities
                    
Intercompany (loans to)/receipts from subsidiaries  (81)  —   444   (363)  — 
Capital expenditures  (201)  (204)  (4)  —   (409)
Increase in restricted cash  —   (1)  —   —   (1)
Decrease in notes receivable  —   21   —   —   21 
Purchases of emission allowances  (4)  —   —   —   (4)
Proceeds from sale of emission allowances  61   —   —   —   61 
Investment in nuclear decommissioning trust fund securities  (285)  —   —   —   (285)
Proceeds from sales of nuclear decommissioning trust fund securities  269   —   —   —   269 
Proceeds from sale of discontinued operations and assets, net of cash divested  —   (59)  288   —   229 
Proceeds from sale of assets  14   —   —   —   14 
Equity investment in unconsolidated affiliate  —   —   (17)  —   (17)
 
Net Cash Provided/Used by Investing Activities
  (227)  (243)  711   (363)  (122)
 
Cash Flows from Financing Activities
                    
(Payments)/proceeds for intercompany loans  (523)  79   81   363   — 
Receipt/(Payment) from intercompany dividend  —   17   (17)  —   — 
Payments for dividends to preferred stockholders  —   —   (28)  —   (28)
Payment of financing element of acquired derivatives  (28)  —   —   —   (28)
Payments for treasury stock  —   —   (55)  —   (55)
Proceeds from issuance of common stock, net of issuance costs  —   —   8   —   8 
Proceeds from sale of noncontrolling interest on subsidiary  —   50   —   —   50 
Proceeds from issuance of long term debt  —   10   —   —   10 
Payments for deferred debt issuance costs  —   —   (2)  —   (2)
Payments for short and long-term debt  —   (30)  (158)  —   (188)
 
Net Cash Provided by/Used by Financing Activities
  (551)  126   (171)  363   (233)
Change in cash from discontinued operations  —   43   —   —   43 
Effect of exchange rate changes on cash and cash equivalents  —   7   —   —   7 
 
Net Increase in Cash and Cash Equivalents
  5   55   71   —   131 
Cash and Cash Equivalents at Beginning of Period
  (4)  124   1,012   —   1,132 
 
Cash and Cash Equivalents at End of Period
     $  1      $  179      $  1,083      $  —      $  1,263 
 
                     
      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.

55

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.

56

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.

57

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 
 
ITEM 2(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 sixnine months ended JuneSeptember 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.

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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 JuneSeptember 30, 2009, NRG had a total global generation portfolio of 187 active operating fossil fuel and nuclear generation units, at 4746 power generation plants, with an aggregate generation capacity of approximately 24,08524,100 MW, and approximately 350550 MW under construction which includes partners’ interests of 100200 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 23,08023,095 MW of fossil fuel and nuclear generation capacity in 179 active generating units at 4342 plants. In addition, NRG has ownership interests in two wind farms representing 195 MW of wind generation capacity. The Company’s power generation facilities are most heavily concentrated in Texas (approximately 11,17511,190 MW, including the 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 JuneSeptember 30, 2009, Reliant Energy had approximately 1.6 million massMass 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.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 technology.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,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:

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     Operational Performance—The Company is focused on increasing value from its existing assets, primarily through the Company’sFORNRG 2.0 initiative, commercial operations strategy, efficiencyachieving synergies between the Company’s retail and wholesale business in Texas, and maintenancemaintaining of appropriate levels of liquidity, debt and equity in order to ensure continued access to capital.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’sRepoweringNRG 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 reducereduced environmental impacts, including facilities that either have near zero GHG emissions or can be equipped to capture and sequester GHG emissions. SeveralIn addition, several of the Company’s originalRepoweringNRG 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.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. AtDuring the endfirst nine months of the second quarter 2009, there were some indications that the nation’s credit markets beganhave recovered to recoversome extent although credit continued to be tight relative to previous years.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 $4.0$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 expects to continue to manage commodity price volatility through its strategic hedging program, under which the Company expects to hedge revenues and fuel costs. This program should provide the Company with the flexibility to enter into hedges opportunistically, such as when gas prices are increasing, while at the same time protecting NRG against longer-term volatility in the commodity markets. 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 Riskfor further discussion.
     The addition of Reliant Energy to NRG’s existing generation portfoliobusiness 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 and therebyin 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 the generationits 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 $17$39 million as of Junefor the period October 1, 2008, through September 30, 2009, of which $9$31 million was for the sixnine months ended JuneSeptember 30, 2009. In the third quarter 2009, the Company expects to incur an additional $19 million of expenditures related to the Exelon defense.
Environmental Matters
Climate Change
     On June 26, 2009, the House of Representatives passedSenators Kerry and Boxer introduced climate legislation based onThe American Clean Energy and Security Act of 2009. This comprehensivewhich passed the House of Representatives in June 2009. The Senate bill proposes a multi-sector, market based greenhouse gas cap and tradecap-and-trade system starting in 2012 as well as national Renewable Energy Standards, expedited transmission planning and approval and aggressive efficiency measures. The bill2012. It provides for a declining cap in U.S. GHG emissions and provides for the allocation of allowances to merchant coal generators, and local distribution companies, 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. The bill further exempts CO2 from regulation under New Source Review, or NSR, as a criteria pollutant, or a hazardous air pollutant under the CAA. It proposes requirements for new coal-fueled power plants to implement, based on commercial availability, carbon capture and sequestration to reduce CO2 emissions. The debate will now move to the Senate. 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 in the U.S. 60 million metric tonnes of CO2.from its domestic operations. If the Waxman-Markeyclimate 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 itsRepoweringNRG and econrg programs. The Company’s multifold strategy is discussed in greater detail in Part I, Item 1 —Business, Carbon Updatein 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. The proposed endangerment finding does not include any proposed regulations. This isOn 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 inMassachusetts 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. Absent eventual action from CongressUnder 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 climate change, this finding could ultimately serve asNRG would be a statutory requirement to install BACT determined on a case-by-case basis, for rulemaking for stationary sources, likemajor modifications or improvements at power plants underif 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 CAA.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 has prepared anNRG’s planned environmental capital expenditure planexpenditures 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 anticipationthe Federal Register on May 1, 2009. While none of these actions directly impact NRG at this point, it is unknown if any such requirements.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.
     On April 24, 2009, In the U.S. EPA granted petitions to reconsider three NSR rules; Fugitive Emissions, PM2.5 Implementation,absence of federal regulations, some states in which NRG operates, such as California, Connecticut, Delaware and Reasonable Possibility. A NoticeNew York, are moving ahead with guidance for reconsideration of the PM2.5 implementation Rule was published in Federal Registermore stringent requirements for once through cooled units which may have an impact on May 1, 2009. While none of these actions directly impact NRG at this point, it is unknown if final rules will impact future projects.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 CO2cap-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.

6265

Texas Region
     On October 6, 2008, as part of its determination of Competitive Renewable Energy Zones, or CREZ, the Public Utility Commission of Texas, or 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 12,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.

6366

Consolidated Results of Operations
     The following table provides selected financial information for the Company:
                                                
 Three months ended June 30, Six months ended June 30,  Three months ended September 30, Nine months ended September 30,
(In millions except otherwise noted) 2009 2008 Change % 2009 2008 Change % 2009 2008 Change % 2009 2008 Change %
Operating Revenues
  
Energy revenue   $725 $1,373  (47)%       $1,612 $2,298  (30)%    $ 771 $ 1,373  (44)% $ 2,383 $ 3,671  (35)%   
Capacity revenue 253 334  (24) 513 681  (25) 278 356  (22) 791 1,037  (24)
Retail revenue 1,250 — N/A 1,250 — N/A  1,876 — N/A 3,126 — N/A 
Risk management activities  (12)  (588)    (98) 425  (717)    (159) 6 744  (99) 431 27 N/A 
Contract amortization  (53) 88  (160)  (32) 157  (120)  (60) 76  (179)  (92) 233  (139)
Thermal revenue 21 23  (9) 55 59  (7) 22 26  (15) 77 85  (9)
Other revenues 53 86  (38) 72 140  (49) 23 37  (38) 95 177  (46)
   
Total operating revenues 2,237 1,316 70 3,895 2,618 49  2,916 2,612 12 6,811 5,230 30 
Operating Costs and Expenses
  
Cost of sales (including risk management activities
of $204 and $136 for the three and six months
ended June 30, 2009, respectively)
 971 783 24 1,492 1,353 10 
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 271 228 19 516 462 12  281 217 29 797 679 17 
   
Total cost of operations 1,242 1,011 23 2,008 1,815 11  1,893 997 90 3,901 2,812 39 
Depreciation and amortization 213 161 32 382 322 19  212 156 36 594 478 24 
Selling, general and administrative 131 83 58 214 158 35  182 75 143 396 233 70 
Acquisition-related transaction and integration costs 23 — N/A 35 — N/A  6 — N/A 41 — N/A 
Development costs 9 4 125 22 16 38  12 13  (8) 34 29 17 
   
Total operating costs and expenses 1,618 1,259 29 2,661 2,311 15  2,305 1,241 86 4,966 3,552 40 
   
Operating income
 619 57 N/A 1,234 307 302 
Operating Income
 611 1,371  (55) 1,845 1,678 10 
Other Income/(Expense)
  
Equity in earnings/(losses) of unconsolidated
affiliates
 5  (19) 126 27  (23) 217 
Equity in earnings of unconsolidated affiliates 6 58  (90) 33 35  (6)
Gain on sale of equity method investments 128 — N/A 128 — N/A  — — — 128 — N/A 
Other income, net  (11) 12  (192)  (14) 21  (167)
Other income/(loss), net 5  (7) 171  (9) 14  (164)
Interest expense  (159)  (144) 10  (297)  (300)  (1)  (178)  (142) 25  (475)  (442) 7 
   
Total other expense  (37)  (151)  (75)  (156)  (302)  (48)  (167)  (91) 84  (323)  (393)  (18)
   
Income/(Losses) from Continuing Operations before
income tax expense
 582  (94) N/A 1,078 5 N/A 
Income tax expense/(benefit) 150  (53) 383 448 1 N/A 
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/(Losses) from Continuing Operations
 432  (41) N/A 630 4 N/A 
Income from Continuing Operations
 278 778  (64) 908 782 16 
Income from discontinued operations, net of income
taxes
 — 168 N/A — 172 N/A  — — — — 172 N/A 
   
Net Income
 432 127 240 630 176 258  278 778  (64) 908 954  (5)
   
Less: Net loss attributable to noncontrolling interest  (1) — N/A  (1) — N/A  — — —  (1) — N/A 
   
Net income attributable to NRG Energy, Inc.
   $433 $127 241    $631 $176 259  $ 278 $ 778  (64) $ 909 $ 954  (5)
   
Business Metrics
  
Average natural gas price — Henry Hub ($/MMBtu) 3.68 11.32  (67)% 4.13 9.95  (58)%
Average natural gas price - Henry Hub ($/MMBtu) 3.15 9.11  (65)% 3.80 9.67  (61)%
N/A — Not Applicable
N/A— Not Applicable

6467

Management’s discussion of the results of operations for the three months ended JuneSeptember 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 twothree months ended JuneSeptember 30, 2009:
                    
                            
 Three months ended June 30,  Three months ended September 30,
 2009 2008     2009  2008  
 Total excluding      Total excluding    
(In millions) Consolidated Reliant Energy Reliant Energy Consolidated Change %   Consolidated Reliant Energy Reliant Energy Consolidated Change %
  
Operating Revenues
  
Energy revenue $725 $— $725 $1,373  (47)%    $ 771 $ — $ 771 $ 1,373  (44)%
Capacity revenue 253 — 253 334  (24) 278 — 278 356  (22)
Retail revenue 1,250 1,250 — — N/A  1,876 1,876 — — — 
Risk management activities  (12) —  (12)  (588)    (98) 6  (1) 7 744  (99)
Contract amortization  (53)  (75) 22 88  (75)  (60)  (85) 25 76  (67)
Thermal revenue 21 — 21 23  (9) 22 — 22 26  (15)
Other revenues 53 — 53 86  (38) 23 — 23 37  (38)
    
Total operating revenues 2,237 1,175 1,062 1,316  (19) 2,916 1,790 1,126 2,612  (57)
Operating Costs and Expenses
  
Cost of sales (including risk management activities) 971 614 357 783  (54)
Cost of sales 1,628 1,203 425 780  (46)
Risk management activities  (16) —  (16) — N/A 
Other operating costs 271 41 230 228 1  281 60 221 217 2 
    
Total cost of operations 1,242 655 587 1,011  (42) 1,893 1,263 630 997  (37)
Depreciation and amortization 213 43 170 161 6  212 42 170 156 9 
Selling, general and administrative 131 49 82 83  (1) 182 76 106 75 41 
Acquisition-related transaction and integration costs 23 — 23 — N/A  6 — 6 — N/A 
Development costs 9 — 9 4 125  12 — 12 13  (8)
    
Total operating costs and expenses 1,618 747 871 1,259  (31) 2,305 1,381 924 1,241  (26)
    
Operating income
 619 428 191 57 235%
Operating Income
 $ 611 $ 409 $ 202 $ 1,371  (85)%
     
Operating Revenues
     Operating revenues, excluding risk management activities, increased by $345 million$1.0 billion during the three months ended JuneSeptember 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 $648$602 million during the three months ended JuneSeptember 30, 2009, compared to the same period in 2008:
 o 
Texas —— energy revenue decreased by $325$201 million, with $283$177 million of the decrease driven by lower energy prices and $42$24 million of the decrease driven by a reduction in generation. The average realized energy price decreased by 32%21%, driven by a 63%53% decrease in merchant prices offset by a 25%21% increase in contract prices. Generation decreased by 5%3% driven by a 9%an 11% decrease in coal plant generation and a 13%an 8% decrease in gasnuclear plant generation, offset by a 17%47% increase in nucleargas 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 the second quarter 2008. Coal plant generation was adversely affected by lower energy prices driven by a 68%64% decrease in average natural gas prices in combination with depressed heat rates in the region. Increased wind generation shifted the coal unit’s position in the bid stack which also negatively affected coal plant generation. The 2008 period contained a planned outage at the Company’s nuclear plant which did not occur in 2009 resulting in an increase in plant generation.prices.

65

 o 
Northeast —— energy revenue decreased by $206$201 million, with $83$120 million driven by lower energy prices and $147$99 million attributable to a reduction in generation offset by a $24an $18 million increase from higher net contract revenue. MerchantAverage merchant energy prices were lower by an average of 56%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 50%30% with a 51%34% decrease in coal generation and a 41%9% decrease in oil and gas generation. Weakened demand for power combined with lowlower gas prices resultedresulting in reduced merchant energy prices. Lower merchant energy prices combined with higher costcosts of production from the introduction of RGGI resultedresulting in increased hours where the unitscoal plants were uneconomicuneconomical to dispatch. The decline in oil and gas generation is attributable to fewer reliability run hours at the Connecticut plants and a planned major maintenance outage at the Arthur Kill plant.

68

 o 
South Central— energy revenue decreased by $49$55 million due to a $27$24 million decline in contract revenue coupled with a decrease of $22$31 million in merchant energy revenues. The decline in contract energy price was driven by a $9$7 million decrease in fuel cost pass through from the cooperatives and an $18a $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 12%7% while the average realized price on contract energy sales was $22.98$22.83 per MWh in 2009 compared to $30.23$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 $22$31 million decline in revenue. Megawatt hours sold to the merchant market increased by 43%18% as increased use of the region’s tolled facility provided additional energy to the merchant market while prices fell by 61%.
o
West —decreased by $8 million due to a 33% decline in merchant energy prices and a 31% decrease in generation.
 o 
Intercompany energy revenuesrevenue —— intercompany sales of $54$144 million by NRG’sthe Company’s Texas region to Reliant Energy iswere eliminated in consolidation.
 • 
Capacity revenue —decreased $81$78 million during the three months ended JuneSeptember 30, 2009, compared to the same period in 2008:
 o 
Texas —— capacity revenue decreased by $72$79 million due to a lower proportion of baseload contracts which contained a capacity component.
 o 
South Central —— capacity revenue increased by $7a $12 million primarily resulting from a new capacity agreement.
 o 
Intercompany capacity revenue —— intercompany sales of $12$18 million by NRG’sthe Company’s Texas region to Reliant Energy iswere eliminated in consolidation.
 • 
RetailContract amortization revenue —the acquisition of Reliant Energy contributed $1.3 billion of retail revenue during the two months ended June 30, 2009. This includes mass revenues of $761 million, C&I revenues of $437 million, and supply management revenues of $52 million.
•
Contract amortization revenue— decreased by $141$136 million in the three months ended JuneSeptember 30, 2009, as compared to the same period in 2008. The decrease includes $75$85 million in amortization expense of intangible assetsnet in-market C&I contracts related to the Reliant Energy acquisition in 2009 and a reduction of $66$52 million in revenue from the Texas Genco acquisition due to the lower volume of contracted energy.
 • 
Other revenues —— decreased by $33$14 million driven by $24$15 million in lower ancillary revenue and $26$13 million in lower emissions revenues. These decreases were offset by the recognition of a $31$12 million non-cash gain related to the settlement of pre-existing in-the-money contract with Reliant Energy.increase in fuels trading.

66

Cost of Operations
Cost of operations, excluding risk management activities, increased $435$912 million during the three months ended JuneSeptember 30, 2009, compared to the same period in 2008.
 • 
Cost of energysales —— increased $392$848 million during the three months ended JuneSeptember 30, 2009, compared to the same period in 2008 due to:
 o 
Retail —Reliant Energy incurred $803 million$1.2 billion of cost of energy during the twothree months ended JuneSeptember 30, 2009,2009. Supply costs were $837 million which included $66$162 million of intercompany purchased energysupply 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 $166$81 million due to lower natural gas and ancillary services costs offset by an increase in coal costs. Natural gas costs decreased $150$84 million, reflecting a 68%64% decline in average natural gas per MMBtu prices andoffset by a 13% decrease47% increase in gas-fired generation. Coal costs increased $3decreased $7 million due to $1011% lower generation. In addition, a $19 million decrease in higher prices and $4 million from higher transportationancillary service costs was offset by a $12$13 million decrease due to 5% lower generation. Ancillary service costs decreased by $12 million due to a decreaseincrease in purchased ancillary services costs incurred to meet contract obligation.energy and other fuel costs.
 o 
Northeast —— cost of energy decreased $123$86 million due to a $78$53 million reduction in natural gas and oil costs and a $48$39 million reduction in coal costs. Natural gas and oil costs decreased due to 41% lower generation and 68%67% lower average natural gas prices.prices and 9% lower generation. Coal costs decreased by $33 million due to 51%34% lower coal generation.generation and by $6 million due to lower prices. These decreases were offset by a $3$6 million increase in costs related to RGGI which became effective in 2009.
 o 
South Central —— cost of energy decreased $32$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 lower costs related to market purchases.
o
West— cost of energy decreased $9a $14 million due to a 67% decrease in average natural gas per MMBtu prices and an 11% decrease in natural gas consumption.costs reflecting 88% lower generation and 61% lower average gas prices.
 o 
Intercompany cost of energysales —— intercompany purchases of $66$162 million by Reliant Energy from NRG’sthe Company’s Texas region is eliminated in consolidation.

69

 • 
Other operating expensescost of operations —increased $43$64 million during the three months ended JuneSeptember 30, 2009, compared to the same period in 2008. Reliant Energy incurred $41$37 million related to customer service operations and $24 million in other operating costsgross 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
 $ —  $ —  $ —  $ — 
 

70

     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 twothree months ended JuneSeptember 30, 2009. Further, operating
•
Consultant costs —increased $18 million consisting of non-recurring costs related to Exelon’s exchange offer and maintenance expense increased $5proxy 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.

71

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.

72

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:
o
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.
o
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.
o
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.

74

o
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.
o
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.
o
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 of $4increased 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 $780$556 million during the threenine months ended JuneSeptember 30, 2009, compared to the same period in 2008. The breakdown of changes by region follows:
                                                                
 Three months ended June 30, 2009 Nine months ended September 30, 2009 
 Reliant South          Reliant South         
(In millions) Energy Texas Northeast Central West Thermal Elimination Total  Energy Texas Northeast Central West Thermal Elimination Total 
Net gains/(losses) on settled positions, or financial income   $(114) $101 $95 $(5) $(1) $1 $— $77 
Net gains/(losses) on settled positions, or financial income in revenues $— $259 $274 $9 $(6) $4 $(9) $531 
Mark-to-market results
 
Mark-to-market results in revenues
 
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges 210  (4)  (13) — —  (1) — 192  —  (41)  (90) — 1  (2) —  (132)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity —  (14)  (9)  (12) — — —  (35)
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 93  (116)  (17)  (9) 7  (1) —  (43) — 59 89  (4)  (1) 2 14 159 
Net unrealized gains/(losses) on open positions related to trading activity —  (10) 5 6 — — — 1  —  (3) 6  (4) — — —  (1)
 
Subtotal mark-to-market results
 303  (144)  (34)  (15) 7  (2) — 115   (1)  (36)  (22)  (55) — — 14  (100)
Total derivative gain/(loss) 189  (43) 61  (20) 6  (1) — 192 
Total derivative gain/(loss) included in revenues
 —  (54) 51  (12) 6  (1)  (2)  (12) $(1) $223 $252 $(46) $(6) $4 $5 $431 
 
Total derivative gain/(loss) included in cost of operations
   $189 $11 $10 $(8) $— $— $2 $204 
                         
  Nine 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 $(316) $(17) $(6) $(7) $22  $(324)
 
Mark-to-market results in cost of operations
                        
Reversal of previously recognized unrealized losses on settled positions related to economic hedges  —   36   63   —   —   99 
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009  449   —   —   —   —   449 
Net unrealized gains/(losses) on open positions related to economic hedges  72   (84)  (20)  (26)  (14)  (72)
 
Subtotal mark-to-market results
  521   (48)  43   (26)  (14)  476 
 
Total derivative gain/(loss) included in cost of operations
 $205  $(65) $37  $(33) $8  $152 
 

6775

                 
  Three months ended June 30, 2008
          South    
  (In millions) Texas Northeast  Central  Total 
 
Net losses on settled positions, or financial income   $(48) $(34) $(4) $(86)
 
Mark-to-market results
                
Reversal of previously recognized unrealized gains on settled positions related to economic hedges  (9)  (6)  —   (15)
Reversal of previously recognized unrealized gains on settled positions related to trading activity  —   (3)  (4)  (7)
Net unrealized losses on open positions related to economic hedges  (382)  (113)  —   (495)
Net unrealized gains/(losses) on open positions related to trading activity  20   10   (15)  15 
 
Subtotal mark-to-market results
  (371)  (112)  (19)  (502)
 
                 
Total derivative loss   $(419) $(146) $(23) $(588)
 
Total derivative loss included in revenues
  (419)  (146)  (23)  (588)
Total derivative gain/(loss) included in cost of operations
   $—  $—  $—  $— 
 
                 
  Nine months ended September 30, 2008 
          South    
(In millions) Texas  Northeast  Central  Total 
 
Net losses on settled positions, or financial income $(94)    $(67) $(4) $(165)
 
Mark-to-market results
                
Reversal of previously recognized unrealized gains on settled positions related to economic hedges  (21)  (11)  —   (32)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity  1   (7)  (14)  (20)
Net unrealized gains on open positions related to economic hedges  95   58   —   153 
Net unrealized gains on open positions related to trading activity  48   11   32   91 
 
Subtotal mark-to-market results
  123   51   18   192 
 
Total derivative gain/(loss) $29     $(16) $14  $27 
 
Total derivative gain/(loss) included in revenues
  29   (16)  14   27 
Total derivative gain included in cost of operations
 $—     $—  $—  $— 
 
     NRG’s second quarter 2009 gain of $583 million during the nine months ended September 30, 2009, was comprised of $115$376 million of mark-to-market gains and $77$207 million in settled gains, or financial income.gains. Of the $115$376 million of mark-to-market gains there was a $192$476 million gain represented the reversal of mark-to-market losses recognized on economic hedgesin expense and a $35$100 million loss representsin revenue. The $100 million loss in revenue consisted of a loss of $257 million from the reversal of mark-to-market gains recognized on trading activity during 2008. The $432008 offset by $158 million loss from economic hedge positions included a $40 million decreasedue to the increase in value inof the forward purchases and sales of electricity and fuel. The $158 million gain consists of a $217 million gain recognized in earnings from previously deferred amounts in OCI as the Company discontinued cash flow hedge accounting in the first quarter for certain 2009 transactions in Texas and New York due to lower expected generation, offset by a $59 million decrease in value in forward sales of electricity and fuel due to higherlower forward power and gas prices,prices. The Company recognized a derivative loss of $29 million resulting from discontinued NPNS designated coal purchases due to expected lower coal consumption and accordingly the Company could not assert taking physical delivery of coal purchase transactions under NPNS designation. This amount was included in the Company’s cost of operations during the nine months ended September 30, 2009. The gain of $476 million in expense consists of $449 million of the Reliant Energy roll-off of loss positions, $99 million from the reversal of mark-to-market losses recognized during 2008 and a $3$72 million loss primarily from hedge accounting ineffectiveness related to gas tradesthe decrease in the Texas region which was driven by decreasingvalue of forward gas prices while forward power prices decreased at a slower pace.purchases of electricity and fuel.
     Reliant Energy gains of $210 million represents the roll-off ofEnergy’s loss positions were acquired as of May 1, 2009, and valued at that date’susing forward prices which areon that date. The $448 million roll-off amounts were offset by therealized losses at the settled prices and are reflected in the cost of operations.operations during the same period.
     Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy, 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 second quarternine months ended September 30, 2009, the settled and forward prices of electricity and natural gas decreased resulting in the recognition of realized gains while forward power and gas prices decreased resulting in the recognition of unrealized mark-to-market gains, while ingains. During the second quarternine months of 2008, increasingdecreasing forward prices of electricity and natural gas resulted in recognition of unrealized mark-to-market gains while the settled prices for power and gas increased resulting in the recognition of realized losses.
     The following table represents the results of the Company’s financial and physical trading of energy commodities for the nine 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.
         
  Nine months ended 
  September 30, 
(In millions) 2009  2008 
 
Trading gains/(losses)        
Realized $100  $58 
Unrealized  (126)  72 
 
Total trading gains/(losses)  (26)  130 
 

76

Depreciation and Amortization
     NRG’s depreciation and amortization expense increased by $52$116 million for the threenine months ended JuneSeptember 30, 2009, compared to the same period in 2008. Reliant Energy’s depreciation and amortization expense for the twofive month period was $43 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 on line in late 2008.
Selling, General and Administrative Expenses
     Selling, general and administrative expenses increased by $48 million for the three months ended June 30, 2009, compared to the same period in 2008. The increase was due to:
•
Retail selling, general and administrative expense —totaled $49 million, including $9 million of bad debt expense during the two months ended June 30, 2009.
•
Consultant costs —increased $2 million consisting of costs related to Exelon’s exchange offer and proxy contest efforts of $4 million offset by a decrease in other consulting costs of $3 million.
•
Wage and benefits expense —increased $3 million.
     These increases were offset by:
•
Other expenses —decreased by $5 million consisting of information technology, administrative fees and travel related costs.

68

Acquisition-related Transaction and Integration Costs
       NRG incurred Reliant Energy acquisition-related transaction costs of $21 million and integration costs of $2 million for the three months ended June 30, 2009.
Equity in Earnings of Unconsolidated Affiliates
     NRG’s equity earnings from unconsolidated affiliates increased by $24 million for the three months ended June 30, 2009, compared to the same period in 2008. During the three months ended June 30, 2009, Sherbino recognized a $6 million mark-to-market unrealized loss whereas in the three months ended June 30, 2008 Sherbino recognized a $32 million mark-to-market loss on a natural gas swap executed to hedge its future power generation. Additionally, in 2009, the Company’s share in NRG Saguaro LLC earnings increased by $2 million.
Gain on Sale of Equity Method Investments and Other (Loss)/Income, Net
     NRG’s gain on sale of equity method investments increased by $128 million for the three months ended June 30, 2009, compared to the same period in 2008 and other (loss)/income, net decreased by $23 million for the three months ended June 30, 2009, compared to the same period in 2008. The 2009 amounts include a $128 million gain on the sale of NRG’s 50% ownership interest in MIBRAG and a $15 million realized loss on a forward contract for foreign currency executed to hedge the sale proceeds from the MIBRAG sale.
Interest Expense
       NRG’s interest expense increased by $15 million for the three months ended June 30, 2009, compared to the same period in 2008. This increase was primarily due to $13 million in fees incurred on the CSRA facility for the months of May and June.
Income Tax Expense
       NRG’s income tax expense increased by $203 million for the three months ended June 30, 2009, compared to the same period in 2008. The increase in income tax expense was primarily due to an increase in income. The effective tax rate was 25.8% and 56.4% for the three months ended June 30, 2009, and 2008, respectively.
       For the three months ended June 30, 2009, NRG’s overall effective tax rate on continuing operations was different than the statutory rate of 35% primarily due to a reduction in the state and local income tax rate as a result of the Reliant Energy acquisition and the sale of the MIBRAG facility. For the three months ended June 30, 2008, NRG’s effective tax rate was increased primarily due to the movement of the valuation allowance established as result of capital losses generated in the period for which there is no projected capital gain or available tax planning strategies.
Income from Discontinued Operations, Net of Income Tax Expense
       For the three months ended June 30, 2008, NRG recorded income from discontinued operations, net of income tax expense, of $168 million. NRG closed the sale of ITISA during the second quarter 2008.

69

Management’s discussion of the results of operations for the six months ended June 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 two months ended June 30, 2009:
                         
       
  Six months ended June 30,    
  2009 2008        
          Total excluding        
(In millions) Consolidated Reliant Energy Reliant Energy Consolidated Change %    
 
Operating Revenues
                        
Energy revenue $1,612  $—  $1,612  $2,298   (30)%    
Capacity revenue  513   —   513   681   (25)    
Retail revenue  1,250   1,250   —   —   N/A     
Risk management activities  425   —   425   (717)  (159)    
Contract amortization  (32)  (75)  43   157   (73)    
Thermal revenue  55   —   55   59   (7)    
Other revenues  72   —   72   140   (49)    
         
Total operating revenues  3,895   1,175   2,720   2,618   4     
Operating Costs and Expenses
                        
Cost of sales (including risk management
activities)
  1,492   614   878   1,353   (35)    
Other operating costs  516   41   475   462   3     
         
Total cost of operations  2,008   655   1,353   1,815   (25)    
Depreciation and amortization  382   43   339   322   5     
Selling, general and administrative  214   49   165   158   4     
Acquisition-related transaction and integration
costs
  35   —   35   —   N/A     
Development costs  22   —   22   16   38     
         
Total operating costs and expenses  2,661   747   1,914   2,311   (17)    
         
Operating income
  1,234   428   806   307   163%    
 
Operating Revenues
     Operating revenues, excluding risk management activities, increased $135 million during the six months ended June 30, 2009, compared to the same period in 2008.
•
Energy revenue— decreased $686 million during the six months ended June 30, 2009, compared to the same period in 2008:
o
Texas— energy revenue decreased by $277 million, with $198 million by driven by lower energy prices and $79 million decrease driven by a reduction in generation. The average realized energy price decreased by 14%, driven by a 51% decrease in merchant prices offset by a 24% increase in contract prices. Generation decreased by 5% driven by a 8% decrease in coal plant generation and a 21% decrease in gas plant generation, offset by generation from the recently constructed Elbow Creek wind farm, which was not in operation in 2008. Coal plant generation was adversely affected by lower energy prices driven by a 61% decrease in average natural gas prices also in combination with depressed heat rates in the region. Increased wind generation shifted the coal unit’s position in the bid stack, negatively affecting coal plant generation.
o
Northeast— energy revenue decreased by $289 million, with $113 million driven by lower energy prices and $212 million attributable to a reduction in generation offset by a $35 million increase from higher net contract revenue. Merchant energy prices were lower by an average of 32%. 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 38%, with a 37% decrease in coal generation and a 40% decrease in oil and gas generation. Weakened demand for power combined with low gas prices resulted in reduced merchant energy prices. Lower merchant energy prices combined with higher cost of production from the introduction of RGGI resulted in increased hours where the units were uneconomic to dispatch. The decline in oil and gas generation is attributable to fewer reliability run hours at the Connecticut plants and a planned major maintenance outage at the Arthur Kill plant.

70

o
South Central— decreased by $53 million due to a $42 million decline in contract revenue coupled with an $11 million decrease in merchant energy revenues. Contract customer sales volumes were down 11%. The decline in contract energy price was driven by a $7 million decrease in fuel cost pass through to the cooperatives. Also contributing to the decline in contract revenue was $31 million due to the expiration of a contract with a regional utility. Average realized price on contract energy sales was $23.17 per MWh in 2009 compared to $28.72 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 an $11 million decline in revenue. Megawatt hours sold to the merchant market increased by 51%, while prices fell by 42%. Increased use of the region’s tolled facility provided additional energy to the merchant market.
o
Intercompany energy revenues— intercompany sales of $54 million by NRG’s Texas region to Reliant Energy is eliminated in consolidation.
•
Capacity revenue —decreased $168 million during the six months ended June 30, 2009, compared to the same period in 2008:
o
Texas— capacity revenue decreased by $143 million due to a lower proportion of baseload contracts which contained a capacity component.
o
Northeast— capacity revenue decreased by $15 million due to lower capacity prices in the NYISO and PJM markets which was partially offset by higher capacity prices in the NEPOOL market.
o
South Central— capacity revenue increased by $18 million resulting primarily from a new capacity agreement.
o
West— capacity revenue decreased by $9 million due to the expiration of a two year tolling agreement at the El Segundo facility in April 2008, which was replaced by resource adequacy and capacity contracts at lower prices.
o
Intercompany capacity revenue— intercompany sales of $12 million by NRG’s Texas region to Reliant Energy is eliminated in consolidation.
•
Retail revenue —the acquisition of Reliant Energy contributed $1.3 billion of retail revenue during the two months ended June 30, 2009. This includes mass revenues of $761 million, C&I revenues of $437 million, and supply management revenues of $52 million.
•
Contract amortization revenue— decreased by $189 million in the six months ended June 30, 2009, as compared to the same period in 2008. The decrease includes a reduction of $114 million in revenue from the Texas Genco acquisition due to the lower volume of contracted energy and $75 million in amortization expense of intangible assets related to the Reliant Energy acquisition in 2009.
•
Other revenues— decreased by $68 million driven by $30 million in lower ancillary revenue, $33 million in lower emissions revenue, and a $37 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.

71

Cost of Operations
Cost of operations, excluding risk management activities, increased $329 million during the six months ended June 30, 2009, compared to the same period in 2008.
•
Cost of energy— increased $275 million during the six months ended June 30, 2009, compared to the same period in 2008 due to:
o
Retail revenue —Reliant Energy incurred $803 million of cost of energy during the two months ended June 30, 2009 which included $66 million of intercompany purchased energy costs.
o
Texas —cost of energy decreased $250 million due to lower natural gas, coal, purchased energy and ancillary services costs. Natural gas costs decreased $197 million, reflecting a 61% decline in average natural gas per MMBtu prices and a 21% decrease in gas-fired generation. Coal costs decreased $9 million as the 2008 expense included a $15 million loss reserve related to a coal contract dispute and $12 million resulting from reduced generation. This decrease was offset by an $11 million increase due to higher prices and a $7 million increase in transportation cost. Purchased energy decreased $14 million due to a lower average price to procure energy from the market offset by a greater number of MWhs purchased. Ancillary service costs decreased by $24 million due to a decrease in purchased ancillary services costs incurred to meet contract obligations. Nuclear fuel expenses decreased by $10 million as amortization of nuclear fuel inventory ended in March 2008 related to the Texas Genco acquistion.
o
Northeast— cost of energy decreased $169 million due to a $107 million reduction in natural gas and oil costs and a $69 million reduction in coal costs. Natural gas and oil costs decreased due to 40% lower generation and 56% lower average natural gas prices. Coal costs decreased due to 37% lower coal generation. These decreases were offset by a $8 million increase in costs related to RGGI which became effective in 2009.
o
South Central— cost of energy decreased $19 million due to a $16 million decrease in purchased energy reflecting lower fuel costs associated with the region’s tolled facility and lower market energy prices, and a $4 million decrease in transmission expense due to transmission line outages.
o
West— cost of energy decreased $7 million due to a 66% decline in average natural gas per MMBtu prices offset by a $3 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.
o
Intercompany cost of energy— intercompany purchases of $66 million by Reliant Energy from NRG’s Texas region are eliminated in consolidation.
•
Other operating expenses —increased $54 million during the six months ended June 30, 2009, compared to the same period in 2008. Reliant Energy incurred $41 million in other operating costs during the two months ended June 30, 2009. Further, operating and maintenance expenses increased by $7 million and property taxes increased by $5 million.

72

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 $1,278 million during the six months ended June 30, 2009, compared to the same period in 2008. The breakdown of changes by region follows:
                                 
  Six months ended June 30, 2009 
     Reliant         South             
(In millions)    Energy Texas  Northeast  Central  West  Thermal  Elimination  Total 
 
Net gains/(losses) on settled positions, or financial income    $(114) $130  $151  $5  $(3) $2  $—  $171 
 
Mark-to-market results
                                
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges  210   (12)  (20)  —   —   (2)  —   176 
Reversal of previously recognized unrealized gains on settled positions related to trading activity  —   (43)  (23)  (38)  —   —   —   (104)
Net unrealized gains/(losses) on open positions related to economic hedges  93   88   136   (14)  6   1   —   310 
Net unrealized gains/(losses) on open positions related to trading activity  —   (8)  4   12   —   —   —   8 
 
 
Subtotal mark-to-market results
  303   25   97   (40)  6   (1)  —   390 
 
Total derivative gain/(loss)  189   155   248   (35)  3   1   —   561 
 
Total derivative gain/(loss) included in revenues
  —   209   233   (19)  3   1   (2)  425 
 
Total derivative gain/(loss) included in cost of operations
    $189  $(54) $15  $(16) $—  $—  $2  $136 
 
                 
  Six months ended June 30, 2008 
          South    
(In millions) Texas  Northeast  Central  Total 
 
 
Net losses on settled positions, or financial income    $(50) $(24) $—  $(74)
 
 
Mark-to-market results
                
Reversal of previously recognized unrealized gains on settled positions related to economic hedges  (16)  (9)  —   (25)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity  1   (2)  (11)  (12)
Net unrealized losses on open positions related to economic hedges  (495)  (142)  —   (637)
Net unrealized gains/(losses) on open positions related to trading activity  37   (7)  1   31 
 
Subtotal mark-to-market results
  (473)  (160)  (10)  (643)
 
Total derivative loss    $(523) $(184) $(10) $(717)
 
Total derivative loss included in revenues
  (523)  (184)  (10)  (717)
Total derivative gain/(loss) included in cost of operations
    $—  $—  $—  $— 
 
     NRG’s first half of 2009 gain was comprised of a $390 million of mark-to-market gains and $171 million in settled gains, or financial income. Of the $390 million of mark-to-market gains, a $176 million gain represents the reversal of mark-to-market losses recognized on economic hedges and a $104 million loss represents the reversal of mark-to-market gains recognized on trading activity during 2008. The $310 million gain from economic hedge positions included $217 million recognized in earnings from previously deferred amounts in OCI as the Company discontinued cash flow hedge accounting in the first quarter for certain 2009 transactions in Texas and New York due to lower expected generation, a $92 million increase in value in forward sales of electricity and fuel due to lower forward power and gas prices, and a $1 million gain primarily from hedge accounting ineffectiveness related to gas trades in the Texas region 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 the Company could not assert taking physical delivery of coal purchase transactions under NPNS designation. This amount was included in the Company’s cost of operations during the six months ended June 30, 2009.
     Reliant Energy gains of $210 million represents the roll-off of positions acquired as of May 1, 2009, valued at that date’s forward prices which are offset by the losses at the settled prices and are reflected in the cost of operations.
     Since these hedging activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy, 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 2008, NRG hedged a portion of the Company’s 2008 and 2009 generation. During the first half of 2009, the settled and forward prices of electricity and natural gas decreased resulting in the recognition of realized gains and unrealized mark-to-market gains, while in the first half of 2008, increasing prices of electricity and natural gas resulted in recognition of unrealized mark-to-market losses.

73

Depreciation and Amortization
     NRG’s depreciation and amortization expense increased by $60 million for the six months ended June 30, 2009, compared to the same period in 2008. Reliant Energy’s depreciation and amortization expense for the two month period was $43$85 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 2008.2008, and the Cedar Bayou 4 plant which came online in the second quarter 2009.
Selling, General and Administrative Expenses
     Selling, general and administrative expenses increased by $56$163 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008. The increase was due to:
 • 
RetailReliant Energy’s selling, general and administrative expense —totaled $49$125 million, including $9$37 million of bad debt expense incurred during the twofive months ended JuneSeptember 30, 2009.
 
 • 
Wage and benefits expense —increased $6$18 million.
 
 • 
Consultant costs —increased $5$23 million consisting of non-recurring costs related to Exelon’s exchange offer and proxy contest efforts of $9$31 million offset by a decrease in other consulting costs of $4$8 million.
     These increases were offset by:
 • 
Other expenses —decreased by $2 million consisting of information technology, administrative fees and travel related costs.million. This decrease is attributable to a bad debt write-off in 2008.
Acquisition-relatedAcquisition-Related Transaction and Integration Costs
     NRG incurred Reliant Energy acquisition-related transaction costs of $33$29 million and integration costs of $2$12 million for the sixnine months ended JuneSeptember 30, 2009.
Equity in Earnings of Unconsolidated Affiliates
     NRG’s equity earnings from unconsolidated affiliates increaseddecreased by $50$2 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008. During 2009, the Company’s share in Gladstone Power Station and MIBRAG decreased by $7 million and $11 million, respectively. These decreases were offset by the Company’s share of NRG Saguaro, LLC earnings increasing $9 million in 2009. In addition, there was a $7 million decrease in Sherbino recognized a $1 millionI Wind Farm, LLC’s mark-to-market unrealized loss whereas inas compared to 2008 Sherbino recognizedas a $50 million mark-to-market loss onresult of a natural gas swap executed to hedge itsto future power generation. Additionally, in 2009, the Company’s share in NRG Saguaro LLC earnings increased by $7 million and the Company’s share in Gladstone decreased by $4 million.
Gain on Sale of Equity Method Investments and Other Income/(Loss)/Income,, Net
     NRG’s gain on sale of equity method investments increased by $128 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008 and other (loss)/income, net decreased by $35$23 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008. The 2009 amounts include a $128 million gain on the sale of NRG’s 50% ownership interest in MIBRAG and a $24 million mark-to-market unrealized loss on a forward contract for foreign currency executed to hedge the sale proceeds from the MIBRAG sale. In addition, the 2009 interest income was lower compared to 2008 due to lower interest rates. Further in 2008, a $19 million impairment charge was incurred to restructure distressed investments in commercial paper.
Interest Expense
     NRG’s interest expense decreasedincreased by $3$33 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008. This decreaseincrease was primarily due to a $28 million increase in fees incurred during the months of May through September of 2009 on the CSRA facility, a $19 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 hedges on the Company’s Term Loan Facility and a $8 million increase in the amortization of deferred financing costs. These increases were offset by a $25 million decrease in interest expense on the Company’s Term Loan facilityFacility due to a decrease in the average interest rates and the outstanding notional amount offset by a $13 million increase in fees incurred onand lower interest rates related to the CSRA facility for the monthsunhedged portion of MayTerm Loan and June.fair value portion of Senior Notes.

7477

Income Tax Expense
     NRG’s income tax expense increased by $447$111 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008. The increase in income tax expense was primarily due to an increase in income.income coupled with the U.S. taxation of foreign earnings. The effective tax rate was 41.5%40.3% and 20.0%39.1% for the sixnine months ended JuneSeptember 30, 2009, and 2008, respectively.
     For the sixnine months ended JuneSeptember 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 induring the six month periodnine months for which there are no projected capital gains or available tax planning strategies. Furthermore, the effective tax rate is decreased by the sale of the MIBRAG facility as well as a reduction of the state and local income tax rate as a result of the Reliant Energy acquisition. For the sixnine months ended JuneSeptember 30, 2008, NRG’s overall effective tax rate was reducedincreased primarily by foreign earnings that are taxed at rates in foreign jurisdictions lower thandue to the U.S. statutory rate.impact of state and local income taxes.
Income from Discontinued Operations, Net of Income Tax Expense
     For the sixnine months ended JuneSeptember 30, 2008, NRG recorded income from discontinued operations, net of income tax expense, of $172 million. NRG closed the sale of ITISA during the second quarter 2008.

7578

Results of Operations for Reliant Energy
Reliant Energy
     The following is a detailed discussion of the results of operations of NRG’s retail business segment since the date of acquisition.
Operating Strategy
     Reliant Energy’s business is to earn a margin by selling electricity to end use customers, providing innovative and value-enhancing services to such customers, and acquiring supply for the estimated demand. As a retail energy provider, Reliant Energy arranges for the transmission and delivery of electricity to customers, bills customers, collects payment for electricity sold, develops innovative energy solutions, engages in energy efficiency initiatives and maintains call centers to provide customer service. Although NRG has begun the process of becoming the primary provider of Reliant Energy’s supply requirements, Reliant Energy presently purchases a substantial portion of its supply requirements from third parties such as generation companies and power marketers. Transmission and distribution services are purchased from entities regulated by the PUCT and subject to ERCOT protocols.
     The energy usage of Reliant Energy’s retail customers varies by season, with generally higher usage during the summer period. As a result, Reliant Energy’s net working capital requirements generally increase during summer months along with the higher revenues, and then decline during off-peak months.
     As of JuneSeptember 30, 2009, Reliant Energy had approximately 1,2741,161 employees, none of whom are covered by a bargaining agreement.
Customer Segments
     The following is a description of Reliant Energy’s significant customer segments in Texas.
 • 
Mass —Reliant Energy’s Mass customer base is made up of approximately 1.6 million residential and small business customers in the ERCOT market with more than half located in the Houston area. Reliant Energy also serves customers in other competitive markets in ERCOT including the Dallas, Fort Worth, and Corpus Christi areas.
 
 • 
Commercial and industrialC&I —Reliant Energy markets electricity and energy services to approximately 0.1 million C&I customers in Texas. These customers include refineries, chemical plants, manufacturing facilities, hospitals, universities, commercial real estate, government agencies, restaurants, and other commercial facilities.
Market Framework
     Reliant Energy operates within the same ERCOT market as the Company’s Texas region. For further discussion of the Texas market framework, see pages 25-26 of NRG Energy Inc.’s 2008 Annual Report on Form 10-K.
     For further discussion of the Company’s Reliant Energy operations, see Item I, Note 3,4,Business Acquisition.Acquisition,to this Form 10-Q.

7679

     Selected Income Statement Data
            
 Period ended Three Months Ended Period Ended
(In millions except otherwise noted) June 30, 2009(a) September 30, 2009 September 30, 2009 (a)
Operating Revenues
  
Mass revenues $761  $    1,157 $    1,918 
Commercial and industrial revenues 437  620 1,057 
Supply management revenues 52  99 151 
Risk management activities  (1)  (1)
Contract amortization  (75)  (85)  (160)
Total operating revenues 1,175  1,790 2,965 
Operating Costs and Expenses
  
Cost of energy (including risk management activities) 614  1,203 1,817 
Other operating expenses 90  136 226 
Depreciation and amortization 43  42 85 
Operating Income
 $428  $    409 $    837 
Electricity sales volume — GWh (in thousands):  
Mass 4,851  7,776 12,627 
Commercial and Industrial(c)
 5,580 
Commercial and Industrial(b)
 8,199 13,780 
Business Metrics
  
Weighted average Retail customers count (in thousands, metered locations)   
Weighted average retail customers count (in thousands, metered locations) 
Mass 1,601  1,569 1,582 
Commercial and Industrial(c)
 71 
Commercial and Industrial(b)
 68 69 
Retail customers count (in thousands, metered locations)    
Mass 1,589  1,552 1,552 
Commercial and Industrial(c)
 68 
 
Commercial and Industrial(b)
 66 66 
Cooling Degree Days, or CDDs(b)(c)
 971  1,760 2,731 
CDD’s 30 year average 819  1,611 2,430 
Heating Degree Days, or HDDs(b)(c)
 1  1 2 
HDD’s 30 year average 5  2 7 
(a) For the period May 1, 2009, to JuneSeptember 30, 2009.
(b) Includes customers of the Texas General Land Office for whom the Company provides services.
(c)National Oceanic and Atmospheric Administration-Climate Prediction Center —- A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Reliant Energy serves its customer base.

80

Quarterly results
Operating Income
     Operating income for the three months ended September 30, 2009, was $409 million, which consisted of the following:
 (c)Three Months Ended
(In millions except otherwise noted) September 30, 2009
Reliant Energy Operating Income:
Mass revenues$    1,157
Commercial and industrial revenues620
Supply management revenues99
Total retail operating revenues(a)
1,876
Retail cost of sales(a)
1,433
Total retail gross margin
443
Unrealized gains on energy supply derivatives217
Contract amortization, net(73)
Other operating expenses(136)
Depreciation and amortization(42)
Operating Income
$    409
(a)Amounts exclude unrealized gains/(losses) on energy supply derivatives and contract amortization.
•
IncludesGross margin —Reliant Energy’s gross margin totaled $443 million for the quarter, which was driven by strong margins in the mass customer segment and expanding margins in the commercial and industrial segment. Volumes were higher due to greater customer usage as a result of warmer weather as compared to the 30 year CDD average, which was partially offset by a decrease in the number of customers during the three months ended September 30, 2009. Reliant Energy announced and enacted price reductions effective June 1 and July 1, 2009, that cumulatively, lowered prices up to 20% for certain Mass customers. These lower prices, relative to lower short term supply costs, delivered strong margins. Competition, price reductions, and supply costs based on forward market prices, will likely drive lower margins in the future.
Relative to first half of 2009, competitive retail prices have decreased due to lower supply costs driven by a decline in natural gas prices. If supply costs continue to remain low, the Company expects competitive retail prices to continue to decline and place pressure on unit margins. Additionally, the Company’s customer counts have declined approximately 2% during the quarter.
•
Risk management activities —Unrealized gains of $217 million on economic hedges relates to supply contracts that were recognized for the three months ended September 2009 including $239 million of gains representing a roll-off of loss positions acquired at May 1, 2009, valued at forward prices and $21 million of losses that represents mark-to-market changes in forward value of purchased electricity and gas. The $239 million gain from roll-off of loss positions is offset by realized losses at the settled prices and reflected in the cost of operations.
Operating Revenues
     Total operating revenues for the three months ended September 30, 2009, were $1.8 billion and consisted of the following:
•
Mass revenues —totaled $1,157 million for the quarter from retail electric sales to approximately 1.6 million end use customers in the Texas market. The current quarter revenue rates reflect the price reductions of up to 20% for certain Mass customer classes that were announced and enacted effective June 1 and July 1, 2009. Also, warmer weather, as compared to the 30 year CDD average, caused an increase in customer usage. The higher prices, along with higher usage, were accompanied by a 2% decrease in the number of customers during the quarter.
•
Commercial and industrial revenue —As of May 1, 2009, Reliant Energy re-launched its C&I segment. C&I revenues for the three months ended September 30, 2009, totaled $620 million for the quarter on volume sales of approximately 8,199 GWh. Variable rate contracts tied to the market price of natural gas accounted for approximately 69% of the Texas General Land Officecontracted volumes as of September 30, 2009.
•
Contract amortization— reduced operating revenues by $85 million resulting from net in-market C&I contracts, which will continue to amortize over the term of the contracts acquired in the Reliant Energy acquisition.
•
Supply management revenues— totaled $99 million for whom the Company provides services.quarter from the sale of excess supply into various markets in Texas.

7781

Cost of Energy
     Cost of energy for the three months ended September 30, 2009, was $1,203 million and consisted of the following:
•
Supply costs— totaled $837 million for the quarter. The market cost of energy was relatively low during the quarter. This was driven by the lowest natural gas prices in the last three years for the same time period. Also, warmer weather for the period, as compared to the 30 year CDD average, caused an increase in purchased supply volumes at a relatively low cost.
•
Risk management activities— Unrealized gains of $218 million on economic hedges relate to supply contracts that were recognized for the three months ended September 30, 2009, including $239 million of gains which represent a roll-off of loss positions acquired at May 1, 2009, valued at forward prices and $21 million of losses that represent mark-to-market changes in forward value of purchased electricity and gas. The $239 million gain from roll-off positions is offset by realized losses at the settled prices and reflected in cost of operations.
•
Transmission and distribution charges— totaled $392 million for the quarter for the cost to transport the power from the generation sources to the end use customers.
•
Financial settlements— totaled $202 million of losses for the quarter resulting from financial settlement of energy related derivatives.
•
Contract amortization— reduced the cost of energy by $11 million, resulting from the net out-of-market supply contracts established at the acquisition date. These contracts will be amortized over the life of the contracts.
Other Operating Expenses
     Other operating expenses for the three months ended September 30, 2009, were $136 million, or 8% of the region’s total operating revenues. Other operating expenses consisted of the following:
•
Operations and maintenance expenses— totaled $37 million for the quarter, primarily consisted of the labor and external costs associated with customer activities, including the call center, billing, remittance processing, and credit and collections, as well as the information technology costs associated with those activities.
•
Selling, general and administrative expenses— totaled $48 million for the quarter, primarily consisted of the costs of labor and external costs associated with advertising and other marketing activities, as well as human resources, community activities, legal, procurement, regulatory, accounting, internal audit, and management, as well as facilities leases and other office expenses.
•
Gross receipts tax— totaled $24 million for the quarter or 1.3% of Mass and C&I revenues.
•
Bad debt expense— totaled $28 million for the quarter or 1.6% of Mass and C&I revenues which was driven by higher summer bills due to warmer weather and economic factors including unemployment in Dallas and Houston, which approximated national averages.

82

Year to date results
Operating Income
     Operating income for the two monthsperiod ended JuneSeptember 30, 2009, was $428$837 million, which consisted of the following:
     
  Period ended
(In millions except otherwise noted) June 30, 2009(a)
 
Reliant Energy Operating Income:
    
Mass revenues $761 
Commercial and industrial revenues  437 
Supply management revenues  52 
 
Total retail operating revenues(a)
  1,250 
 
Retail cost of sales(a)
  930 
 
Total retail gross margin
  320 
Unrealized gains on energy supply derivatives  303 
Contract amortization, net  (62)
Other operating expenses  (90)
Depreciation and amortization  (43)
 
Operating Income
 $428 
 
(a) 
Period Ended
(In millions except otherwise noted)September 30, 2009
Reliant Energy Operating Income:
Mass revenues$    1,918
Commercial and industrial revenues1,057
Supply management revenues151
Total retail operating revenues(a)
3,126
Retail cost of sales(a)
2,363
Total retail gross margin
763
Unrealized gains on energy supply derivatives520
Contract amortization, net(135)
Other operating expenses(226)
Depreciation and amortization(85)
Operating Income
$    837
(a)Amounts exclude unrealized gains/(losses) on energy supply derivatives and contract amortization.
 • 
Gross margin —— Reliant Energy’s gross margin totaled $320$763 million, which was driven by strong margins in the residentialmass customer segment and expanding margins in the commercial and industrial segment. In addition, volumesVolumes were higher due to greater customer usage as a result of warmer weather as compared to the 30 year CDD average, although partially offset by a decrease in number of customers during the twofive months ended JuneSeptember 30, 2009. The strong margins were driven by high revenue rates relative to the current market cost of energy as the Company acquired Reliant Energy customers on prices more consistent with 2008 costs of natural gas. The lag between significant declines in energy costs and the corresponding price reductions resulted in higher margins for the period. This benefit from lower cost of energy will be partially offset in future periods by the Company’sReliant Energy announced and enacted price reductions ofeffective June 1 and July 1, 2009, that cumulatively lowered prices up to 20% for certain massMass customers. These lower prices, relative to lower short term supply costs, delivered strong margins. Competition, price reductions, are consistent with recent trends in competitive offers, and the Company expects to see competitors continue to more accurately reflect their true cost of capital in their pricing. Competition, along with the Company’s pricing and supply decisions,costs based on forward market prices, will likely drive lower margins in the future and the Company believes that, in order to stabilize customer count, this level of margins will not be sustainable.future.
 
   With the decline in natural gas prices, and the corresponding decline in the cost of energy supply, competitive retail prices have decreased relative to 2008. If supply costs continue to remain low, the Company expects competitive retail prices to continue to decline and place pressure on unit margins. Additionally, the Company’s customer counts have declined approximately 1% for each of the past two months. The recent price reductions for certain mass customers are expected to improve customer retention. Further price reductions may be necessary if current attrition trends continue.4% since May 1, 2009.
 
 • 
Risk management activities —— Unrealized gains of $303$520 million on economic hedges relates to supply contracts that were recognized for the two monthsperiod ended JuneSeptember 2009 including $210$448 million of gains representing a roll-off of loss positions acquired at May 1, 2009, valued at forward prices and $93$72 million of gains that represents mark-to-market changes in forward value of purchased electricity and gas. The $210$448 million gain from roll-off of loss positions is offset by the realized losses at the settled prices and reflected in the cost of operations. In August 2009, Reliant Energy entered into two contracts to mitigate a portion of Reliant Energy’s exposure to lost revenue as a result of a hurricane during the 2009 season. The contracts premiums of $5.7 million provided coverage for a $50 million loss.

78

Operating Revenues
     Total operating revenues for the two monthsperiod ended JuneSeptember 30, 2009, were $1.2$3.0 billion and consisted of the following:
 • 
Mass revenues —— totaled $761$1,918 million from retail electric sales to approximately 1.6 million end use customers in the Texas market. Revenue rates for acquired Reliant Energy customers were not consistent with current costs of natural gas. The Company lowered prices up to 10% on select residential customer segmentsThese acquired revenue rates were reduced by Reliant Energy’s announced and enacted price reductions effective June 1 and announced another rate reduction for July. These two pricing actions will provideJuly 1, 2009 of up to 20% lower prices for certain Mass customers.customers classes. Also, warmer weather, as compared to the 30 year CDD average, caused an increase in customer usage. The higher prices, along with higher usage, were accompanied withby a 4% decrease in the number of customers by approximately 1% per month. The Company expects the announced price reductions to stem the recent attrition trends.since May 1, 2009.
 
 • 
Commercial and industrial revenue— As of May 1, 2009, Reliant Energy re-launched its C&I segment. C&I revenues for the two monthsperiod ended JuneSeptember 30, 2009, totaled $437$1,057 million on volume sales of roughly 5,58013,780 GWh. Variable rate contracts tied to the market price of natural gas accounted for approximately 68%71% of the contracted volumes as of JuneSeptember 30, 2009.

83

 • 
Contract amortization— reduced operating revenues by $75$160 million resulting from net in-market C&I contracts, which will continue to amortize over the term of the contracts acquired in the Reliant Energy acquisition.
 
 • 
Supply management revenues— totaled $52$151 million from the sale of excess supply into various markets in Texas.
Cost of Energy
     Cost of energy for the two monthsperiod ended JuneSeptember 30, 2009, was $614$1,817 million and consisted of the following:
 • 
Supply costs— totaled $550$1,387 million. The current market cost of energy is significantly down in 2009.for the period. Natural gas prices have declined 70%69% since the second quarter of 2008.same period last year. Also, warmer weather for the period, as compared to the 30 year CDD average, caused an increase in purchased supply volumes at a relatively low cost.
 
 • 
Risk management activities— Unrealized gains of $303$521 million on economic hedges relate to supply contracts that were recognized for the two monthsperiod ended JuneSeptember 30, 2009, including $210$449 million of gains which represent a roll-off of loss positions acquired at May 1, 2009, valued at forward prices and $93$72 million of gains that represent mark-to-market changes in forward value of purchased electricity and gas. The $210$449 million gain from roll-off of loss positions is offset by therealized losses at the settled prices and reflected in cost of operations.
 
 • 
Transmission and distribution charges— totaled $267 million.$659 million for the cost to transport the power from the generation sources to the end use customers.
 
 • 
Financial settlements— totaled $114$316 million resulting from financial settlement of energy related derivatives.
 
 • 
Contract amortization— reduced the cost of energy by $13$24 million, resulting from the net out-of-market supply contracts established at the acquisition date. These contracts will be amortized over the life of the contracts.
Other Operating Expenses
     Other operating expenses for the two monthsperiod ended JuneSeptember 30, 2009, was $90were $226 million, or 8% of the region’s total operating revenues. Other operating expenses consisted of the following:
 • 
Operations and maintenance expenses— totaled $25$62 million, primarily consisted of the labor and external costs associated with customer activities, including the call center, billing, remittance processing, and credit and collections, as well as the information technology costs associated with those activities.
 
 • 
Selling, general and administrative expenses— totaled $40$88 million, primarily consisted of the costs of labor and external costs associated with advertising and other marketing activities, as well as human resources, community activities, legal, procurement, regulatory, accounting, internal audit, and management, as well as facilities leases and other office expenses.
 
 • 
Gross receipts tax— totaled $16$39 million or 1.4%1.3% of revenue.Mass and C&I revenues.
 
 • 
Bad debt expense— totaled $9$37 million or 0.8%1.2% of revenue.Mass and C&I revenues which was driven by higher summer bills due to warmer weather and economic factors including unemployment in Dallas and Houston which approximated national averages.

7984

Results of Operations for Wholesale Power Generation Regions
     The following is a detailed discussion of the results of operations of NRG’s major wholesale power generation business segments.
Texas
     For a discussion of the business profile of the Company’s Texas operations, see pages 23-26 of NRG Energy, Inc.’s 2008 Annual Report on Form 10-K.
Selected Income Statement Data
                                                
 Three months ended June 30, Six months ended June 30, Three months ended September 30, Nine months ended September 30,
(In millions except otherwise noted) 2009 2008 Change % 2009 2008 Change % 2009 2008 Change % 2009 2008 Change %
Operating Revenues
  
Energy revenue    $600 $925  (35)% $1,194 $1,471  (19)%   $  672 $  873  (23)% $  1,866 $  2,344  (20)%
Capacity revenue 47 119  (61) 94 237  (60) 50 129  (61) 144 366  (61)
Risk management activities  (54)  (419)  (87) 209  (523)  (140) 14 552  (97) 223 29 N/A 
Contract amortization 17 83  (80) 32 146  (78) 17 69  (75) 49 215  (77)
Other revenues 9 43  (79) 15 69  (78) 7 14  (50) 22 83  (73)
   
Total operating revenues 619 751  (18) 1,544 1,400 10  760 1,637  (54) 2,304 3,037  (24)
Operating Costs and Expenses
  
Cost of energy (including risk management activities) 236 413  (43) 474 671  (29) 296 366  (19) 770 1,037  (26)
Other operating expenses 154 150 3 322 314 3  164 154 6 486 468 4 
Depreciation and amortization 117 113 4 234 226 4  119 108 10 353 334 6 
   
Operating Income
    $112 $75 49 $514 $189 172  $  181 $  1,009  (82) $  695 $  1,198  (42)
MWh sold (in thousands) 12,333 12,675  (3) 22,506 23,706  (5) 13,979 13,111 7 36,485 36,817  (1)
MWh generated (in thousands) 11,919 12,500  (5) 21,992 23,256  (5) 12,534 12,891  (3) 34,527 36,147  (4)
Business Metrics
  
Average on-peak market power prices ($/MWh) 45.20 164.29  (72) 39.43 117.80  (67) 33.68 102.82  (67) 37.51 112.80  (67)
Cooling Degree Days, or CDDs(a)
 982 1,009  (3) 1,108 1,092 1  1,601 1,417 13 2,709 2,509 8 
CDD’s 30 year average 854 854 — 948 949 —  1,485 1,485 — 2,433 2,434 — 
Heating Degree Days, or HDDs(a)
 100 112  (11)% 1,003 1,157  (13) 5 6  (17)% 1,008 1,163  (13)
HDD’s 30 year average 83 83 — 1,205 1,215  (1)%   5 5 — 1,210 1,221  (1)%
(a) National Oceanic and Atmospheric Administration-Climate Prediction Center —- A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.
Quarterly Results
Operating Income
     Operating income increaseddecreased by $37$828 million for the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, primarily due to:
 • 
Risk management activitiesOperating revenues —— an increase of $365decreased by $877 million was primarily due to a $212 million reductionreduced impact from risk management activities, in unrealized derivative losses and $153 million in realized gains on settled financial transactions. These changes reflect a decline in forward and settled power and gas prices relatedaddition to economic hedges in the second quarter 2009 as compared to the same period of 2008.
•Energylower energy revenues— decreased by $325 million due to lower average energy prices and lower sales volume.
 
 • 
Cost of energy— decreased by $177$70 million reflectingresulting from lower natural gas costs and a decrease in coal and gas generation.costs.

8085

Operating Revenues
     Total operating revenues decreased by $132$877 million during the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Risk management activities— lossdecreased by $538 million due to the difference between gains of $54$14 million was recognized for the three months ended Juneending September 30, 2009, compared to a $419gains of $552 million loss induring the same period in 2008. The $54$14 million of lossesgain included $159$102 million of unrealized mark-to-market losses and $105$116 million in gains on settled gains,transactions, or financial income, compared to $371$596 million in unrealized derivative lossesmark-to-market gains and $48$44 million of settledin financial losses induring the same period in 2008. The $159 million loss included a $133 million unrealized loss duePlease refer to the increaseconsolidated Management’s Discussion and Analysis for a more complete description of forward power and gas prices related to economic hedges, a $2 million unrealized loss due to ineffectiveness on gas hedges, and a $24 million unrealized loss attributable to tradingmovements in risk management activities.
 • 
Energy revenues— decreased $325$201 million due to:
 o 
Energy Pricesprices— decreased by $283$177 million as the unusually high prices that occurredcontinue to remain lower in the secondthird quarter of 2008 did not repeat in2009 compared to the same period 2009. Higher MWh sold in the merchant market were offset by significantly lower merchant prices in 2009 versus the same period of 2008. The average realized energy price decreased by 32%21%, driven by a 63%53% decrease in merchant prices offset by a 25%21% increase in contract prices.
 o 
Generation— decreased by 5% contributing to3% resulting in a $42$24 million decrease in sales volume. This decrease was driven by a 9%an 11% decrease in coal plant generation and a 13%an 8% decrease in gas plant generation, offset by a 17% increase in nuclear plant generation as the second quarter of 2008 contained a planned outage which did not occur in the same period 2009, as well as generation from the recently constructed Elbow Creek wind farm, which was not in operation in the second quarter 2008.generation. Coal plant generation was adversely affected by lower energy prices driven by a 68%64% decrease in average natural gas pricesprices. This was offset by a 47% increase in combination with depressed heat ratesgas plant generation due to very warm temperatures in the region. Increasedthird quarter 2009 compared to the same period 2008, as well as generation from the recently constructed Cedar Bayou 4 gas plant and Elbow Creek wind generation shifted the coal unit’s positionfarm which began commercial operations in the bid stack which also negatively affected coal plant generation. These factors led to increased hours in which the coal units were uneconomic to dispatch.June 2009 and December of 2008, respectively.
 • 
Capacity revenue— decreased by $72$79 million due to a lower proportion of baseload contracts which contain a capacity component.
 
 • 
Contract amortization revenue— resulting from the Texas Genco acquisition decreased by $66$52 million due to the reduced volume of contracted energy in 2009 as compared to 2008.
 
 • 
Other revenue— decreased by $34$7 million primarily due to lower ancillary services revenue lowerof $16 million. This decrease was offset by $6 million higher physical sales of natural gas and coal and $1 million higher emissions credit revenue and lower physical coal and natural gas sales.revenue.
Cost of Energy
     Cost of energy decreased by $177$70 million during the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Natural gas costs— decreased by $150$84 million due to a 68%64% decline in average natural gas prices andoffset by a 13% decrease47% increase in gas-fired generation.
 
 • 
Derivative Cost of Energy— decreased $17 million due to the recognition of unrealized gains on coal contracts of $8 million as the Company discontinued NPNS accounting for coal purchases combined with $9 million of unrealized gains associated with oil transactions hedging price risk on rail transportation contracts.
•
Ancillary Services Costsservices costs— decreased by $12$19 million due to a decrease in purchased ancillary services costs incurred to meet obligations.

81

•
Coal and nuclear fuel costs— decreased by $7 million due to lower generation, offset by an $8 million increase in nuclear fuel due to the reversal of amortization of nuclear fuel inventory established under Texas Genco accounting.
     These decreases were offset by:
 • 
Financial Cost of EnergyPurchased energy— increased $6$13 million primarily due to higher risk management activitiesbaseload units either unavailable or uneconomic to hedgeprovide power for coal transportation, as well as certain hedge allocations.contract commitments.
 
 • 
Coal costsCost contract amortization—– increased $10 million driven primarily by $3the reduction in amortization credit for out-of-the money coal contracts assumed in the acquisition of Texas Genco as coal is delivered under that contract.

86

•
Fuel risk management activities —losses of $11 million due to higherwere recorded for the three months ending September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified into mark-to-market accounting. The $11 million loss included $7 million of unrealized mark-to-market losses, largely associated with forward coal positions and $4 million in losses on settled transactions, or financial cost of coalenergy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of $10 million and greater transportation costs of $4 million . These increases were offset by reduced generation of $12 million.movements in risk management activities.
Other Operating Expenses
     Other operating expenses increased by $4$10 million during the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, driven by increased developmentan increase of $9 million in general and administrative expenses due to higher corporate allocations as a result of the change in method in allocating corporate costs as described in 2009, offset byNote 12,Segment Reporting,in combination with a decrease$3 million increase in operations and maintenance expense.expense as a result of maintenance outages at the region’s baseload plants.
Depreciation and Amortization
     Depreciation and amortization expense increased by $11 million for the three months ended September 30, 2009, compared to the same period in 2008. This increase is the result of Cedar Bayou 4 and Elbow Creek reaching commercial operations in June 2009 and December 2008, respectively.
Year to date results
Operating Income
     Operating income increaseddecreased by $325$503 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, primarily due to:
 • 
Risk management activitiesOperating revenues —— an increase of $732 million was primarily due to a $539 million increase in unrealized derivative gains and $193 million in realized gains on settled financial transactions. These changes reflect a decline in forward power and gas prices related to economic hedges in the first half of 2009 as compared to the same period of 2008.
•
Energy revenues— decreased by $277$733 million due to lower averageunfavorable energy prices and lower sales volume.capacity revenues offset by favorable impact of risk management activities.
 • 
Cost of energy —— decreased by $197$267 million reflecting lower natural gas costs and a decrease in coal and gas generation.
Operating Revenues
     Total operating revenues increaseddecreased by $144$733 million during the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Risk management activities— $209 million gain was recognized for the six months ended June 30, 2009, compared to a $523 million loss in the same period in 2008. The $209 million gain included $65 million of unrealized mark-to-market gains and $144 million in settled gains, or financial income, compared to $473 million in unrealized derivative losses and $50 million of settled financial losses in the same period in 2008. The $65 million gain included an $115 million unrealized gain due to decreases in forward and settled power and gas prices related to economic hedges, and a $50 million unrealized loss attributable to trading activities.
•
Energy revenues— decreased $277$478 million due to:
 o 
Energy Pricesprices— decreased by $198$373 million as the average realized merchant price was lower in 2009 due to the combination of lower gas prices and unusually high pricespricing events that occurred in the second quarter 2008 but did not repeat in 2009. Higher MWh sold under merchant market was offset by lower merchant prices. The average realized energy price decreased by 14%17%, driven by a 51%52% decrease in merchant prices offset by a 24%23% increase in contract prices.
 
 o 
Generation— decreased by 5% contributing toresulting in a $79$105 million decrease in sales volume. This decrease was driven by an 8%a 9% decrease in coal plant generation andgeneration. This was offset by a 21% decrease6% increase in gas plant generation, offset byand generation from the recently constructed Cedar Bayou 4 gas plant and Elbow Creek wind farm which was not inbegan commercial operation in the first half of 2008.June 2009 and December 2008, respectively. Coal plant generation was adversely affected by lower energy prices driven by a 61%66% decrease in average natural gas prices in combination with depressed heat ratesincreased wind generation in the region. Increased wind generation shifted the coal unit’s position in the bid stack also negatively affecting coal plant generation. These factors led to increased hours where the coal units were uneconomic to dispatch.

82

 • 
Capacity revenue— decreased by $143$222 million due to a lower proportion of baseload contracts which contain a capacity component.
 
 • 
Risk management activities— increased by $194 million due to the difference between gains of $223 million recorded for the nine months ending September 30, 2009, compared to gains of $29 million during the same period in 2008. The $223 million gain included $36 million of unrealized mark-to-market losses and $259 million in gains on settled transactions, or financial income, compared to $123 million in unrealized mark-to-market gains and $94 million in financial losses during the same period in 2008. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

87

•
Contract amortization revenue— resulting from the Texas Genco acquisition decreased by $114$166 million due to the reduced volume of contracted energy in 2009 as compared to 2008.
 
 • 
Other revenue— decreased by $54$61 million primarily due to lower ancillary services revenue of $41 million provided to the market, as well as lower emissions credit revenue of $13 million and reduced physical sales.sales of natural gas and coal of $7 million.
Cost of Energy
     Cost of energy decreased by $197$267 million during the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Natural gas costs— decreased by $197$281 million due to a 61%66% decline in average natural gas prices andoffset by a 21% decrease6% increase in gas-fired generation.
 
 • 
Ancillary Service Costsservice costs— decreased by $24$41 million due to a decrease in purchased ancillary services costs incurred to meet contract obligations.
 
 • 
Coal costs— decreased by $9$17 million as the first halfthree months of 2008 included a $15 million loss reserve related to a coal contract dispute. Indispute in addition there wasto a $12decrease of $6 million reduction caused bydue to lower generation. These decreases were offset by higher coal costs of $11 million and greater transportation costs of $7$9 million.
•
Purchased energy— decreased by $14 million due to a lower average price to procure energy from the market offset by a greater number of MWhs purchased.
•
Nuclear fuel expense— resulting from the Texas Genco purchase accounting, decreased $10 million as amortization of nuclear fuel inventory ended in March 2008.
     These decreases were offset by:
 • 
Derivative CostFuel risk management activities —losses of Energy— increased $40$65 million due towere recorded for the recognition of unrealized losses onnine months ending September 30, 2009. In the first quarter 2009, all NPNS coal contracts of $32were discontinued and reclassified into mark-to-market accounting. The $65 million as the Company discontinued NPNS accounting for coal purchases combined with $8loss included $48 million of unrealized mark-to-market losses, largely associated with oilforward coal positions and $17 million in losses on settled transactions, hedging priceor financial cost of energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk on rail transportation contracts.management activities.
Other Operating Expenses
     Other operating expenses increased by $8$18 million during the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, driven by an increase of $14 million in general and administrative expense due to higher corporate allocations as a result of higher external consulting expendituresthe change in method in allocating corporate costs as described in Note 12,Segment Reporting,to this Form 10-Q. In addition there was an increase of $4 million for development expense as prior year results included a one time credit due to the reimbursement by the Company’s nuclear development partner of previously expensed development costs on STP units 3 and higher corporate allocations, offset4 of $8 million.
Depreciation and Amortization
     Depreciation and amortization expense increased by lower$19 million for the nine months ended September 30, 2009, compared to the same period in 2008. This increase was the result of Cedar Bayou 4 and Elbow Creek reaching commercial operations in June 2009 and maintenance expenditures.December 2008, respectively.

8388

Northeast Region
     For a discussion of the business profile of the Northeast region, see pages 27-29 of NRG Energy, Inc.’s 2008 Annual Report on Form 10-K.
Selected Income Statement Data
                                                
 Three months ended June 30, Six months ended June 30,  Three months ended September 30, Nine months ended September 30,
(In millions except otherwise noted)
 2009 2008     Change % 2009 2008   Change % 2009 2008 Change % 2009 2008 Change %
Operating Revenues
  
Energy revenue    $79 $285  (72)%   $260 $549  (53)%   $  123 $  324  (62)% $  383 $  873  (56)%
Capacity revenue 100 101  (1) 196 211  (7) 120 117 3 316 328  (4)
Risk management activities 51  (146)  (135) 233  (184)  (227) 19 168  (89) 252  (16) N/A 
Other revenues 7 25  (72) 12 49  (76) 8 13  (38) 20 62  (68)
   
Total operating revenues 237 265  (11) 701 625 12  270 622  (57) 971 1,247  (22)
Operating Costs and Expenses
  
Cost of energy (including risk management activities) 58 191  (70) 175 359  (51) 90 198  (55) 265 557  (52)
Other operating expenses 94 91 3 188 184 2  88 89  (1) 276 273 1 
Depreciation and amortization 30 25 20 59 51 16  29 26 12 88 77 14 
   
Operating Income/(Loss)
    $55 $(42)  (231)   $279 $31 N/A 
Operating Income
 $  63 $  309  (80) $  342 $  340 1 
MWh sold (in thousands) 1,634 3,245  (50) 4,272 6,836  (38) 2,508 3,588  (30) 6,779 10,424  (35)
MWh generated (in thousands) 1,634 3,245  (50) 4,272 6,836  (38) 2,508 3,588  (30) 6,779 10,424  (35)
Business Metrics
  
Average on-peak market power prices ($/MWh)(b)
 39.68 107.36  (63) 48.99 96.76  (49) 40.42 108.44  (63) 46.13 100.66  (54)
Cooling Degree Days, or CDDs(a)
 77 165  (53) 77 165  (53) 419 446  (6) 496 611  (19)
CDD’s 30 year average 105 105 — 105 105 —  429 430 — 534 534 — 
Heating Degree Days, or HDDs(a)
 789 771  2% 3,997 3,731 7  129 135  (4) 4,126 3,866 7 
HDD’s 30 year average 841 841 — 3,935 3,968  (1)%   158 159  (1)% 4,093 4,126  (1)%
(a) 
National Oceanic and Atmospheric Administration-Climate Prediction Center —- A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.
(b) 
MWh sold are shown net of MWh purchased to satisfy certain load contracts in the region.
Quarterly Results
Operating Income
     Operating income increaseddecreased by $97$246 million for the three months ended JuneSeptember 30, 2009, compared to the same period in 2008 due to:
 • 
Cost of energyOperating revenues —decreased by $133$352 million due to lower generationunfavorable energy revenues and fuel costs.an unfavorable impact from risk management activities.
 
 • 
Operating revenuesCost of energy —decreased by $28$108 million due to unfavorable energy revenues offset by favorable impact of risk management activities.lower generation and fuel costs.

8489

Operating Revenues
     Operating revenues decreased by $28$352 million for the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Energy revenues —decreased by $206$201 million due to:
 o 
Energy prices— decreased by $83$120 million reflecting an average 56%52% decline in merchant energy prices. This decrease was partially offset by higher net contract revenues of $24$18 million driven by lower net costs incurred in meeting obligations under load serving contracts in the PJM market.
 
 o 
Generation— decreased by $147$99 million due to a 50%30% decrease in generation in 2009 compared to 2008, with a 51%34% decrease in coal generation and a 41%9% decrease in oil and gas generation. Coal generation in western New York declined 44%33%, or 625,000568,247 MWhs, due to weak power prices that made the plants uneconomic to dispatch. Coal generation at the Indian River plant declined 65%35%, or 536,000305,203 MWhs, due to a combination of weakened demand for power, low gas prices and higher cost of production from compliance with RGGI and the NOx rules contained in CAIR resulting in increased hours where the units were uneconomic to dispatch. The Somerset plant experienced similar weakened demand and low gas prices, with generation down 95%82%, or 174,000111,819 MWh. The decline in oil and gas generation is attributable to fewer reliability run hours at the Connecticut plants and a planned major maintenance outage at the Arthur Kill plant during February through May 2009.
•
Other revenues— decreased by $18 million due to $10 million lower allocations of net physical gas sales and $8 million due to decreased activity in the trading of emission allowances.
     These decreases were offset by:
 • 
Risk management activities— gains of $51$19 million were recorded for the three months ending JuneSeptember 30, 2009, compared to lossesgains of $146$168 million during the same period in 2008. The $51$19 million gain included $46$99 million of unrealized mark-to-market losses and $97$118 million in gains on settled transactions, or financial income, compared to $111$211 million in unrealized mark-to-market lossesgains and $35$43 million in financial losses during the same period in 2008. The $46 million unrealized loss isPlease refer to the net effectconsolidated Management’s Discussion and Analysis for a more complete description of a $10 million loss from economic hedge positions, the reversal of $33 million of mark-to-market gains on economic hedges, the reversal of $9 million of mark-to-market gains on trading activities and $6 millionmovements in unrealized mark-to-market gains on trading activity. Gains and losses are driven by changes in power and gas prices.risk management activities.
Cost of Energy
Cost of energy decreased by $133$108 million for the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 o 
Natural gas and oil costs— decreased by $78$53 million, or 74%57%, due to 41%9% lower generation and 68%67% lower average natural gas prices.
 
 o 
Coal costs— decreased by $48$39 million, or 57%38%, due to lower coal generation of 51% as discussed in energy revenues above.34% accounting for $33 million and lower prices accounting for $6 million.
 
 o 
Fuel risk management activities— decreased by $10gains of $22 million due to a $12 million mark-to-market gain on fuel hedges which were discontinued from NPNS to mark-to-market inrecorded for the three months ending September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified into mark-to-market accounting. The $22 million gain included $23 million of 2009 offset by a $2mark-to-market gains, largely associated with forward coal positions and $1 million lossin losses on settled fuel hedges.transactions, or financial cost of energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.
     These decreases were offset by:
 o• 
Carbon emissionsemission expense— increased by $3$6 million due to the January 1, 2009, implementation of RGGI and the recognition of carbon compliance cost under this program.

8590

Year-to-Date Results
Operating Income
     Operating income increased by $248$2 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008 due to:
 • 
Cost of energy —decreased by $184$292 million due to lower generation and fuel costs.
     This decrease was offset by:
•
Operating revenues —decreased by $276 million due to unfavorable energy revenues, other revenues and capacity revenues partially offset by a favorable impact from risk management activities.
 
 • 
Operating revenues Depreciation and amortization—increased by $76$11 million primarily due to favorable impact of risk management activities, offset by lower energy revenues.depreciation from the 2009 baghouse projects at our Western New York coal plants and additional depreciation recognized in 2009 compared to 2008 from the June 2008 Cos Cob repowering project.
Operating Revenues
     Operating revenues increaseddecreased by $76$276 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Risk management activities— gains of $233 million were recorded for the six months ending June 30, 2009, compared to losses of $184 million during the same period in 2008. The $233 million gain included $77 million of unrealized mark-to-market gains and $156 million in gains on settled transactions, or financial income, compared to $160 million in unrealized mark-to-market losses and $24 million in financial losses during the same period in 2008. The $77 million unrealized gain is the net effect of a $159 million gain from economic hedge positions and $4 million in unrealized mark-to-market gains on trading activity offset by the reversal of $63 million of mark-to-market gains on economic hedges and the reversal of $23 million of mark-to-market gains on trading activities. Gains and losses are driven by changes in power and gas prices.
     This increase was offset by:
•
Energy revenues —decreased by $289$490 million due to:
 o 
Energy prices— decreased by $113$231 million reflecting an average 32%40% decline in merchant energy prices. This decrease was partially offset by higher net contract revenues of $35$53 million driven by lower net costs incurred in meeting obligations under load serving contracts in the PJM market.
 
 o 
Generation— decreased by $212$312 million due to a 38%35% decrease in generation in 2009 compared to 2008, driven by a 37%36% decrease in coal generation and a 40%28% decrease in oil and gas generation. Coal generation in western New York declined 30%31% or 921,0001,480,454 MWhs due to weak power prices that made the plants uneconomic to dispatch. Coal generation at the Indian River plant declined 48%44% or 953,0001,257,936 MWhs due to a combination of weakened demand for power, low gas prices and higher cost of production from the introduction of RGGI and NOx rules contained in CAIR resulting in increased hours where the units were uneconomic to dispatch. The Somerset plant experienced similar weakened demand and low gas prices, with generation down 78%79% or 297,000408,435 MWh. The decline in oil and gas generation is attributable to fewer reliability run hours at the Connecticut plantsNorwalk plant and a planned majorhigher maintenance outagework at the Arthur Kill plant during February through May ofin 2009.
Capacity revenues — decreased by $15 million due to:
o
NYISO— capacity revenues decreased by $15 million due to unfavorable prices. The lower capacity market prices are a result of NYISO’s reductions in Installed Reserve Margins and ICAP in-city mitigation rules effective March 2008.
o
PJM— capacity revenues decreased by $4 million due to lower capacity prices.
o
NEPOOL— capacity revenues increased by $4 million due to higher volume of Locational Forward Reserve Market, or LFRM, revenues on the Cos Cob repowered units which entered service in June 2008.
 • 
Other revenues— decreased by $37$42 million due to $21$22 million from decreased activity in the trading of emission allowances and $17 million lower allocations of net physical gas sales and $14sales.
•Capacity revenues — decreased by $12 million due to decreased activitylower capacity cash flow revenue in New York in 2009.
     These decreases were offset by:
•
Risk management activities— gains of $252 million were recorded for the tradingnine months ending September 30, 2009, compared to losses of emission allowances.$16 million during the same period in 2008. The $252 million gain included $22 million of unrealized mark-to-market losses and $274 million in gains on settled transactions, or financial income, compared to $51 million in unrealized mark-to-market gains and $67 million in financial losses during the same period in 2008. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

8691

Cost of Energy
Cost of energy decreased by $184$292 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 o 
Natural gas and oil costs— decreased by $107$160 million, or 63%61%, due to 40%28% lower generation and 56%60% lower average natural gas prices.
 
 o 
Coal costs— decreased by $69$108 million, or 38%, due to lower coal generation of 37% as discussed in energy revenues above.36% accounting for $106 million and lower prices accounting for $2 million.
 
 o 
Fuel risk management activities— decreased by $15gains of $37 million due to a $20 million mark-to-market gains on fuel hedges which were discontinued from NPNS to mark-to-market inrecorded for the nine months ended September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified to mark-to-market accounting. The $37 million gain included $43 million of 2009 offset by a $5unrealized mark-to-market gains, largely associated with forward coal positions and $6 million lossin losses on settled fuel hedges.transactions, or financial cost of energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.
     These decreases were offset by:
 o 
Carbon emissionsemission expense— increased by $8$15 million due to the January 1, 2009, implementation of RGGI and the recognition of carbon compliance cost under this program.

8792

     South Central Region
     For a discussion of the business profile of the South Central region, see pages 30-3129-31 of NRG Energy, Inc.’s 2008 Annual Report on Form 10-K.
Selected Income Statement Data
                                      
 Three months ended June 30, Six months ended June 30, Three months ended September 30, Nine months ended September 30,
(In millions except otherwise noted) 2009 2008 Change %  2009 2008 Change %  2009 2008 Change% 2009 2008 Change%
Operating Revenues
  
Energy revenue   $81 $130  (38)%   $177 $230  (23)%  $  90 $  145  (38)% $  267 $  375  (29)%
Capacity revenue 65 58 12 133 115 16  71 59 20 204 174 17 
Risk management activities  (12)  (23)  (48)  (19)  (10) 90   (27) 24 N/A  (46) 14 N/A 
Contract amortization 5 5 — 11 11 —  8 7 14 19 18 6 
Other revenues — 2 100  (1) 5  (120) 1  (1) N/A — 4 N/A 
   
Total operating revenues 139 172  (19) 301 351  (14) 143 234  (39) 444 585  (24)
Operating Costs and Expenses
  
Cost of energy (including risk management activities) 92 116  (21) 202 204  (1) 122 156  (22) 324 360  (10)
Other operating expenses 27 33  (18) 49 55  (11) 27 25 8 76 80  (5)
Depreciation and amortization 17 17 — 34 34 —  16 16 — 50 50 — 
   
Operating Income
   $3 $6  (50)   $16 $58  (72)
Operating (Loss)/Income
 $(22) $  37  (159) $(6) $  95  (106)
MWh sold (in thousands) 2,792 2,977  (6) 5,961 6,065  (2) 3,243 3,383  (4) 9,204 9,448  (3)
MWh generated (in thousands) 2,386 2,616  (9) 5,093 5,641  (10) 2,727 2,828  (4) 7,819 8,469  (8)
Business Metrics
  
Average on-peak market power prices ($/MWh) 32.21 84.82  (62) 34.75 76.28  (54) 29.50 84.88  (65) 33.00 79.14  (58)
Cooling Degree Days, or CDDs(a)
 582 546 7 588 550 7  952 1,027  (7) 1,540 1,577  (2)
CDD’s 30 year average 458 458 — 489 489 —  997 997 — 1,486 1,487 — 
Heating Degree Days, or HDDs(a)
 289 319  (9)% 2,094 2,223  (6) 14 16  (13)% 2,108 2,239  (6)
HDD’ 30 year average 299 299 — 2,194 2,213  (1)% 33 33 — 2,227 2,246  (1)%
(a) 
National Oceanic and Atmospheric Administration-Climate Prediction Center —- A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.
Quarterly Results
     Operating income decreased by $3$59 million for the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, primarily due to:
 • 
Operating revenues— decreased by $33$91 million due to a decreases in energy revenue offset by increases inand risk management activities andoffset by increased capacity revenue.
 
 • 
Cost of energy — decreased by $24$34 million due to lower purchased energy, costs reflecting lower fuel and energy prices and lower transmission costs, offset by higher fuel risk management activities.
 
 • 
Other Operating Expensesoperating expenses— decreasedincreased by $6$2 million because ofdue to higher maintenance expense offset by lower operations and maintenance and general and administrative costs.

8893

Operating Revenues
     Operating revenues decreased by $33$91 million for the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Energy revenues— decreased by $49$55 million due to a $27$24 million decline in contract revenue coupled with a decrease of $22$31 million in merchant energy revenues. Total MWh sales to the region’s contract customers were down 12%7% while the average realized price on contract energy sales was $22.98$22.83 per MWh in 2009 compared to $30.23$29.19 per MWh in 2008. The decline in contract energy price was driven by a $9$7 million decrease in fuel cost pass through from the cooperatives. Also contributing to the decline in contract revenue was $18$17 million due to the expiration of a contract with a regional utility. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower average prices resulting in a $22$31 million decline in revenue. Megawatt hours sold to the merchant market increased by 43%18% as increased use of the region’s tolled facility provided additional energy to the merchant market while prices fell by 61%. to $54.52/MWh.
 
 • 
Risk Management Activitiesmanagement activities— losses of $12$27 million were recognized duringrecorded for the second quarterthree months ending September 30, 2009, compared to lossesgains of $23$24 million recognized during the same period in 2008. The $12$27 million loss included $10$25 million inof unrealized mark-to-market losses and $2 million in realized losses on settled transactions, or financial income, compared to $18$28 million in unrealized lossesmark-to-market gains and $4 million in realizedfinancial losses forduring the same period in 2008. The $10 million unrealized loss wasPlease refer to the net effectconsolidated Management’s Discussion and Analysis for a more complete description of a $2 million unrealized mark-to-market gain from trading activity and the reversal of $12 million of mark-to-market gains on trading activity.movements in risk management activities.
 
 • 
Capacity revenues— capacity revenue increased by $7$12 million due to a $9an $11 million increase from a new capacity agreement and a $2$1 million increase in capacity revenue from the region’s Rockford plants which dispatch into the PJM market, offset by a decrease in contract capacity of $4 million.market.
Cost of Energy
     Cost of energy decreased by $24$34 million for the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Purchased energy— Total purchased energy and capacity decreased by $30$35 million. Purchased energy costs decreased by $29$35 million even thoughreflecting a 2% decrease in MWhs purchased increased by 8%,and a 65% decrease in price reflecting lower fuel costs associated with energy from the region’s tolled facility and lower costs of market purchases.
 
 • 
TransmissionNatural gas expense— decreased by $3$14 million duereflecting an 88% decrease in gas generation and a 61% decrease in gas prices. The region’s gas facilities ran extensively to outages onsupport transmission linessystem stability following hurricane Gustav in neighboring systems limiting their useSeptember 2008.
•
Coal expense— decreased $2 million as cost per ton was $31.94 compared to move power and incur cost.$32.46 for the same period last year reflecting lower fuel transportation surcharges partially offset by increased transportation contract rates.
     These decreases were offset by:
 • 
Fuel risk management activities— increased by $8 million.losses of $17 million were recorded for the three months ending September 30, 2009. In the first quarter 2009, all NPNS coal contracts were discontinued and reclassified into mark-to-market accounting, which resulted in unrealized losses of $10accounting. The $17 million on coal commodity hedging activities. Hedging activities related to fuel transportation resulted in $4loss included $16 million of unrealized gainsmark-to-market losses, largely associated with forward coal positions and $2$1 million in losses on settled transactions, or financial cost of realized losses.energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.

94

Other Operating Expenses
     Other operating expense decreasedincreased by $6$2 million for the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Operations and Maintenancemaintenance expense— decreasedincreased by $4 million because the spring outageof work done on river docking facility used for barge unloading and expenditures in 2009 was performed on a jointly owned unit, while 2008 outages were on NRG-owned units.preparation for fall outages.
 
 • 
General and Administrativeadministrative expense— declined by $2 million due to lower corporate allocations as such costs are spread over a wider base following the Reliant Energy acquisition.

89

Year-to-Date Results
     Operating income decreased by $42$101 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, primarily due to:
 • 
Operating revenues— decreased by $50$141 million due to decreases in energy revenue, risk management activities, and other revenue. These decreases were offset by an increase in capacity revenuerevenue.
 
 • 
Cost of energy — decreased by $2$36 million due to lower purchased energy, costs reflecting lower fuel and energy prices, lower transmission expense and lower coal costcosts, offset by higher expenses associated with fuel risk management activities.
 
 • 
Other Operating Expensesoperating expenses— decreased by $6$4 million because of lower operations and maintenance and general and administrative costs.
Operating Revenues
     Operating revenues decreased by $50$141 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Energy revenues— decreased by $53$108 million due to a $42$66 million decline in contract revenue coupled with an $11a $42 million decrease in merchant energy revenues. Contract customer sales volumes were down 11%10% while the average realized price on contract energy sales was $23.17$23.04 per MWh in 2009 compared to $28.72$28.89 per MWh in 2008. The decline in contract energy price was driven by a $7$12 million decrease in fuel cost pass through to the cooperatives. Also contributing to the decline in contract revenue was $31$48 million due to the expiration of a contract with a regional utility. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower average prices resulting in an $11a $42 million decline in revenue. Megawatt hours sold to the merchant market increased by 51%41%, while prices fell by 42%.50% to $52.10/MWh. Increased use of the region’s tolled facility provided additional energy to the merchant market.
 
 • 
Risk Management Activitiesmanagement activities— losses of $19$46 million were recognized duringrecorded for the second half ofnine months ending September 30, 2009, compared to lossesgains of $10$14 million recognized during the same period in 2008. The $19$46 million loss included $30$55 million of unrealized mark-to-market losses offset by $9 million in gains on settled transactions, or financial income, compared to $18 million in unrealized lossesmark-to-market gains offset by realized gains of $11 million compared to $10$4 million in unrealizedfinancial losses forduring the same period in 2008. The $30 million unrealized loss wasPlease refer to the net effectconsolidated Management’s Discussion and Analysis for a more complete description of a $8 million unrealized mark-to-market gain from trading activity and the reversal of $38 million of mark-to-market losses on trading activity.movements in risk management activities
 
 • 
Other Revenuerevenue— declined by $6$4 million due to $3$1 million in lower physical coal and natural gas sales and $3 million reduction in reduced intercompany emission allowance sales.
     These decreases were offset by:
 • 
Capacity revenues— increased by $18$30 million due to a $17$30 million increase from a new capacity agreementagreements with a regional utilityutilities and a $5 million increase in capacity revenue from the region’s Rockford plants which dispatch into the PJM market, offset by lower contract capacity revenue of $4$5 million.

95

Cost of Energy
     Cost of energy decreased by $2$36 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Purchased energy— decreased by $16$52 million while purchased capacity increased by $3 million. The lower purchased energy reflects lower fuel costs associated with the region’s tolled facility and lower market energy prices. The energy declines were offset by higher capacity payments of $3 million on tolled facilities.
 
 • 
Natural gas expense– decreased by $13 million reflecting a 32% decrease in gas generation and a 58% decrease in gas prices. The region’s gas facilities ran extensively to support transmission system stability following hurricane Gustav in September 2008.
•
Transmission expense— decreased by $4$5 million due to certain transmission line outages onbetween electrical power regions which limited merchant energy volumes that would attract transmission lines in neighboring systems limiting their use to move power and incur costs.costs as well as lower network interchange transmission costs associated with reduced contract customer energy volumes.
 
 • 
Coal costsexpense— decreased by $2$4 million due to a 10% reduction inas coal generation and a decrease in fuel transportation surchargeswas down 7%, offset by a contractual5% increase in rail contract base rates and higher coal commodity costs.cost per ton.

90

     These decreases were offset by:
 • 
Fuel risk management activities— increased by $16losses of $33 million inwere recorded for the nine months ending September 30, 2009. In the first quarter of 2009, all normal purchase and saleNPNS coal contracts were discontinued and reclassified into mark-to-market accounting, which resulted in unrealized losses of $7accounting. The $33 million on coal commodity hedging activities. Hedging activities related to fuel transportation resulted in $3loss included $26 million of unrealized mark-to-market losses largely associated with forward coal positions and $6$7 million in losses on settled transactions, or financial cost of realized losses.energy. Please refer to the consolidated Management’s Discussion and Analysis for a more complete description of movements in risk management activities.
Other Operating Expenses
     Other operating expense decreased by $6$4 million for the threenine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Operations and Maintenance expense— decreased by $4 million because the spring outage in 2009 was performed on a jointly owned unit, while 2008 outages were on NRG-owned units.
•
General and Administrativeadministrative expense— declined by $2$4 million due to lower corporate allocations as such costs are spread over a wider base following the Reliant Energy acquisition.

9196

     West Region
     For a discussion of the business profile of the West region, see pages 31-33 of NRG Energy, Inc.’s 2008 Annual Report on Form 10-K.
Selected Income Statement Data
                                     
 Three months ended June 30, Six months ended June 30, Three months ended September 30, Nine months ended September 30,
(In millions except otherwise noted) 2009 2008 Change %  2009 2008 Change %  2009 2008 Change% 2009 2008 Change%
Operating Revenues
  
Energy revenue $5 $13  (62)%   $7 $13  (46)% $  15 $  12  25% $  22 $  25  (12)%
Capacity revenue 31 31 — 60 69  (13) 33 28 18 93 97  (4)
Risk management activities 6 — N/A 3 — N/A   (9) — N/A  (6) — N/A 
Other revenues — 5  (100) — 5  (100) 1 — N/A 1 5  (80)
   
Total operating revenues 42 49  (14) 70 87  (20) 40 40 — 110 127  (13)
Operating Costs and Expenses
  
Cost of energy (including risk management activities) 3 12  (75) 7 14  (50) 10 11  (9) 17 25  (32)
Other operating expenses 21 20 5 46 38 21  15 14 7 61 52 17 
Depreciation and amortization 2 3  (33) 4 4 —  2 2 — 6 6 — 
   
Operating Income
 $16 $14 14   $13 $31  (58) $  13 $  13 — $  26 $  44  (41)
MWh sold (in thousands) 182 327  (44) 352 468  (25) 569 534 7 921 1,002 (8)
MWh generated (in thousands) 182 327  (44) 352 468  (25) 569 534 7 921 1,002 (8)
Business Metrics
  
Average on-peak market power prices ($/MWh) 33.14 97.54  (66) 36.80 88.92  (59) 38.78 96.72  (60) 37.46 91.52  (59)
Cooling Degree Days, or CDDs(a)
 144 205  (30) 144 205  (30) 741 687 8 885 893  (1)
CDD’s 30 year average 150 150 — 157 157 —  506 506 — 663 663 — 
Heating Degree Days, or HDDs(a)
 470 576  (18)% 1,880 2,096  (10) 43 61  (30)% 1,923 2,157  (11)
HDD’s 30 year average 556 556 — 1,975 1,990  (1)% 108 108 — 2,083 2,098  (1)%
(a) 
National Oceanic and Atmospheric Administration-Climate Prediction Center —- A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.
Quarterly Results
Operating Income
     Operating income increased by $2was unchanged at $13 million for the three months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:2008.
•
Operating revenues— decreased by $7 million due to decreases in capacity revenue, energy revenue, and other revenues. These decreases were offset by a gain on risk management activities. Lower demand and lower merchant power prices contributed to the decrease.
•
Cost of energy — decreased by $9 million due to lower generation and lower natural gas prices.
Operating Revenues
     Operating revenues decreased by $7of $40 million for the three months ended JuneSeptember 30, 2009, were unchanged compared to the same period in 2008, due to:
 • 
Energy revenues —decreasedincreased by $8$3 million primarily due to a 33% decline23% increase in generation in 2009 compared to 2008 offset by a 7% decrease in merchant energy prices and a 31% decrease in generationprices.
•
Capacity revenues —increased by $5 million primarily due to additional resource adequacy contract sales at El Segundo in 2009 compared to 2008.
 
 • 
Other revenue revenues—decreased increased by $5$1 million due to a reduced allocation of emission allowances sales.an increase in ancillary services revenue.
 
 • 
Risk Management Activities management activities— losses of $9 million were recorded during the quarter including $6 million of unrealized mark-to-market gains of $6losses and $3 million in realized losses on asset backed hedges were recognized during the second quarter of 2009.settled transactions. There was no asset backed hedgingrisk management activity in 2008. For further discussion of the Company’s risk management activities, see Consolidated Results of Operations.

9297

Cost of Energy
     Cost of energy decreased by $9 million for the three months ended June 30, 2009, compared to the same period in 2008, due to a 67% decrease in average natural gas prices per MMBtu and an 11% decrease in natural gas consumption.
Year-to-Date Results
     Operating income decreased by $18 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:to decreases in capacity revenue, energy revenue, risk management activity revenue and other revenues.
•
Operating revenues— decreased by $17 million due to decreases in capacity revenue, energy revenue, and other revenues. These decreases were offset by a gain on risk management activities. Lower demand and lower merchant power prices contributed to the decrease.
•
Cost of energyand other operating expenses— increased by $1 million due to lower generation and lower natural gas prices offset by higher major maintenance expense.
Operating Revenues
     Operating revenues decreased by $17 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Capacity revenues —decreased by $9$4 million primarily due to expiration of a two year tolling agreement at the El Segundo facility in April 2008, which was replaced by resource adequacy and capacity contracts at lower prices.
 
 • 
Energy revenues —decreased by $6$3 million primarily due to a 27% decline19% decrease in merchant energy prices andin 2009 compared to 2008; offset by a 15% decrease6% increase in merchant generation in 2009 compared to 2008.
 
 • 
Other revenue— decreased by $5$4 million primarily due to a reduced allocation oflower emission allowances sales.allowance sales partially offset by an increase in ancillary services revenue.
 
 • 
Risk Management Activitiesmanagement activities— gainrealized losses of $3$6 million wason settled transactions were recognized during the first half of 2009 compared toperiod. There was no gain during the same periodrisk management activity in 2008. The $3 million gain included $6 million in unrealized mark-to-market gains offset by realized lossesFor further discussion of $3 million for natural gas hedges.the Company’s risk management activities, see Consolidated Results of Operations.
Cost of Energy and Other Operating Expenses
     Cost of energy and other operating expenses increased by $1 million for the sixnine months ended JuneSeptember 30, 2009, compared to the same period in 2008, due to:
 • 
Cost of energy —decreased by $7$8 million due to a 66%43% decline in average natural gas prices per MMBtu and a 17% decrease in natural gas consumption.MMBtu. This decrease was partially offset by a $37% 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.expense.
 
 • 
Other operating expenses— increased by $8$9 million due to higher major maintenance expense associated with ana major overhaul at El Segundo major overhaul and majorhigher maintenance at Long Beach.

9398

Liquidity and Capital Resources
Liquidity Position
     As of JuneSeptember 30, 2009, and December 31, 2008, NRG’s liquidity, excluding collateral received, was approximately $4.0$3.9 billion and $3.4 billion, respectively, and comprised of the following:
               
 June 30, December 31,    September 30, December 31,
(In millions) 2009 2008    2009 2008
Cash and cash equivalents $2,282 $     1,494  $  2,250 $  1,494 
Funds deposited by counterparties 468 754  293 754 
Restricted cash 19 16  26 16 
Total cash 2,769 2,264  2,569 2,264 
Synthetic Letter of Credit Facility availability 784 860  756 860 
Revolver Credit Facility availability 941 1,000  904 1,000 
Total liquidity 4,494 4,124  4,229 4,124 
Less: Funds deposited as collateral by hedge counterparties  (468)  (760)  (293)  (760)
Total liquidity, excluding collateral received $4,026 $      3,364  $  3,936 $  3,364 
     For the sixnine months ended JuneSeptember 30, 2009, total liquidity, excluding collateral received, increased by $662$572 million due to a higher cash balance of $788$756 million, and reduced funds deposited as collateral by hedged counterparties of $292 million. These increases were partially offset by a lower funds deposited of $286 million, as well as decreased availability of the synthetic letterSynthetic Letter of creditCredit Facility and the revolving credit facilityRevolving Credit Facility of $76$104 million and $59$96 million, respectively. Changes in cash balances are further discussed below under the headingCash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at JuneSeptember 30, 2009, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.
     The line item “Funds deposited by counterparties” consists of cash collateral received from hedge counterparties in support of energy risk management activities, and it isrepresents the Company’s intention as of June 30, 2009, to limit the use of these funds. The decrease in these amounts from December 31, 2008 was due to cash collateral moved fromthat are held by NRG to Merrill Lynch in connection with novations under the CSRA (see Note 3 —Business Acquisition), offset by an increase of in-the-money positions as a result of decreasing forward prices.collateral posting obligations from our counterparties due to positions in our hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company’s intention, are not available for the payment of NRG’s general corporate obligations. Depending on market fluctuation and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. TheSince collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company’s balance sheet, reflects awith an offsetting liability for this cash collateral received within current liabilities. The decrease in these amounts from December 31, 2008 was due to cash collateral moved from NRG to Merrill Lynch in connection with novations under the CSRA (see Note 4,Business Acquisition,to this Form 10-Q), offset by an increase of in-the-money positions as a result of decreasing forward prices.
     Management believes that the Company’s liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG’s preferred shareholders and other liquidity commitments. Management continues to regularly monitor the Company’s ability to finance the needs of its operating, financing and investing activity in a manner consistent with its intention to maintain a net debt to capital ratio in the range of 45-60%.
SOURCES OF FUNDS
     The principal sources of liquidity for NRG’s future operating and capital expenditures are expected to be derived from new and existing financing arrangements, asset sales, existing cash on hand and cash flows from operations.
Financing Arrangements
Senior Credit Facility
     As of JuneSeptember 30, 2009, NRG had a Senior Credit Facility which is comprised of a senior first priority secured term loan, or the Term Loan Facility, a $1.0 billion senior first priority secured revolving credit facility, or the Revolving Credit Facility, and a $1.3 billion senior first priority secured synthetic letter of credit facility, or the Synthetic Letter of Credit Facility. The Senior Credit Facility was last amended on June 8, 2007. On July 23, 2009, Moody’s upgraded the Senior Credit Facility to Baa3 due to the underlying value that the capital structure provides to secured creditors. As of JuneSeptember 30, 2009, NRG had issued $516$544 million of letters of credit under the Synthetic Letter of Credit Facility, leaving $784$756 million available for future issuances. Under the Revolving Credit Facility, as of JuneSeptember 30, 2009, NRG had issued a letter of credit of $96 million of which $59 million which supports the tax exempt bonds issued by Dunkirk Power LLC as described in Note 7,8,Long—TermLong-Term Debt,.to this Form 10-Q.

9499

2019 Senior Notes
     On June 5, 2009, NRG completed the issuance of $700 million aggregate principal amount of 8.5% Senior Notes due 2019, or 2019 Senior Notes as described in Note 7,8,Long—TermLong-Term Debt,.to this Form 10-Q. The Company used a portion of the net proceeds of $678 million are intended to be used to facilitate the early termination of NRG’s obligations pursuant to the CSRA anticipatedAmendment, which became effective October 5, 2009. Net proceeds in the late third or early fourth quarter 2009. Prior to the termination, or in the event NRG does not reach agreement on acceptable terms with either Merrill Lynch or its counterparties, the net proceeds will beexcess of this amount are available for general corporate purposes. See further discussion of the CSRA Amendment in Note 20,Subsequent Event,to this Form 10-Q.
Merrill Lynch Credit Sleeve Facility
      As of September 30, 2009, Merrill Lynch, through the CSRA with NRG, has provided the Company as of June 30, 2009, with $630$163 million in financialcredit support (includes cash collateral posted by counterparties and Reliant Energy as an offset to exposure) that significantly reducesreduced the liquidity requirements and substantially eliminateseliminated collateral postings for Reliant Energy. See discussion in Note 3,4,Business Acquisition,to this Form 10-Q, regarding the CSRA as a result of the acquisition of Reliant Energy on May 1, 2009. Effective October 5, 2009, the Company executed the CSRA Amendment. In connection with this transaction, the Company posted $366 million of cash collateral to Merrill Lynch and other counterparties, returned $53 million of counterparty collateral, issued $206 million of letters of credit, and received $45 million of counterparty collateral. In addition, Merrill Lynch returned $250 million of previously posted cash collateral, and released liens on $322 million of unrestricted cash held by Reliant Energy. See further discussion of the CSRA Amendment in Note 20,Subsequent Event,to this Form 10-Q.
TANE Facility
     On February 24, 2009, NINA executed an EPC agreement with 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 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 JuneSeptember 30, 2009, no amounts had been borrowed under the TANE Facility. NINA will be required to repay all outstanding amounts associated with its existing $20 million revolving credit facility before borrowing under the TANE Facility.
Dunkirk Power LLC Tax-Exempt Bonds
     On April 15, 2009, NRG executed a $59 million tax-exempt bond financing through its wholly ownedwholly-owned subsidiary, Dunkirk Power LLC. The bonds were issued by the County of Chautauqua Industrial Development Agency and will be applied towardsused 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 JuneSeptember 30, 2009, were $34$38 million with the remaining balance being released over time as construction costs are paid.
GenConn Energy LLC related financings
     OnIn April 27, 2009, a wholly ownedwholly-owned subsidiary of NRG closed onexecuted 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 JuneSeptember 30, 2009, were $70$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.

95100

First and Second Lien Structure
     NRG has granted first and second liens to certain counterparties on substantially all of the Company’s assets. NRG uses the first and second lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first and second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first and second lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty or NRG and has no stated maturity date.
     The Company’s lien counterparties may have a claim on its assets to the extent market prices exceed the hedged price. As of JuneSeptember 30, 2009, and July 23,October 22, 2009, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.
     The following table summarizes the amount of MWs hedged against the Company’s baseload assets and as a percentage relative to the Company’s forecasted baseload capacity under the first and second lien structure as of July 23,October 22, 2009:
                     
 Equivalent Net Sales Secured by First and Second Lien Structure (a) 2009 2010 2011 2012 2013
 
In MW (b)
  4,851   5,029   3,711   2,066   801 
As a percentage of total forecasted baseload capacity (c)
  70%   74%   55%   31%   12% 
 
                     
Equivalent Net Sales Secured by First and Second Lien Structure (a)
 2009  2010  2011  2012  2013 
 
In MW(b)
  3,617   3,963   3,060   1,610   793 
As a percentage of total forecasted baseload capacity(c)
  52%   58%   45%   24%   12% 
 
(a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.
(b) 2009 MW value consists of AugustNovember through December positions only.
(c) Forecasted baseload capacity under the first and second lien structure represents 80% of the Company’s total Company’s baseload assets.
Asset Sales ——Disposition of MIBRAG Investment
     MIBRAG— On June 10, 2009, NRG completed the sale of its 50% ownership interest in Mibrag B.V. to a consortium of SeveročSeveroćeské 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 ($284 million at an exchange rate of 1.40 US$U.S.$/EUR), net of transaction costs. During the three and sixnine months ended JuneSeptember 30, 2009, NRG recognized a pre-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 three and sixnine months ended JuneSeptember 30, 2009, NRG recorded an exchange loss of $15 million and $24 million respectively, on the contract within “Other (loss)/income, net.”

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USES OF FUNDS
     The Company’s requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures including RepoweringNRGRepoweringNRG and environmental; and (iv) corporate financial transactions including return of capital to shareholders.
Commercial Operations
     NRG’s commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) initial collateral required to establish trading relationships; (iii) timing of disbursements and receipts (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of JuneSeptember 30, 2009, commercial operations had total cash collateral outstanding of $214$222 million, and $292$345 million outstanding in letters of credit to third parties primarily to support its economic hedging activities. As of JuneSeptember 30, 2009, total collateral held from counterparties was $468$293 million and $11$19 million of letters of credit. These collateral amounts do not include collateral postings by Merrill Lynch under the CSRA.

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     Upon execution of the CSRA Amendment, effective October 5, 2009, the Company is required to post collateral for any net liability derivatives, and other static margin associated with supply for Reliant Energy.
Debt Service Obligations
     NRG must annually offer a portion of its excess cash flow (as defined in the Senior Credit Facility) to its first lien lenders under the Term Loan Facility. The percentage of excess cash flow offered to these lenders is dependent upon the Company’s consolidated leverage ratio (as defined in the Senior Credit Facility) at the end of the preceding year. Of the amount offered, the first lien lenders must accept 50% while the remaining 50% may either be accepted or rejected at the lenders’ option. In March 2009, NRG made and the lenders accepted a repayment of approximately $197 million for the mandatory annual offer relating to 2008.
     As of JuneSeptember 30, 2009, NRG had issued approximately $5.4 billion in aggregate principal amount of unsecured high yield notes, or Senior Notes, had approximately $2.4 billion in principal amount outstanding under the Term Loan Facility, and had issued $516$544 million of letters of credit under the Company’s $1.3 billion Synthetic Letter of Credit Facility and $59$96 million of letters of credit under the Company’s Revolving Credit Facility. The Revolving Credit Facility matures on February 2, 2011, and the Synthetic Letter of Credit Facility matures on February 1, 2013.
     As of September 30, 2009, the Company’s CSF I and CSF II subsidiaries had outstanding notes and preferred interests classified as debt that matured in two tranches: $143 million for CSF II in October 2009, plus accrued interest and the balance of $190 million for CSF I in June 2010, plus accrued interest. 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. 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.
Capital Expenditures
     For the sixnine months ended JuneSeptember 30, 2009, the Company’s capital expenditures, including accruals, were approximately $366$556 million, of which $173$272 million was related toRepoweringNRG projects. The following table summarizes the Company’s capital expenditures for the sixnine months ended JuneSeptember 30, 2009, and the estimated capital expenditure and repowering investments forecast for the remainder of 2009.
                   
(In millions)
 Maintenance Environmental Repowering Total Maintenance Environmental Repowering Total
Northeast $17 $86 $5 $108  $  22 $  119 $  5 $  146 
Texas 78 — 89 167  112 — 134 246 
South Central 2 — — 2  3 — — 3 
West 3 — 1 4  3 — 2 5 
Reliant Energy 2 — — 2  14 — — 14 
Nuclear development — — 78 78  — — 130 130 
Other 5 — — 5  11 — 1 12 
Total $107 $86 $173 $366  $  165 $  119 $  272 $  556 
Estimated capital expenditures for the remainder of 2009 $  184 $  149 $  178 $  511  $  117 $  76 $  73 $  266 
     RepoweringNRGcapital expenditures and investments—RepoweringNRG project capital expenditures consisted of approximately $62$104 million related to the Company’s Langford wind farm project which is currently under construction. In addition, the Company’sRepoweringNRG capital expenditures included $27$29 million for the construction of Cedar Bayou Unit 4 in Texas and $78$130 million for the development of STP Units 3 and 4 in Texas.
     The Company’s estimated repowering capital expenditures for the remainder of 2009 are expected to be approximately $178$73 million. Of this amount, $115$58 million is estimated for STP Units 3 and 4 without giving effect to any partner contributions or potential equity sell down and approximately $47$10 million to complete the construction of the Langford wind farm.

97102

     Major maintenance and environmental capital expenditures— The Company’s baghouse projects at western New York facilities resulted in environmental capital expenditures of $79$104 million for the sixnine months ended JuneSeptember 30, 2009. In addition, the Company’s maintenance capital expenditures were $107$165 million, of which $78$112 million was primarily related to the Texas region’s baseload assets which included approximately $25$38 million in nuclear fuel expenditures related STP units 1 and 2.
     NRG anticipates funding its maintenance capital projects primarily with funds generated from operating activities. In addition, on April 15, 2009, the Company executed a $59 million tax-exempt bond financing through its wholly ownedwholly-owned subsidiary, Dunkirk Power LLC, with the bonds issued by the County of Chautauqua Industrial Development Agency. These funds are expected to fund environmental capital expenditures at the Dunkirk Generating facility.
     Loans to affiliates— The Company had funded approximately $48 million in interest bearing loans to GenConn Energy LLC, a 50/50 joint venture vehicle of NRG and the United Illuminating Company as part of the Devon and Middletown plant repowering projects prior to the closing of the EBL and GenConn Facility. At the timeAs of closing, $39 million wasSeptember 30, 2009, these loans were repaid with proceeds from the EBL financing. Except for a balance of less than $1 million that will be repaid during the third quarter of 2009, this loan was repaid during the second quarter 2009. Subsequent to the financing, the equity portion of construction costs for GenConn are funded through the EBLEBLs of NRG Connecticut Peaking and United Illuminating. These funds are made available to GenConn through convertible interest bearing promissory notes that convert to equity upon repayment of the EBL loans by NRG Connecticut Peaking and UI.United Illuminating. As of JuneSeptember 30, 2009, there was $70$88 million was outstanding under the loan from NRG.NRG Connecticut Peaking.
Environmental Capital Expenditures
     Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures to be incurred during the remainder of 2009from 2010 through 2013 to meet NRG’s environmental commitments will be approximately $1.1 billion$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 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.
Capital Allocation
     In addition to the aforementioned planned investments in maintenance and environmental capital expenditures andRepoweringNRG in 2009, and the 2009 repayment of Term Loan Facility debt to the first lien lenders, the Company’s Capital Allocation Plan includes the completion of the 2008 Capital Allocation Plan with the planned purchase of $30 million of common stock as well as the purchase of an additional $300 million in common stock under the previously announced 2009 Capital Allocation Plan, with such purchases to be made from time to time and subject to market conditions and other factors, includingPlan. In July 2009, as permitted by U.S. securities laws. On July 8, 2009,part of the Company announced an increase in planned purchases of $170 million under theCompany’s 2009 Capital Allocation plan.Program, the 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 approximately $250 million. NRG intends to complete theits $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 and other requirements.laws.
Preferred Stock Dividend Payments
     For the sixnine months ended JuneSeptember 30, 2009, NRG paid approximately $6 million, $9$13 million, and $6$8 million in dividend payments to holders of the Company’s 5.75%, 4%, and 3.625% Preferred Stock, respectively. On March 16, 2009, the outstanding shares of the 5.75% Preferred Stock converted into common stock and, as a result, there will be no further dividends paid with respect to this series of preferred stock.

98

CSF Share Lending Arrangement
     On February 20, 2009, CSF I and CSF II, wholly-owned unrestricted subsidiaries of the Company, entered into Share Lending Agreements with affiliates of Credit Suisse Group, or CS, relating to the shares of NRG common stock currently held by CSF I and II in connection with the CSF I and CSF II issued notes and preferred interests agreements, or 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 the current 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 June 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.
Benefit Plans Obligations
     As of JuneSeptember 30, 2009, NRG contributed $14$22 million towards its three defined benefit pension plans to meet the Company’s 2009 benefit obligation. The Company’s expected contribution to the plans is $16$5 million during the remainder of 2009. The total 2009 planned contribution of $30$27 million is a decrease of $30$33 million from the expected contributions as disclosed in Part II, Item 7 —-Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, in the Company’s Annual Report on Form 10-K for the 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.

103

Reliant Energy Customer Deposits
     Changes in the Texas law will require customer deposits and advance payments to be held in a segregated cash account on or before May 21, 2010. The amount of deposits subject to segregation at JuneSeptember 30, 2009, was approximately $58$56 million.
Cash Flow Discussion
     The following table reflects the changes in cash flows for the comparative years; all cash flow categories include the cash flows from both continuing operations and discontinued operations:
                    
(In millions)
            
Six months ended June 30,
 2009 2008 Change
Nine months ended September 30,
 2009 2008 Change
Net cash provided by operating activities $722 $436 $286  $1,280 $1,086 $194 
Net cash used by investing activities    (500)    (122)    (378)  (727)  (332)  (395)
Net cash provided by/(used by) financing activities 565  (233) 798  200  (446) 646 
Net Cash Provided By Operating Activities
     For the sixnine months ended JuneSeptember 30, 2009, net cash provided by operating activities increased by $286$194 million compared to the same period in 2008. The difference was2008, due to:
 • 
Collateral deposits and option premiumsCash generated by Reliant Energy— In 2009,Reliant Energy contributed approximately $370 million to the changes in both collateral deposits and option premiums paid and collected increasedCompany’s consolidated cash flow from operations in 2009, primarily reflecting $807 million in pre-tax income since the May 1, 2009, acquisition date. This contribution from pre-tax income was offset by $232$250 million duein collateral postings to close outsatisfy obligations under the CSRA. In addition, a seasonal increase in accounts receivable of commercial trade positions$174 million and lower commodity prices.a $68 million decrease in accrued expenses and other current liabilities also negatively impacted Reliant Energy’s cash flow from operations.
 • 
Working capitalLower cash flows from Wholesale Power Generation —The Company’s cash flow from operation excluding Reliant Energy was lower by approximately $176 million in 2009 compared to 2008, as drops in generation and power prices impacted results from operation. In 2009, theaddition, $15 million more cash fromwas used for working capital items increasedin 2009 compared to 2008, as higher coal inventory balances were partially offset by $54$35 million duelower pension contributions. The reductions to various changescash flows were partially offset by the return of collateral deposits from the settlement of gas options during the first quarter of 2009 which resulted in assets and liabilities.a $97 million net inflow of cash.

99

Net Cash Used By Investing Activities
     For the sixnine months ended JuneSeptember 30, 2009, net cash used in investing activities was $378increased by $395 million higher thancompared to the same period in 2008. This was2008, due to:
 • 
Acquisition of Reliant Energy— During the sixnine months ended JuneSeptember 30, 2009, the Company paid $345$356 million, net of cash acquired of $6 million, towards its acquisition of Reliant Energy. This amount was comprised of approximately $288 million paid at closing, andas well as $63 million paid on June 11, 2009, and $11 million paid on July 24, 2009, as an initial remittanceremittances of the approximately $82 million of acquired working capital to be remitted to RRI over the 8 months following the closing.RRI.
 • 
Trading of emission allowances —Net purchases and sales of emission allowances resulted in a decrease in cash of $94$117 million for 2009 as compared to 2008.
 • 
Proceeds from sale of equity method investment and discontinued operations —Net proceeds from investing activities increased by $55$43 million in 2009 as compared to 2008 due to the sale of MIBRAG in June 2009 for net proceeds of $284 and the sale of ITISA for proceeds, net of divested cash, of $229$241 million in the first half of 2008.
•
Capital expenditures and loans to affiliates —NRG’s capital expenditures decreased by $89 million due to decreased spending onRepoweringNRG projects. Loans to affiliates increased by $37 million in 2009 as compared to 2008.

104

Net Cash Provided By/Used By Financing Activities
     For the sixnine months ended JuneSeptember 30, 2009, net cash provided by financing activities increased by $798$646 million compared to 2008, due to:
 • 
Issuance of debt —During 2009, the Company received $25 million from the initial draw under the Reliant Energy working capital facility $34with Merrill Lynch, $38 million from the Dunkirk bonds, $70$88 million in GenConn financings and $688 million in gross proceeds from the 2019 Senior Notes. During 2008, the Company received $10$20 million in proceeds from borrowings.
 
 • 
Deferred financing costs —During 2009, the Company paid deferred financing costs of $15 million related to the Reliant Energy CSRA, $10 million related to the 2019 Senior Notes, and $2 million related to the Dunkirk bonds and the Reliant Energy working capital facility.
 • 
Term Loan Facility debt payment —In 2009, the Company paid down $213$221 million of its Term Loan Facility, including the payment of excess cash flow, as discussed above underDebt Service Obligations. The Company paid down $158$166 million of its Term Loan Facility during 2008 which resulted in a net cash decrease of $55 million for the six months ended 2009 as compared to the same period in 2008.million.
 • 
Share repurchase —During 2009, the Company did not repurchase anyrepurchased common stock during the first half in 2009,of $250 million as compared to $55$185 million for 2008.in 2008, which resulted in a net cash decrease of $65 million.
 • 
Payment of financing element ofNet payments to settle acquired derivatives —that include financing elements—In 2009, the Company paid a net of $22$140 million for the settlement of gas swaps related to Reliant Energy and Texas Genco compared to a payment of $28$49 million for 2008 related to Texas Genco for an increasea net decrease in cash of $6$91 million.
•
Payment for CSF I CAGR settlement —In August 2008, the Company paid $45 million to CS for the benefit of CSF I to early settle the embedded derivative in the Company’s CSF I notes and preferred interests.
 • 
Exercise of stock options —TheDuring 2009, the Company received proceeds of $8$1 million from the exercise of stock options as compared to $8 million for 2008.
•
Preferred dividends —During the nine months ended September 30, 2009, dividends payments on preferred stock decreased by $14 million as compared to the same period in 2008 due to the conversion of the 5.75% preferred stock in the fourth quarter of 2008 and for the first half of 2008.period ended September 30, 2009.

100

NOL’s,NOLs, Deferred Tax Assets and FIN 48Uncertain Tax Position Implications, under ASC-740, Income Taxes, or ASC 740
     As of JuneSeptember 30, 2009, the Company had generated total domestic pre-tax book income of $936$1,371 million and foreign continuing pre-tax book income of $142$151 million. The Company has net operating losses for tax return purposes that have been classified as capital loss carryforwards for financial statement purposes and for which a full valuation allowance has been established. In addition, NRG has cumulative foreign NOL carryforwards of $276$290 million, of which $78$83 million will expire starting in 2011 through 2018 and of which $198$207 million do not have an expiration date.
     In addition to these amounts, the Company has net operating losses for tax return purposes but have been classified as capital loss carryforwards for financial statements purposes and for which a full valuation allowance has been established. As a result of the Company’s tax position, and based on current forecasts, the Company anticipates income tax payments of up to $100$75 million during 2009.
     However, as the position remains uncertain, the Company has recorded a non-current tax liability of $463 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority.$688 million. The $463$688 million non-current tax liability for unrecognized tax benefits is due to taxable earnings for which there are no NOLs available to offset for financial statement purposes.
     The Company continues to be under examination by the Internal Revenue Service.

105

New and On-going Company Initiatives
FORNRGUpdate
     Beginning in January 2009, the Company transitioned toFORNRG 2.0 to target an incremental 100 basis point improvement to the Company’s ROIC by 2012. The initial targets forFORNRG 2.0 were based upon improvements in the Company’s ROIC as measured by increased cash flow. The economic goals ofFORNRG 2.0 will focus on: (i) revenue enhancement; (ii) cost savings; and (iii) asset optimization, including reducing excess working capital and other assets. TheFORNRG 2.0 program will measure its progress towards theFORNRG 2.0 goals by using the Company’s 2008 financial results as a baseline, while plant performance calculations will be based upon the appropriate historic baselines.
     The 2009FORNRG goal is a 20 basis point improvement in ROIC which corresponds to approximately $30 million in cash flow. As of JuneSeptember 30, 2009, the Company has exceeded its 2009 goal with a 22.929.5 basis point improvement in ROIC, which is equivalent to approximately $34$44 million in cash flows. The performance of the plants coupled with strategic projects undertaken by corporate functions is evidenced in the overall corporate performance.
Nuclear Innovation North America
     NINA is an NRG subsidiary focused on marketing, siting, developing, financing and investing in new advanced design nuclear projects in select markets across North America, including the planned STP Units 3 and 4 that NRG is developing on a 50/50 basis with City of San Antonio’s agent City Public Service Board of San Antonio, or CPS Energy, at the STP nuclear power station site. TANE, a wholly ownedwholly-owned subsidiary of Toshiba Corporation, owns a non-controlling interest in NINA. On May 1, 2009, TANE made the second of its scheduled $50 million contributions to NINA.
     The Department of Energy, or DOE, has confirmed that the South Texas Project expansion, or STP Units 3 and 4 is one of four projects selected for further due diligence and negotiation leading to a conditional commitment under the DOE loan guarantee program. NINA will now begin discussions with the DOE on the specific terms and amount to be loaned for the project. NRG believes DOE loan guarantee support is critical to new nuclear development projects. In addition to U.S. loan guarantees, NINA is seeking to diversify financing by actively pursuing additional loan guarantees through the Japanese government. Due diligence by Japanese financing agencies is in progress and represents an important step in Japanese loan support.

101

     On February 24, 2009, NINA executed an EPC agreement with TANE to build the STP expansion. The EPC agreement is structured so as to assure that the new plant is constructed on time, on budget and to exacting standards. In accordance with the EPC agreement, TANE will provide engineering and development services prior to Full Notice to Proceed, or FNTP, on a time and materials basis. Upon the New Source Review’s, or NRCNSR approval of the STP Units 3 and 4 combined license and the owners decision to issue the FNTP, the EPC converts to a lump-sum turnkey contract with customary warranties, performance and schedule guarantees, and liquidated damage provisions. TANE’s obligations are backed by a guaranty from its ultimate parent, the Toshiba Corporation. Concurrent with the execution of the EPC agreement, NINA entered into a $500 million credit facility with TANE to finance the cost of material and equipment commitments prior to FNTP for STP Units 3 and 4.
     In light of the progress made by the project in terms of regulatory schedule, DOE loan guarantee process, and the conclusion of the EPC agreement, NINA has initiated a partial sell down process in the STP expansion. NINA has Memorandums of Understanding with a mix of investment grade rated load serving entities and industrial customers for all offtake from NINA’s anticipated 40% ownership interest in STP Units 3 and 4’s generation. Currently, NINA and CPS Energy each own 50% of the 2,700 megawatt planned expansion of the South Texas Project nuclear facility. After the sell down, it is expected that each would own 40% and a new owner(s) would have a 20% equity interest although other ownership outcomes may arise. The ownership interests of STP Units 1 and 2 (NRG 44%, CPS Energy 40% and Austin Energy 16%) are not affected by this proposed sale.
     A request to intervene in the Combined License, or COL, proceeding was submitted by several individuals and public interest groups on April 21, 2009. An Atomic Licensing and Safety andBoard, or Licensing Board, or ASLB, panel heard oral arguments on athe Petitioner’s request for a hearing in the South Texas Project COL proceeding on June 23, 2009, and June 24, 2009, in Bay City, Texas. The ASLB isOn August 27, 2009, and September 29, 2009, the NRC’s quasi-judicial arm dealing with licensing matters. The oral argument addressed the admissibilityLicensing Board of the issues raisedUnited States Nuclear Regulatory Commission, or NRC, issued its decision on the petition to intervene in the COL proceeding for STP Units 3 and 4. Of the 28 contentions submitted by Petitionersthe Petitioner’s, the Licensing Board rejected 23 and admitted a portion of five contentions. The Licensing Board’s decision to admit a contention represents a procedural ruling only. The ruling does not reflect any decision on the merits of any admitted contention by the Licensing Board. NINA will continue to defend its position against the admitted contentions in their filing.future hearings.

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     On October 22, 2009, NINA amended its revolving credit agreement with the Royal Bank of Scotland PLC, or RBS. The ASLB is expectedamended agreement allows for NINA to issuehave borrowings outstanding on both its findings asRBS facility and its TANE facility. Under the new agreement NINA will be required to whether or not a hearing should be granted duringrepay all outstanding balances on the month of August.RBS facility by March 31, 2010.
Agreement with eSolar
     On June 1, 2009, NRG completed an agreement with eSolar, a leading provider of modular, scalable solar thermal power technology, to acquire the development rights for up to 465 MW of solar thermal power plants at sites in California and the Southwest. The agreement currently contemplates up to 465 MW of solar thermal development. The first plant is anticipated to begin producing electricity as early as 2011, subject to certain technology demonstration milestones being pursued by eSolar.eSolar and successful financial closing in 2010.  At the closing with eSolar, NRG invested approximately $5 million for an equity interest in eSolar and $5 million for deposits and land purchase options associated with development rights for three projects on sites in south central California and the Southwest U.S. as well as a portfolio of PPAs to develop, build, own and operate up to 1110 eSolar modular solar generating units at these sites.  These development assets will use eSolar’s concentrating solar power, or CSP, technology to sell renewable electricity under contracted PPAs with local utilities.
     NRG has three projects in various stages of development: NRG New Mexico SunTower,— On June 11, 2009, NRG announced the execution Alpine SunTower and Desert View SunTower.  While each of a 20-year solar power purchase agreement with El Paso Electric for the full capacity of a 92 MW solar power plant to be built on a 450 acre site located about 10 miles from El Paso, Texas near the City of Sunland Park, New Mexico. The Company anticipates the plant to be inthese projects has an anticipated commercial operation bydate, the second quarter 2011.
Alpine SunTower— On June 25, 2009, NRG, through its wholly owned subsidiary, Alpine Sun Tower, LLC, announceddevelopment of these projects are subject to certain conditions and milestones which may effect the executionCompany’s decision to pursue further development of a solar power purchase agreement with Pacific Gas and Electric Company for the full capacity of a 92 MW solar power plant to be built in Lancaster, California. The Company anticipates the plant to be in commercial operation by 2012.these projects.

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RepoweringNRG Update
     Currently, NRG has several projects in varying stages of development that include the following: a solar project with the City of Houston, a biomass project at the Montville Generating Station, a new generating unit at the Limestone power station and the repowering of Big Cajun I, Encina and El Segundo sites. The following is a summary of repowering projects that are under construction. In addition, NRG continues to participate in active bids in response to requests for proposals in markets in which it operates.
Plants Completed and Operating
     Cedar Bayou Generating Station— On June 24, 2009, NRG and Optim Energy, LLC, or Optim Energy, completed construction and began commercial operation of a new natural gas-fueled combined cycle generating plant at NRG’s Cedar Bayou Generating Station in Chambers County, Texas. NRG and Optim Energy have a 50/50 undivided interest basis in the 550 MW generating plant. NRG is the operator of the plant and Optim Energy is acting as energy manager for Cedar Bayou unit 4. Cedar Bayou unit 4 is providing the Company a net capacity of 275 MW given NRG’s 50% ownership.
Plants under Construction
     GenConn Energy LLC— In a procurement process conducted by the Department of Public Utility Control, or DPUC, and finalized in 2008, GenConn Energy, a 50/50 joint venture of NRG and The United Illuminating Company, secured contracts in 2008 with Connecticut Light & Power, or CL&P, for the construction and operation of two 200 MW peaking facilities, at NRG’s Devon and Middletown sites in Connecticut. The contracts, which are structured as contracts for differences for the operation of the new power plants, have a 30-year term and call for commercial operation of the Devon project by June 1, 2010, and the Middletown project by June 1, 2011. GenConn has secured all state permits required for the projects and has entered into contracts for engineering, construction and procurement of the eight GE LM6000 combustion turbines required for the projects. Construction has begun at the Devon facility while site while constructiondemolition has begun at the Middletown is expected to commence in the first quarter of 2010.location.
     On April 27, 2009, GenConn Energy closed on $534 million of project financing related to these projects. The project financing includes a seven-year project backed term loan and a five year working capital facility which together total $291 million. In addition, NRG and United Illuminating have each closed an equity bridge loan of $121.5 million, which together total $243 million. NRG is funding its share of costs related to these projects via year to date draw downs on the equity bridge loan of $70$88 million as of JuneSeptember 30, 2009. In August 2009, GenConn began to draw on the project financing facility to cover costs related to the Devon project.

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     Langford Wind Project— On March 16, 2009, NRG, through its wholly ownedwholly-owned subsidiary, Padoma Wind Power LLC, began construction on a 150 MW wind farm located in Tom Green, Irion, and Schleicher Counties, Texas. The Langford Wind Project will utilize 100 General Electric 1.5 MW wind turbines. The project is scheduled to reach commercial operation by the end of 2009.2009 and is expected to be eligible to qualify for a cash grant from the Department of Treasury.

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Off-Balance Sheet Arrangements
     Obligations under Certain Guarantee Contracts
     NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Note 17,18,Guarantees,to this Form 10-Q for additional discussion.
     See discussion in Note 3,4,Business Acquisition,to this Form 10-Q, regarding the CSRA as a result of the acquisition of Reliant Energy on May 1, 2009.
     Retained or Contingent Interests
     NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
     Derivative Instrument Obligations
     The Company’s 3.625% Preferred Stock includes a feature which is considered an embedded derivative per SFAS 133.ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFAS 133.ASC 815. As of JuneSeptember 30, 2009, based on the Company’s stock price, the embedded derivative was out-of-the-money and had no redemption value.
     The Company’s unrestricted wholly-owned subsidiary, CSF II, has outstanding notes and preferred interests that contain a feature considered an embedded derivative per SFAS 133.as defined in ASC 815. Although it is considered a derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFAS 133.ASC 815. As of JuneSeptember 30, 2009, based on the Company’s stock price, the CSF II embedded derivative was out-of-the-money and had no redemption value.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
     Variable Interest in Equity Investments— As of JuneSeptember 30, 2009, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. One of these investments, GenConn, is a variable interest entity for which NRG is not the primary beneficiary.
     NRG’s pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $68$77 million as of JuneSeptember 30, 2009. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.
     Letter of Credit Facilities— The Company’s $1.3 billion Synthetic Letter of Credit Facility is unfunded by NRG and is secured by a $1.3 billion cash deposit at Deutsche Bank AG, New York Branch that was funded using proceeds from the Term Loan Facility investors who participated in the facility syndication. Under the Synthetic Letter of Credit Facility, NRG is allowed to issue letters of credit for general corporate purposes including posting collateral to support the Company’s commercial operations activities.
Contractual Obligations and Commercial Commitments
     NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company’s capital expenditure programs, as disclosed in the Company’s Form 10-K. Also see Note 14,15,Commitments and Contingencies, to the condensed consolidated financial statements of this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the first half ofnine months ended September 30, 2009.

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Critical Accounting Policies and Estimates
     NRG’s discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S.United States. The preparation of these financial statements and related disclosures in compliance with generally accepted accounting principles, or GAAP, requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects and legal and regulatory challenges. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.
     On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company’s estimates. Effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
     Critical accounting policies and estimates are the accounting policies that are most important to the portrayal of NRG’s financial condition and results of operations and require management’s most difficult, subjective or complex judgment. NRG’s critical accounting policies include revenue recognition and derivative accounting, income taxes and valuation allowance for deferred taxes, evaluation of assets for impairment and other than temporary decline in value, goodwill and other intangible assets, and contingencies.
     In connection with the Reliant Energy acquisition, the Company will record additional intangible assets. See Note 3 –4,Business Acquisition.
     The following represents new critical estimates of, to this Form 10-Q. In addition, accrued unbilled revenues and cost of energy related to the Company’s Reliant Energy segment that would have a material impactare critical accounting estimates as volumes are not precisely known at the end of each reporting period and the revenue amounts are material. Accrued unbilled revenues were $321 million as of September 30, 2009, which represents 5% of the Company’s consolidated revenues for the nine months ended September 30, 2009, and 11% of Reliant Energy’s revenues for the period ended September 30, 2009. Accrued unbilled revenues are based on Reliant Energy’s estimates of customer usage since the segment’s financial conditiondate of the last meter reading provided by the independent system operators or results of operations:
•
Accrued Unbilled Revenues—Accrued unbilled revenues are critical accounting estimates as volumes are not precisely known at the end of each reporting period and the revenue amounts are material. Accrued unbilled revenues of $433 million as of June 30, 2009 which represents 11% of the Company’s consolidated revenues for the six months ended June 30, 2009 and 37% of Reliant Energy’s revenues for the two months ended June 30, 2009.
•
Estimated Energy Supply Costs—Reliant Energy record energy supply costs for electricity sales and services to retail customers based on estimated supply volumes for the applicable reporting period. This is a critical accounting estimate as volumes are not known at the end of each reporting period and the purchased power amounts are material. Reliant Energy’s energy supply costs of $93 million as of June 30, 2009 consist of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities.
In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. The Company estimates transmission and distribution delivery fees using the same method that is used for electricity sales and services to retail customers. In addition, NRG estimates ERCOT ISO fees based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as purchased power in the applicable reporting period. Changes in the Company’s volume usage would result in a similar offsetting change in billed volumes, thus partially mitigating the Company energy supply costs.
•
Dependence on ERCOT ISO Settlement Procedures—Preliminary settlement information is due from the ERCOT ISO within two months after electricity is delivered. Final settlement information is due from the ERCOT ISO within six months after electricity is delivered. The six month settlement received from ERCOT is considered final as ERCOT will only resettle if there are data errors greater than 2% of that day’s transaction dollars or if alternate dispute resolutions are granted. The Company records estimated supply costs and related fees using estimated supply volumes, as discussed above, and adjust those costs upon receipt of the ERCOT ISO information. Delays in settlements could materially affect the accuracy of NRG’s recorded energy supply costs and related fees.
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.

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ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     NRG is exposed to several market risks in the Company’s normal business activities. Market risk is the potential loss that may result from market changes associated with the Company’s merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk, and currency exchange risk. In order to manage these risks, the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in the over-the-counter financial markets to:
Manage and hedge fixed-price purchase and sales commitments;
Manage and hedge exposure to variable rate debt obligations;
Reduce exposure to the volatility of cash market prices; and
Hedge fuel requirements for the Company’s generating facilities.
•Manage and hedge fixed-price purchase and sales commitments;
•Manage and hedge exposure to variable rate debt obligations;
•Reduce exposure to the volatility of cash market prices; and
•Hedge fuel requirements for the Company’s generating facilities.
Commodity Price Risk
     Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. A number of factors influence the level and volatility of prices for energy commodities and related derivative products. These factors include:
Seasonal, daily and hourly changes in demand;
Extreme peak demands due to weather conditions;
Available supply resources;
Transportation availability and reliability within and between regions; and
Changes in the nature and extent of federal and state regulations.
•Seasonal, daily and hourly changes in demand;
•Extreme peak demands due to weather conditions;
•Available supply resources;
•Transportation availability and reliability within and between regions; and
•Changes in the nature and extent of federal and state regulations.
     As a result of the acquisition of Reliant Energy, NRG’s portfolio consists of generation assets and full requirement load serving obligations. NRG manages the commodity price risk of the Company’s merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as New York Mercantile Exchange, or NYMEX, Intercontinental Exchange, or ICE, and Chicago Climate Exchange, or CCX, as well as over-the-counter financial markets. The portion of forecasted transactions hedged may vary based upon management’s assessment of market, weather, operations and other factors.
     While some of the contracts the Company uses to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. NRG uses the Company’s best estimates to determine the fair value of commodity and derivative contracts held and sold. These estimates consider various factors, including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. However, it is likely that future market prices could vary from those used in recording mark-to-market derivative instrument valuation, and such variations could be material.
     NRG measures the risk of the Company’s portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VaR. VaR is a statistical concept that defines risk of loss, at a certain confidence level, over a designated horizon due to changes in market prices over that horizon. Currently, the company estimates VaR using a Monte Carlo simulation of prices. NRG’s total portfolio includes mark-to-market and non-mark-to-market energy assets and liabilities.
     NRG uses a diversified VaR model to calculate an estimate of the potential loss in the fair value of the Company’s energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions. The key assumptions for the Company’s diversified model include: (i) a lognormal distribution of prices; (ii) a one-day holding period; (iii) a 95% confidence interval; (iv) a rolling 36-month forward looking period; and (v) market implied volatilities and historical price correlations.

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     As of JuneSeptember 30, 2009, the VaR for NRG’s commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the diversified VaR model was $49$53 million. The inclusion of the Reliant Energy retail portfolio, comprised of contracted load and related supply, did not materially affect the VaR measure as the portfolio is currently hedged.

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     The following table summarizes average, maximum and minimum VaR for NRG for the three and sixnine months ended JuneSeptember 30, 2009, and 2008:
              
(In millions)
          
VAR
 2009 2008  2009 2008 
Three months ended June 30: $49 $58 
Three months ended September 30: $53 $51 
Average 35 50  49 48 
Maximum 54 63  55 62 
Minimum 28 39  42 35 
Six months ended June 30: $49 $58 
Nine months ended September 30: $53 $51 
Average 38 52  42 50 
Maximum 54 65  55 65 
Minimum 28 35  28 35 
     Due to the inherent limitations of statistical measures such as VaR, the evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VaR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated VaR, and such changes could have a material impact on the Company’s financial results.
     In order to provide additional information for comparative purposes to NRG’s peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of JuneSeptember 30, 2009, for the entire term of these instruments entered into for both asset management and trading, was approximately $42$26 million primarily driven by asset-backed transactions.
Interest Rate Risk
     NRG is exposed to fluctuations in interest rates through the Company’s issuance of fixed rate and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG’s risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.
     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.
     As of JuneSeptember 30, 2009, the Company had various interest rate swap agreements with notional amounts totaling approximately $3.3 billion. If the swaps had been discontinued on JuneSeptember 30, 2009, the Company would have owed the counterparties approximately $120$124 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.
     NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of JuneSeptember 30, 2009, a 1% change in interest rates would result in a $13$11 million change in interest expense on a rolling twelve month basis.
     As of JuneSeptember 30, 2009, the Company’s long-term debt fair value was $8.3$8.4 billion and the carrying amount was $8.6 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company’s long-term debt by $456$435 million.

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Liquidity Risk
     Liquidity risk arises from the general funding needs of NRG’s activities and in the management of the Company’s assets and liabilities. NRG’s liquidity management framework is intended to maximize liquidity access and minimize funding costs. Through active liquidity management, the Company seeks to preserve stable, reliable and cost-effective sources of funding. This enables the Company to replace maturing obligations when due and fund assets at appropriate maturities and rates. To accomplish this task, management uses a variety of liquidity risk measures that take into consideration market conditions, prevailing interest rates, liquidity needs, and the desired maturity profile of liabilities.
     Based on a sensitivity analysis for power and gas positions under marginable contracts excluding all non-affiliate third party positions under the CSRA, a $1 per MMBtu increase or decreasechange in natural gas prices across the term of the marginable contracts would cause a change in margin collateral outstandingposted of approximately $65$73 million as of JuneSeptember 30, 2009, and a 0.25 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $63$53 million as of JuneSeptember 30, 2009. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of JuneSeptember 30, 2009.
     With the CSRA Amendment, effective October 5, 2009, based on a sensitivity analysis for power and gas positions under marginable contracts, a $1 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $164 million, and a $0.25 MMBtu/MWh change in heat rate positions would result in a change in margin collateral posted of approximately $69 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of October 5, 2009.
     Under the second lien, NRG is required to post certain letterletters of creditscredit as credit support for changes in commodity prices. As of JuneSeptember 30, 2009, no letters of credit are outstanding to second lien counterparties. With changes in commodity prices, the letters of credit could grow to $87 million, the cap under the agreements.
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.
     UnderSince the current economic downturncredit crisis began in the U.S. and overseas,late 2008, the Company has heightened its management and mitigation of counterpartytaken several additional steps to mitigate credit risk by using credit limits,including the use of netting agreements,arrangements, entering contracts with collateral thresholds, setting volumetric limits with certain counterparties and other mitigation measures,restricting trading relationships with counterparties where available.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 JuneSeptember 30, 2009, total credit exposure to substantially all counterparties was $2.1$1.8 billion and NRG held collateral (cash and letters of credit) against those positions of $469$280 million resulting in a net exposure of $1.7 billion compared with a net exposure of $1.3 billion as of March 31, 2009. This increase is due to Merrill Lynch’s position as credit provider to Reliant Energy and the exposure resulting from novated trades that were completed as part of the acquisition of Reliant Energy, as discussed Note 3 — Business Acquistion.$1.5 billion. Total credit exposure is discounted at the risk free rate.

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     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 normal purchase and sale,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)(b) as of
  Juneas of September 30, 2009
Category
 (% of Total)
 
Financial institutions  8281%
Utilities, energy, merchants, marketers and other  1413 
Coal suppliers  23 
ISOs  23 
 
Total  100%
 
 
  Net Exposure(a) (b)(b) as of
  Juneas of September 30, 2009
Category
 (% of Total)
 
Investment grade  9493%
Non-Investment grade  —2 
Non-rated  65 
 
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 tabledo not include non-affiliate third party exposure under the CSRA. The gross credit exposure to third parties under the CSRA is $410$385 million, and the cash collateral held by Merrill Lynch against this exposure is $312$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 $707$704 million. NRG has significant credit risk concentration with Merrill Lynch primarily due to cash collateral held by Merrill Lynch for positions under the CSRA. NRG expects this risk to be significantly reduced when the Company unwinds the CSRA. Approximately 85%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.
     NRG is exposed to retail credit risk through ourits competitive electricity supply business, which serves commercial and industrial 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 moneyin-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.
Fair Value of Derivative Instruments
     NRG may enter into long-term power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices, to hedge fuel requirements at generation facilities, hedge supplies for retail operations and protect fuel inventories. In addition, in order to mitigate interest rate risk associated with the issuance of the Company’s variable rate and fixed rate debt, NRG enters into interest rate swap agreements.
     NRG’s trading activities include contracts 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 energy marketing portfolio.

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     The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value.value in accordance with ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; identify changes in fair value attributable to changes in valuation techniques; disaggregate estimated fair values at JuneSeptember 30, 2009, based on whethertheir level within the fair values are determined by quoted market prices or more subjective means;value hiearchy defined in ASC 820; and indicate the maturities of contracts at JuneSeptember 30, 2009. Also, in connection with the Company’s acquisition of Reliant Energy, NRG acquired retail load and supply contracts. The table below also includes the fair value of supply contracts under mark-to-market accounting treatment as of May 1, 2009.
        
Derivative Activity Gains/(Losses)
 (In millions) (In millions) 
Fair value of contracts as of December 31, 2008 $996  $996 
Contracts realized or otherwise settled during the period  (322)  (375)
Contracts acquired in conjunction with Reliant Energy    (1,054)  (1,054)
Changes in fair value 860  795 
Fair value of contracts as of June 30, 2009 $480 
Fair value of contracts as of September 30, 2009 $362 
                     
  
Fair Value of Contracts as of June 30, 2009
  Maturity         Maturity  
(In millions)
 Less Than Maturity Maturity in Excess Total Fair
Sources of Fair Value Gains/(Losses)
 1 Year 1-3 Years 4-5 Years 4-5 Years Value
 
Prices actively quoted $11  $9  $—  $—  $20 
Prices provided by other external sources  130   131   179   (30)  410 
Prices provided by models and other valuation methods  57   (7)  —   —   50 
 
 Total $  198  $  133  $  179  $  (30) $    480 
 
                     
  Fair Value of Contracts as of September 30, 2009
  Maturity         Maturity  
(In millions) Less Than Maturity Maturity in Excess   Total Fair 
Fair value hiearchy gains/(losses) 1 Year 1-3 Years 4-5 Years 4-5 Years   Value 
 
Level 1 $5  $4  $(1) $—  $8 
Level 2  204   131   120   (31)  424 
Level 3  (27)  (43)  —   —   (70)
 
Total $182  $92  $119  $(31) $362 
 
     A small portion of NRG’s contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG’s contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company’s prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company’s derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate our transactions and we believe such price quotes are executable. We do not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 10%19% of the total fair value of all derivative contracts. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG’s net exposure under a specific master agreement is an asset, the Company is usinguses the counterparty’s default swap rate. If the exposure under a specific master agreement is a liability, the Company is usinguses NRG’s default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG’s liabilities or that a market participant would be willing to pay for NRG’s assets. As of JuneSeptember 30, 2009, the credit reserve resulted in a $23$18 million increase in fair value which is composed of a $1$4 million lossgain in OCI and a $24$14 million gain in derivative revenue and cost of operations.
     The fair values in each category reflect the level of forward prices and volatility factors as of JuneSeptember 30, 2009, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

110

     The Company has elected to disclose derivative activity on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company’s portfolio. As discussed in Item 7A— Commodity Price Riskin the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, NRG measures the sensitivity of the Company’s portfolio to potential changes in market prices using Value at Risk, or VAR,VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG’s risk management policy places a limit on one-day holding period VAR,VaR, which limits the Company’s net open position. As the Company’s trade-by-trade derivative accounting results in a gross-up of the Company’s derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG’s hedging activity. As of JuneSeptember 30, 2009, NRG’s net derivative asset was $480$362 million, a decrease to total fair value of $516$634 million as compared to December 31, 2008. This decrease was primarily driven by the acquisition of Reliant Energy’s retail portfolio offset by increase in fair value due to the decreases in gas and power prices and the roll-off of trades that settled during the period.
     Based on a sensitivity analysis, the impact of a $1 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $574 million in the value of derivatives as of September 30, 2009.

114

Currency Exchange Risk
     NRG may be subject to foreign currency exchange risk as a result of the Company entering into purchase commitments with foreign vendors for the purchase of major equipment associated withRepoweringNRG initiatives. To reduce the risks to such foreign currency exposure, the Company may enter into transactions to hedge its foreign currency exposure using currency options and forward contracts. As of JuneSeptember 30, 2009, there were no foreign currency options andor forward contracts outstanding for purchase commitments.
     In connection with the MIBRAG sale 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 three and sixnine months ended JuneSeptember 30, 2009, NRG recorded an exchange loss of $15 million and $24 million respectively, on the contract within “Other income/(expense).”
     As a result of the Company’s limited foreign currency exposure to date, the effect of foreign currency fluctuations has not been material to the Company’s results of operations, financial position and cash flows as of and for the three and nine months ended JuneSeptember 30, 2009.
ITEM 4 — CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
     Under the supervision and with the participation of NRG’s management, including its principal executive officer, principal financial officer, and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on this evaluation, the Company’s principal executive officer, principal financial officer, and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report on Form 10-Q.
Changes in Internal Control over Financial Reporting
     There were no changes in the Company’s internal controls over financial reporting (as such term is defined in RulesRule 13a-15(f) under the Exchange Act) that occurred in the secondthird quarter of 2009 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Inherent Limitations over Internal Controls
     NRG’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. However, internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

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PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
     For a discussion of material legal proceedings in which NRG was involved through JuneSeptember 30, 2009, see Note 14,15,Commitments and Contingencies, to the condensed consolidated financial statements of this Form 10-Q.
ITEM 1A — RISK FACTORS
     In addition to the revised risk factors below, informationInformation regarding risk factors appears in Part I, Item 1A,Risk Factorsin NRG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and Part II, Item 1A,Risk Factorsin NRG’s Quarterly Report on Form 10-Q for the quarterquarters ended March 31, 2009.
Risks Related to the Reliant Energy Retail Business
NRG may have to post significant amounts of collateral, which could adversely affect its liquidity, financial position2009 and business.
     In connection with any unwind of the Company’s credit-enhanced retail structure with Merrill Lynch, NRG will have to post collateral for new retail supply and hedging transactions in connection with Reliant Energy’s retail business. The Company’s levels of collateral postings would be determined and impacted by the terms and timing of the unwind, the nature and volume of the Company’s commodity hedging agreements, commodity prices and other strategic alternatives that NRG may undertake. While NRG intends to (i) become the primary provider of Reliant Energy’s supply requirements; and (ii) use a portion of the net proceeds of the 8.50% Senior Notes to the cash collateralize Reliant Energy’s obligations under the credit sleeve arrangements (assuming NRG can reach an agreement with Merrill Lynch on terms acceptable to the Company), depending on the specific timing and the movement in underlying commodity prices, NRG could incur significant collateral posting obligations that may require the Company to seek additional sources of liquidity, including additional debt. The covenants in NRG’s senior secured credit facility and credit sleeve arrangements with Merrill Lynch restrict the Company’s ability to, among other things, obtain additional financing. If NRG were unable to generate sufficient cash flows from operations or raise cash from other sources, NRG may not be able to meet the Company’s collateral posting obligations. These situations could result from further adverse developments in the energy, fuel or capital markets, a disruption in NRG’s operations or those of third parties or other events adversely affecting NRG’s cash flows and financial performance. NRG cannot make any assurances that it would be able to obtain such additional liquidity on commercially reasonable terms or at all.
Volatile power supply costs and demand for power could adversely affect the financial performance of NRG’s retail business.
     Although NRG has begun the process of becoming the primary provider of Reliant Energy’s supply requirements, Reliant Energy presently purchases a substantial portion of its supply requirements from third parties. As a result, Reliant Energy’s financial performance depends on its ability to obtain adequate supplies of electric generation from third parties at prices below the prices it charges its customers. Consequently, the Company’s earnings and cash flows could be adversely affected in any period in which Reliant Energy’s power supply costs rise at a greater rate than the rates it charges to customers. The price of power supply purchases associated with Reliant Energy’s energy commitments can be different than that reflected in the rates charged to customers due to, among other factors:
varying supply procurement contracts used and the timing of entering into related contracts;
subsequent changes in the overall price of natural gas;
daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
transmission constraints and the Company’s ability to move power to its customers; and
changes in market heat rate (i.e., the relationship between power and natural gas prices).
     The Company’s earnings and cash flows could also be adversely affected in any period in which the demand for power significantly varies from the forecasted supply, which could occur due to, among other factors, weather events, competition and economic conditions.

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NRG depends on the Electric Reliability Council of Texas, or ERCOT, to communicate operating and system information in a timely and accurate manner. Information that is not timely or accurate can have an impact on the Company’s current and future reported financial results.
     ERCOT communicates information relating to a customer’s choice of retail electric provider and other data needed for servicing the customer accounts of the Company’s retail electric providers. Any failure to perform these tasks will result in delays and other problems in enrolling, switching and billing customers. Information that is not timely or accurate may adversely impact the Company’s ability to serve load in the optimum manner.
NRG could be liable for a share of the payment defaults of other market participants.
     If a market participant defaults on its payment obligations to an independent system operator, or ISO, the Company, together with other market participants, are liable for a portion of the default obligation that is not otherwise covered by the defaulting market participant. Each ISO establishes credit requirements applicable to market participants and the basis for allocating payment default amounts to market participants. In ERCOT, the allocation is based on share of the total load.
Significant events beyond the Company’s control, such as hurricanes and other weather-related problems or acts of terrorism, could cause a loss of load and customers and thus have a material adverse effect on the Company’s business.
     The uncertainty associated with events beyond the Company’s control, such as significant weather events and the risk of future terrorist activity, could cause a loss of load and customers and may affect the Company’s results of operations and financial condition in unpredictable ways. In addition, significant weather events or terrorist actions could damage or shut down the power transmission and distribution facilities upon which the retail business is dependent. Power supply may be sold at a loss if these events cause a significant loss of retail customer load.June 30, 2009.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
     None.
                 
              Dollar value of
          Total number of shares shares that may be
          purchased as part of purchased under the
  Total number of Average price publicly announced 2009 Capital Allocation 
For the period ended September 30, 2009 shares purchased paid per share plans or programs Plan
 
First quarter 2009  —  $—   —  $330,000,000 
Second quarter 2009  —   —   —   330,000,000 
                 
July 1 – July 31  —   —   —   500,000,000 
August 1 – August 31  8,477,000   28.09   8,477,000   261,753,846 
September 1 – September 30  442,100   26.57   442,100   250,002,565 
 
Third quarter 2009 Total  8,919,100   28.01   8,919,100   250,002,565 
 
Year-to-date  8,919,100  $28.01   8,919,100  $250,002,565 
 
     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 approximately $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.
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
     None.
ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     None.The stockholders of NRG Energy, Inc. voted on nine items at the Annual Meeting of Stockholders held on July 21, 2009:
1.The election of Class III Directors to a three-year term;
2.The proposal to adopt the NRG Energy, Inc. Amended and Restated Long-Term Incentive Plan;
3.The proposal to adopt the NRG Energy, Inc. Amended and Restated Annual Incentive Plan for Designated Corporate Officers;
4.The proposal to approve the amendment to Article Six of the Amended and Restated Certificate of Incorporation;
5.The proposal to ratify the appointment of KPMG LLP as NRG’s independent registered public accounting firm;
6.The stockholder proposal to prepare a report on the Carbon Principles;
7.Exelon Corporation’s proposal to approve an amendment to the NRG Bylaws to increase the size of the NRG Board to 19 members;
8.If proposal 7 was approved, Exelon’s proposal to elect five Exelon nominees to serve as a director of NRG Board; and
9.Exelon’s proposal to repeal any Bylaw amendments adopted by the NRG Board without stockholder approval after February 26, 2008 and prior to the effectiveness of the resolution effecting such repeal.
     There were 265,646,655 shares of common and preferred stock entitled to vote at the meeting and a total of 234,133,623 shares (approximately 88%) were represented at the meeting.

116

     The four NRG nominees named below were elected to serve a three-year term as Class III Directors expiring at the annual meeting of stockholders in 2012, while the four Exelon nominees named below were defeated:
         
NRG NomineeVotes For Votes Withheld
 
John F. Chlebowski  175,973,764   691,844 
Howard E. Cosgrove  176,009,097   656,511 
William E. Hantke  176,018,113   647,495 
Anne C. Schaumburg  176,019,858   645,750 
 
 
Exelon NomineeVotes For Votes Withheld
 
Betsy S. Atkins  57,258,080   209,935 
Ralph E. Faison  57,256,776   211,239 
Coleman Peterson  57,256,676   211,339 
Thomas C. Wajnert  57,256,726   211,289 
 
     The names of the directors whose terms as directors continued after the meeting are as follows:
•Class I: Kirbyjon H. Caldwell, David Crane, Stephen L. Cropper, Kathleen A. McGinty, Thomas W. Weidemeyer
•Class II: Lawrence S. Coben, Paul W. Hobby, Gerald Luterman, Herbert H. Tate, Walter R. Young
     The proposal to adopt the NRG Energy, Inc. Amended and Restated Long-Term Incentive Plan was approved with 225,514,895 shares voting for, 4,790,467 shares voting against, and 3,828,260 shares abstaining.
     The proposal to adopt the NRG Energy, Inc. Amended and Restated Annual Incentive Plan for Designated Corporate Officers was approved with 228,716,330 shares voting for, 1,578,602 shares voting against, and 3,838,682 shares abstaining.
     The proposal to approve the amendment to Article Six of the Amended and Restated Certificate of Incorporation was approved with 227,053,518 shares voting for, 3,098,376 shares voting against, and 3,981,728 shares abstaining.
     The proposal to ratify the appointment of KPMG LLP as independent registered public accounting firm was ratified with 229,676,224 shares voting for, 653,217 shares voting against, 3,804,181 shares abstaining.
     The stockholder proposal to prepare a report on the Carbon Principles was defeated with 189,432,665 shares voting against, 2,553,249 voting for, and 42,147,708 abstaining.
     Exelon Corporation’s proposal to approve an amendment to the NRG Bylaws to increase the size of the NRG Board to 19 members was defeated with 179,032,706 shares voting against, 54,982,954 shares voting for, and 117,963 abstaining. As a result of the defeat of this proposal, Exelon’s proposal to elect five additional Exelon nominees to serve as a director of the NRG Board was rendered moot.
     Exelon’s proposal to repeal any Bylaw amendments adopted by the NRG Board without stockholder approval after February 26, 2008 and prior to the effectiveness of the resolution effecting such repeal was defeated with 195,842,708 shares voting against, 38,084,601 shares voting for, and 206,313 abstaining. Regardless of the vote outcome, NRG did not initiate any amendments to the Bylaws during the reference period.
ITEM 5 — OTHER INFORMATION
     None.

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ITEM 6 — EXHIBITS
   
Exhibits  
   
4.1 Sixteenth
Twenty-Third Supplemental Indenture, dated April 28,July 14, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York.(1)
   
4.2 Seventeenth
Twenty-Fourth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York.(1)
4.3Eighteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York.(1)
4.4Nineteenth Supplemental Indenture, dated May 8,October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.(2)
   
4.54.3 Twentieth
Twenty-Fifth Supplemental Indenture, dated May 8,October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.(2)
   
4.64.4 Twenty-First
Twenty-Sixth Supplemental Indenture, dated May 8,October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.(2)
   
4.74.5 Twenty-Second
Twenty-Seventh Supplemental Indenture, dated JuneOctober 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.(3) (2)
4.8Twenty-Third Supplemental Indenture, dated July 14, 2009, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.(4)
   
10.1A Amended and Restated Credit Sleeve and Reimbursement Agreement, dated May 1,September 30, 2009 (effective October 5, 2009), among Reliant Energy Power Supply, LLC, RERH Holdings, LLC, Reliant Energy Retail Holdings, LLC, Reliant Energy Retail Services, LLC, RE Retail Receivables,Renewables, LLC, Merrill Lynch Commodities, Inc. and Merrill Lynch & Co., Inc.(5)
   
10.1B Schedules and Exhibits to the Amended and Restated Credit Sleeve and Reimbursement Agreement, dated May 1,September 30, 2009 (effective October 5, 2009) (Portions of this Exhibit have been omitted pursuant to a request for confidential treatment).(5)
10.2Contingent Contribution Agreement, dated May 1, 2009, among NRG Energy, Inc., NRG Retail LLC, RERH Holdings, LLC, Reliant Energy Retail Holdings, LLC and Merrill Lynch Commodities, Inc.(5)
   
31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
   
31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
   
31.3 Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
   
32 Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.
101.INSXBRL Instance Document
101.SCHXBRL Taxonomy Extension Schema
101.CALXBRL Taxonomy Extension Calculation Linkbase
101.DEFXBRL Taxonomy Extension Definition Linkbase
101.LABXBRL Taxonomy Extension Label Linkbase
101.PREXBRL Taxonomy Extension Presentation Linkbase
(1) Incorporated herein by reference to NRG Energy, Inc’sInc.’s current report on Form 8-K filed on May 4, 2009July 15, 2009.
 
(2) Incorporated herein by reference to NRG Energy, Inc’sInc.’s current report on Form 8-K filed on May 14, 2009
(3)Incorporated herein by reference to NRG Energy, Inc’s current report on Form 8-K filed on June 5, 2009
(4)Incorporated herein by reference to NRG Energy, Inc’s current report on Form 8-K filed on July 15, 2009
(5)Incorporated herein by reference to NRG Energy, Inc’s current report on Form 8-K filed on May 7, 2009October 6, 2009.

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
     
  NRG ENERGY, INC.
(Registrant)		   
By:     
  /s/ DAVID W. CRANE   
  
David W. Crane
Chief Executive Officer
(Principal Executive Officer)		  
 
  /s/ ROBERT C. FLEXON   
  
Robert C. Flexon
Chief Financial Officer
(Principal Financial Officer)		  
 
  /s/ JAMES J. INGOLDSBY   
  
James J. Ingoldsby		  
Date: July 30,November 2, 2009 Chief Accounting Officer
(Principal Accounting Officer)		  
 (Principal Accounting Officer)

115119

EXHIBIT INDEX
   
Exhibits  
   
4.1 Sixteenth
Twenty-Third Supplemental Indenture, dated April 28,July 14, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York.(1)
   
4.2 Seventeenth
Twenty-Fourth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York.(1)
4.3Eighteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York.(1)
4.4Nineteenth Supplemental Indenture, dated May 8,October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.(2)
   
4.54.3 Twentieth
Twenty-Fifth Supplemental Indenture, dated May 8,October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.(2)
   
4.64.4 Twenty-First
Twenty-Sixth Supplemental Indenture, dated May 8,October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.(2)
   
4.74.5 Twenty-Second
Twenty-Seventh Supplemental Indenture, dated JuneOctober 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.(3) (2)
4.8Twenty-Third Supplemental Indenture, dated July 14, 2009, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.(4)
   
10.1A Amended and Restated Credit Sleeve and Reimbursement Agreement, dated May 1,September 30, 2009, among Reliant Energy Power Supply, LLC, RERH Holdings, LLC, Reliant Energy Retail Holdings, LLC, Reliant Energy Retail Services, LLC, RE Retail Receivables,Renewables, LLC, Merrill Lynch Commodities, Inc. and Merrill Lynch & Co., Inc.(5)
   
10.1B Schedules and Exhibits to the Amended and Restated Credit Sleeve and Reimbursement Agreement, dated May 1,September 30, 2009 (effective October 5, 2009) (Portions of this Exhibit have been omitted pursuant to a request for confidential treatment).(5)
10.2Contingent Contribution Agreement, dated May 1, 2009, among NRG Energy, Inc., NRG Retail LLC, RERH Holdings, LLC, Reliant Energy Retail Holdings, LLC and Merrill Lynch Commodities, Inc.(5)
   
31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
   
31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
   
31.3 Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
   
32 Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith.
101.INSXBRL Instance Document
101.SCHXBRL Taxonomy Extension Schema
101.CALXBRL Taxonomy Extension Calculation Linkbase
101.DEFXBRL Taxonomy Extension Definition Linkbase
101.LABXBRL Taxonomy Extension Label Linkbase
101.PREXBRL Taxonomy Extension Presentation Linkbase
(1) Incorporated herein by reference to NRG Energy, Inc’sInc.’s current report on Form 8-K filed on May 4, 2009July 15, 2009.
 
(2) Incorporated herein by reference to NRG Energy, Inc’sInc.’s current report on Form 8-K filed on May 14, 2009
(3)Incorporated herein by reference to NRG Energy, Inc’s current report on Form 8-K filed on June 5, 2009
(4)Incorporated herein by reference to NRG Energy, Inc’s current report on Form 8-K filed on July 15, 2009
(5)Incorporated herein by reference to NRG Energy, Inc’s current report on Form 8-K filed on May 7, 2009October 6, 2009.

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