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Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
     
þ   Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended: June 30, 2010
     
o   Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission File Number: 001-15891
NRG Energy, Inc.
(Exact name of registrant as specified in its charter)
     
Delaware   41-1724239
(State or other jurisdiction   (I.R.S. Employer
of incorporation or organization)   Identification No.)
     
211 Carnegie Center, Princeton, New Jersey   08540
(Address of principal executive offices)   (Zip Code)
(609) 524-4500
(Registrant’s telephone number, including area code)
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ      No o
     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes þ     No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o     No þ
     Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
Yes þ     No o
     As of July 29, 2010, there were 253,184,870 shares of common stock outstanding, par value $0.01 per share.
 
 

 


 

TABLE OF CONTENTS
Index
         
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 EX-10.3
 EX-10.4
 EX-31.1
 EX-31.2
 EX-31.3
 EX-32

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CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
     This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The words “believes,” “projects,” “anticipates,” “plans,” “expects,” “intends,” “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause NRG’s actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risks Factors Related to NRG Energy, Inc. in Part I, Item 1A, of the Company’s Annual Report on Form 10-K, for the year ended December 31, 2009, including the following:
    General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;
 
    Volatile power supply costs and demand for power;
 
   
Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;
 
   
The effectiveness of NRG’s risk management policies and procedures, and the ability of NRG’s counterparties to satisfy their financial commitments;
 
    Counterparties’ collateral demands and other factors affecting NRG’s liquidity position and financial condition;
 
   
NRG’s ability to operate its businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
 
    NRG’s ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;
 
    The liquidity and competitiveness of wholesale markets for energy commodities;
 
   
Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other greenhouse gas emissions;
 
   
Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately compensate NRG’s generation units for all of its costs;
 
   
NRG’s ability to borrow additional funds and access capital markets, as well as NRG’s substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;
 
   
Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG’s outstanding notes, in NRG’s Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;
 
   
NRG’s ability to implement its RepoweringNRG strategy of developing and building new power generation facilities, including new nuclear, wind and solar projects;
 
   
NRG’s ability to implement its econrg strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;
 
   
NRG’s ability to implement its FORNRG strategy of increasing the return on invested capital through operational performance improvements and a range of initiatives at plants and corporate offices to reduce costs or generate revenues;
 
    NRG’s ability to achieve its strategy of regularly returning capital to shareholders;
 
    Reliant Energy’s ability to maintain market share;
 
    NRG’s ability to successfully evaluate investments in new business and growth initiatives; and
 
    NRG’s ability to successfully integrate and manage acquired businesses.
     Forward-looking statements speak only as of the date they were made, and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.

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GLOSSARY OF TERMS
     When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
     
Baseload capacity
 
Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
 
   
BTU
  British Thermal Unit
 
   
CAA
  Clean Air Act
 
   
CAIR
  Clean Air Interstate Rule
 
   
CAISO
  California Independent System Operator
 
   
CATR
  Clean Air Transport Rule
 
   
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
 
   
C&I
  Commercial, industrial and governmental/institutional
 
   
CFTC
  U.S. Commodity Futures Trading Commission
 
   
CO2
  Carbon dioxide
 
   
CPS
  CPS Energy
 
   
CSF Debt
 
CSF I and CSF II issued notes and preferred interest, individually referred to as CSF I Debt and CSF II Debt
 
   
CSRA
 
Credit Sleeve Reimbursement Agreement with Merrill Lynch in connection with acquisition of Reliant Energy, as hereinafter defined
 
   
CSRA Amendment
  Amendment of the existing CSRA with Merrill Lynch which became effective October 5, 2009
 
   
DNREC
  Delaware Department of Natural Resources and Environmental Control
 
   
ERCOT
 
Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
 
   
Exchange Act
  The Securities Exchange Act of 1934, as amended
 
   
Expected Baseload Generation
 
The net baseload generation limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages)
 
   
FASB
 
Financial Accounting Standards Board — the designated organization for establishing standards for financial accounting and reporting
 
   
FERC
  Federal Energy Regulatory Commission
 
   
Funded Letter of Credit Facility
 
NRG’s $1.3 billion term loan-backed fully funded senior secured letter of credit facility, of which $500 million matures on February 1, 2013, and $800 million matures on August 31, 2015, and is a component of NRG’s Senior Credit Facility
 
   
GHG
  Greenhouse Gases
 
   
GWh
  Gigawatt hour
 
   
IGCC
  Integrated Gasification Combined Cycle
 
   
ISO
 
Independent System Operator, also referred to as Regional Transmission Organizations, or RTO
 
   
ISO-NE
  ISO New England Inc.
 
   
kV
  Kilovolts
 
   
kW
  Kilowatts

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kWh
  Kilowatt-hours
 
   
LIBOR
  London Inter-Bank Offer Rate
 
   
LTIP
  Long-Term Incentive Plan
 
   
MACT
  Maximum Achievable Control Technology
 
   
Mass
  Residential and small business
 
   
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
 
   
MW
  Megawatts
 
   
MWh
  Saleable megawatt hours net of internal/parasitic load megawatt-hours
 
   
NAAQS
  National Ambient Air Quality Standards
 
   
NINA
  Nuclear Innovation North America LLC
 
   
NOx
  Nitrogen oxide
 
   
NPNS
  Normal Purchase Normal Sale
 
   
NRC
  U.S. Nuclear Regulatory Commission
 
   
NYISO
  New York Independent System Operator
 
   
OCI
  Other comprehensive income
 
   
Phase II 316(b) Rule
  A section of the Clean Water Act regulating cooling water intake structures
 
   
PJM
  PJM Interconnection, LLC
 
   
PJM market
 
The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia
 
   
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
 
   
RERH
  RERH Holding, LLC and its subsidiaries
 
   
Revolving Credit Facility
 
NRG’s $875 million senior secured revolving credit facility, which matures on August 31, 2015, and is a component of NRG’s Senior Credit Facility
 
   
RGGI
  Regional Greenhouse Gas Initiative
 
   
RMR
  Reliability Must-Run
 
   
ROIC
  Return on invested capital
 
   
RRI
  RRI Energy, Inc. (formerly Reliant Energy, Inc.)
 
   
Sarbanes-Oxley
  Sarbanes-Oxley Act of 2002, as amended
 
   
SEC
  United States Securities and Exchange Commission

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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, an $875 million Revolving Credit Facility and a $1.3 billion Funded Letter of Credit Facility
 
   
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
 
   
SO2
  Sulfur dioxide
 
   
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
 
   
TANE
  Toshiba America Nuclear Energy Corporation
 
   
TANE Facility
 
NINA’s $500 million credit facility with TANE which matures on February 24, 2012
 
   
TEPCO
  The Tokyo Electric Power Company of Japan, Inc.
 
   
Term Loan Facility
 
A senior first priority secured term loan, of which approximately $975 million matures on February 1, 2013 and $1.0 billion matures on August 31, 2015, and is a component of NRG’s Senior Credit Facility
 
   
TNEA
  TEPCO Nuclear Energy America LLC
 
   
Tonnes
  Metric tonnes, which are units of mass or weight in the metric system each equal to 2,205lbs and are the global measurement for GHG
 
   
TWh
  Terawatt hour
 
   
U.S.
  United States of America
 
   
U.S. DOE
  United States Department of Energy
 
   
U.S. EPA
  United States Environmental Protection Agency
 
   
U.S. GAAP
  Accounting principles generally accepted in the United States
 
   
VaR
  Value at Risk

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ACCOUNTING PRONOUNCEMENTS
     The FASB has established the FASB Accounting Standards Codification, or ASC, as the source of authoritative U.S. GAAP. The FASB issues updates to the ASC through Accounting Standards Updates, or ASUs. The following ASC topics and ASUs are referenced in this report:
     
ASC 280
  ASC-280, Segment Reporting
 
   
ASC 450
  ASC-450, Contingencies
 
   
ASC 740
  ASC-740, Income Taxes
 
   
ASC 805
  ASC-805, Business Combinations
 
   
ASC 810
  ASC-810, Consolidation
 
   
ASC 815
  ASC-815, Derivatives and Hedging
 
   
ASC 820
  ASC-820, Fair Value Measurements and Disclosures
 
   
ASC 980
  ASC-980, Regulated Operations
 
   
ASU 2009-15
  ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing
 
   
ASU 2009-17
  ASU No. 2009-17, Consolidations: Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities
 
   
ASU 2010-02
  ASU No. 2010-02, Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary—a Scope Clarification
 
   
ASU 2010-06
  ASU No. 2010-06, Fair Value Measurement and Disclosures: Improving Disclosures about Fair Value Measurements
 
   
ASU 2010-09
  ASU No. 2010-09, Subsequent Events (Topic 815): Amendments to Certain Recognition and Disclosure Requirements
 
   
ASU 2010-10
  ASU No. 2010-10, Consolidation (Topic 810): Amendments for Certain Investment Funds

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PART I — FINANCIAL INFORMATION
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
                                 
    Three months ended June 30,   Six months ended June 30,
(In millions, except for per share amounts)   2010   2009   2010   2009
 
Operating Revenues
                               
Total operating revenues
  $ 2,133     $ 2,237     $ 4,348     $ 3,895  
 
Operating Costs and Expenses
                               
Cost of operations
    1,329       1,242       2,968       2,008  
Depreciation and amortization
    208       213       410       382  
Selling, general and administrative
    139       131       269       214  
Acquisition-related transaction and integration costs
          23             35  
Development costs
    13       9       22       22  
 
Total operating costs and expenses
    1,689       1,618       3,669       2,661  
Gain on sale of assets
                23        
 
Operating Income
    444       619       702       1,234  
 
Other Income/(Expense)
                               
Equity in earnings of unconsolidated affiliates
    11       5       25       27  
Gain on sale of equity method investment
          128             128  
Other income/(expense), net
    19       (11 )     23       (14 )
Interest expense
    (147 )     (159 )     (300 )     (297 )
 
Total other expense
    (117 )     (37 )     (252 )     (156 )
 
Income Before Income Taxes
    327       582       450       1,078  
Income tax expense
    117       150       182       448  
 
Net Income
    210       432       268       630  
Less: Net loss attributable to noncontrolling interest
    (1 )     (1 )     (1 )     (1 )
 
Net income attributable to NRG Energy, Inc.
    211       433       269       631  
 
Dividends for preferred shares
    3       7       5       21  
 
Income Available for NRG Energy, Inc. Common Stockholders
  $ 208     $ 426     $ 264     $ 610  
 
Earnings per share attributable to NRG Energy, Inc. Common Stockholders
                               
Weighted average number of common shares outstanding — basic
    255       253       254       245  
Net Income per Weighted Average Common Share — basic
  $ 0.82     $ 1.68     $ 1.04     $ 2.49  
Weighted average number of common shares outstanding — diluted
    256       275       256       275  
Net Income per Weighted Average Common Share — diluted
  $ 0.81     $ 1.56     $ 1.03     $ 2.27  
 
See notes to condensed consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
                 
    June 30, 2010   December 31, 2009
(In millions, except shares)   (unaudited)        
 
ASSETS
               
Current Assets
               
Cash and cash equivalents
  $ 2,168     $ 2,304  
Funds deposited by counterparties
    310       177  
Restricted cash
    13       2  
Accounts receivable — trade, less allowance for doubtful accounts of $21 and $29, respectively
    909       876  
Inventory
    535       541  
Derivative instruments valuation
    1,800       1,636  
Cash collateral paid in support of energy risk management activities
    391       361  
Prepayments and other current assets
    243       311  
 
Total current assets
    6,369       6,208  
 
Property, plant and equipment, net of accumulated depreciation of $3,414 and $3,052, respectively
    11,793       11,564  
 
Other Assets
               
Equity investments in affiliates
    394       409  
Note receivable — affiliate and capital leases, less current portion
    434       504  
Goodwill
    1,716       1,718  
Intangible assets, net of accumulated amortization of $862 and $648, respectively
    1,626       1,777  
Nuclear decommissioning trust fund
    360       367  
Derivative instruments valuation
    910       683  
Restricted cash supporting funded letter of credit facility
    1,300        
Other non-current assets
    201       148  
 
Total other assets
    6,941       5,606  
 
Total Assets
  $ 25,103     $ 23,378  
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current Liabilities
               
Current portion of long-term debt and capital leases
  $ 179     $ 571  
Accounts payable
    690       697  
Derivative instruments valuation
    1,484       1,473  
Deferred income taxes
    244       197  
Cash collateral received in support of energy risk management activities
    310       177  
Accrued expenses and other current liabilities
    623       647  
 
Total current liabilities
    3,530       3,762  
 
Other Liabilities
               
Long-term debt and capital leases
    7,991       7,847  
Funded letter of credit
    1,300        
Nuclear decommissioning reserve
    309       300  
Nuclear decommissioning trust liability
    234       255  
Deferred income taxes
    1,768       1,783  
Derivative instruments valuation
    433       387  
Out-of-market contracts
    258       294  
Other non-current liabilities
    1,002       806  
 
Total non-current liabilities
    13,295       11,672  
 
Total Liabilities
    16,825       15,434  
 
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)
    248       247  
Commitments and Contingencies
               
Stockholders’ Equity
               
Preferred stock (at liquidation value, net of issuance costs)
          149  
Common stock
    3       3  
Additional paid-in capital
    5,311       4,948  
Retained earnings
    3,596       3,332  
Less treasury stock, at cost — 50,625,606 and 41,866,451 shares, respectively
    (1,373 )     (1,163 )
Accumulated other comprehensive income
    476       416  
Noncontrolling interest
    17       12  
 
Total Stockholders’ Equity
    8,030       7,697  
 
Total Liabilities and Stockholders’ Equity
  $ 25,103     $ 23,378  
 
See notes to condensed consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
(In millions)        
Six months ended June 30,   2010   2009
 
Cash Flows from Operating Activities
               
Net income
  $ 268     630  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Distributions and equity in earnings of unconsolidated affiliates
    (9 )     (27 )
Depreciation and amortization
    410       382  
Provision for bad debts
    22       9  
Amortization of nuclear fuel
    19       19  
Amortization of financing costs and debt discount/premiums
    15       21  
Amortization of intangibles and out-of-market contracts
    1       15  
Changes in deferred income taxes and liability for unrecognized tax benefits
    179       445  
Changes in nuclear decommissioning trust liability
    9       15  
Changes in derivatives
    (55 )     (368 )
Changes in collateral deposits supporting energy risk management activities
    (30 )     245  
Gain on sale of assets, net
    (11 )     (1 )
Gain on sale of equity method investment
          (128 )
Loss/(gain) on sale of emission allowances
    3       (9 )
Gain recognized on settlement of pre-existing relationship
          (31 )
Amortization of unearned equity compensation
    15       13  
Changes in option premiums collected, net of acquisition
    34       (270 )
Cash used by changes in other working capital, net of acquisition
    (265 )     (238 )
 
Net Cash Provided by Operating Activities
    605       722  
 
Cash Flows from Investing Activities
               
Acquisition of businesses, net of cash acquired
    (141 )     (345 )
Capital expenditures
    (330 )     (374 )
Increase in restricted cash, net
    (11 )     (3 )
Decrease/(increase) in notes receivable
    15       (11 )
Purchases of emission allowances
    (45 )     (52 )
Proceeds from sale of emission allowances
    11       15  
Investments in nuclear decommissioning trust fund securities
    (76 )     (172 )
Proceeds from sales of nuclear decommissioning trust fund securities
    67       157  
Proceeds from renewable energy grants
    102        
Proceeds from sale of assets, net
    30       6  
Proceeds from sale of equity method investment
          284  
Other
    (7 )     (5 )
 
Net Cash Used by Investing Activities
    (385 )     (500 )
 
Cash Flows from Financing Activities
               
Payment of dividends to preferred stockholders
    (5 )     (21 )
Payment for treasury stock
    (50 )      
Net receipt from/(payments for) acquired derivatives that include financing elements
    27       (22 )
Installment proceeds from sale of noncontrolling interest in subsidiary
    50       50  
Proceeds from issuance of long-term debt
    141       820  
Proceeds from issuance of term loan for funded letter of credit facility
    1,300        
Increase in restricted cash supporting funded letter of credit facility
    (1,300 )      
Proceeds from issuance of common stock
    2        
Payment of deferred debt issuance costs
    (53 )     (29 )
Payments for short and long-term debt
    (459 )     (233 )
 
Net Cash (Used)/Provided by Financing Activities
    (347 )     565  
 
Effect of exchange rate changes on cash and cash equivalents
    (9 )     1  
 
Net (Decrease)/Increase in Cash and Cash Equivalents
    (136 )     788  
Cash and Cash Equivalents at Beginning of Period
    2,304       1,494  
 
Cash and Cash Equivalents at End of Period
  $ 2,168     2,282  
 
See notes to condensed consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 — Basis of Presentation
     NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company with a significant presence in major competitive power markets in the United States, as well as a major retail electricity provider in the ERCOT (Texas) market. NRG is engaged in the ownership, development, construction and operation of power generation facilities, both conventional and renewable, 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 Company also seeks to invest in and deploy new energy technologies.
     The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC’s regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The 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, 2009. 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 June 30, 2010, the results of operations for the three and six months ended June 30, 2010, and 2009, and cash flows for the six months ended June 30, 2010 and 2009. Certain prior-year amounts have been reclassified for comparative purposes.
Use of Estimates
     The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions impact the reported amount of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the consolidated financial statements. They also impact the reported amount of net earnings during the reporting period. Actual results could be different from these estimates.
Note 2 — Summary of Significant Accounting Policies
Other Cash Flow Information
     NRG’s investing activities do not include non-cash capital expenditures of $113 million which were accrued at June 30, 2010.
Recent Accounting Developments
     ASU No. 2009-17 — On January 1, 2010, the Company adopted the provisions of ASU No. 2009-17, Consolidations: Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities, or ASU 2009-17. This guidance amends ASC 810 by altering how a company determines when an entity that is insufficiently capitalized or not controlled through its voting interests should be consolidated. The previous ASC 810 guidance required a quantitative analysis of the economic risk/rewards of a Variable Interest Entity, or a VIE, to determine the primary beneficiary. ASU 2009-17 specifies that a qualitative analysis be performed, requiring the primary beneficiary to have both the power to direct the activities of a VIE that most significantly impact the entities’ economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. The Company’s adoption of ASU 2009-17 on January 1, 2010, did not have an impact on its results of operations, financial position or cash flows.
     ASU No. 2010-10 — In February 2010, the FASB issued ASU No. 2010-10, Consolidation (Topic 810): Amendments for Certain Investment Funds, or ASU 2010-10. The amendments to ASC 810 clarify that related parties should be considered when evaluating the criteria for determining whether a decision maker’s or service provider’s fee represents a variable interest. In addition, the amendments clarify that a quantitative calculation should not be the sole basis for evaluating whether a decision maker’s or service provider’s fee represents a variable interest. The Company adopted the provisions of ASU 2010-10 effective January 1, 2010, with no impact on its results of operations, financial position or cash flows.

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     Other effects of ASU 2009-17/ASU 2010-10 adoption — NRG determined that one of its equity method investments was a VIE as of January 1, 2010, upon adoption of this new guidance. NRG owns a 50% interest in Sherbino I Wind Farm LLC, or Sherbino, a 150MW wind farm operated as a joint venture with BP Wind Energy North America Inc., or BP Wind. The Company has determined that Sherbino is a VIE, but the Company is not the primary beneficiary, under the amended guidance in ASU 2009-17 and ASU 2010-10. Therefore, NRG will continue to account for its investment in Sherbino under the equity method. NRG’s maximum exposure to loss is limited to its equity investment, which is $94 million as of June 30, 2010.
     Borrowings of an equity method investment – In December 2008, Sherbino entered into a 15-year term loan facility which is non-recourse to NRG. As of June 30, 2010, the outstanding principal balance of the term loan facility was $131 million, and is secured by substantially all of Sherbino’s assets and membership interests.
     ASU No. 2010-09 — In February 2010, the FASB issued ASU No. 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements, or ASU 2010-09. Under the amendments of ASU 2010-09, an entity that is an SEC filer is not required to disclose the date through which subsequent events have been evaluated. As this guidance provides only disclosure requirements, the adoption of ASU 2010-09 effective January 1, 2010, did not impact the Company’s results of operations, financial position or cash flows.
     Other — The following accounting standards were adopted on January 1, 2010, with no impact on the Company’s results of operations, financial position or cash flows:
   
ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, or ASU 2009-15.
   
ASU No. 2010-02, Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary—a Scope Clarification, or ASU 2010-02.
   
ASU No. 2010-06, Fair Value Measurement and Disclosures: Improving Disclosures about Fair Value Measurements, or ASU 2010-06.
Note 3 — 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)   2010   2009   2010   2009
 
Net income attributable to NRG Energy, Inc.
  $ 211     $ 433     $ 269     $ 631  
 
Changes in derivative activity
    (154 )     (109 )     103       64  
Foreign currency translation adjustment
    (36 )     36       (42 )     18  
Reclassification adjustment for translation gain realized upon sale of foreign investments
          (22 )           (22 )
Unrealized (loss)/gain on available-for-sale securities
    (1 )     1       (1 )     2  
 
Other comprehensive (loss)/income
    (191 )     (94 )     60       62  
 
Comprehensive income attributable to NRG Energy, Inc.
  $ 20     $ 339     $ 329     $ 693  
 
     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, 2009
  $ 416  
Changes in derivative activity
    103  
Foreign currency translation adjustment
    (42 )
Unrealized loss on available-for-sale securities
    (1 )
 
Accumulated other comprehensive income as of June 30, 2010
  $ 476  
 

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Note 4 — Business Acquisitions and Dispositions
Acquisition of Reliant Energy
     On May 1, 2009, NRG, through its wholly-owned subsidiary, NRG Retail LLC, acquired Reliant Energy from RRI Energy, Inc., or RRI, which consisted of the entire Texas electric retail business operations of RRI, including the exclusive use of the trade name “Reliant” and related branding rights. The acquisition of Reliant Energy was accounted for under the acquisition method of accounting in accordance with ASC 805. Accordingly, NRG conducted an assessment of net assets acquired and recognized identifiable assets acquired and liabilities assumed at their acquisition date fair values. The accounting for this business combination was completed on March 31, 2010.
     NRG paid RRI total cash consideration of approximately $370 million. NRG also recognized a $31 million non-cash gain at the acquisition date, 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. This non-cash gain was considered a component of consideration in accordance with ASC 805, and together with cash consideration, brings total consideration to approximately $401 million.
     The following table summarizes the values assigned to the net assets acquired, including cash acquired of $6 million, as of the acquisition date:
         
    (In millions)
Assets
       
Current and non-current assets
  $ 635  
Property, plant and equipment
    72  
Intangible assets subject to amortization:
       
In-market customer contracts
    790  
Customer relationships
    405  
Trade names
    178  
In-market energy supply contracts
    54  
Other
    6  
Derivative assets
    1,942  
Deferred tax asset, net
    14  
Goodwill
     
 
Total assets acquired
  $ 4,096  
 
Liabilities
       
Current and non-current liabilities
  $ 556  
Derivative liabilities
    2,996  
Out-of-market energy supply and customer contracts
    143  
 
Total liabilities assumed
  $ 3,695  
 
Net assets acquired
  $ 401  
 

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Measurement period adjustments
     The following measurement period adjustments to the provisional amounts, attributable to refinement of the underlying appraisal assumptions, were recognized during 2009 subsequent to the acquisition date and through the first quarter of 2010, the end of the measurement period:
         
    Increase/(Decrease)
    (In millions)
Assets
       
Intangible assets subject to amortization:
       
In-market customer contracts
  $ 57  
Customer relationships
    (76 )
In-market energy supply contracts
    17  
Deferred tax asset, net
    3  
 
Total assets acquired
    1  
 
Liabilities
       
Current and non-current liabilities
    6  
Out-of-market energy supply and customer contracts
    (5 )
 
Total liabilities assumed
    1  
 
Net assets acquired
  $  
 
Other Acquisitions
     Northwind Phoenix — On June 22, 2010, NRG, through its wholly-owned subsidiary, NRG Thermal LLC, or NRG Thermal, acquired Northwind Phoenix, LLC, or Northwind Phoenix, for a total purchase price of $100 million, plus a payment for acquired working capital true-ups. Northwind Phoenix owns and operates a district cooling system that provides chilled water to commercial buildings in the Phoenix central business district. In addition, Northwind Phoenix maintains and operates Combined Heat and Power, or CHP, plants that provide chilled water, steam and electricity in metropolitan Tucson and to portions of Arizona State University campuses in Tempe and Mesa. The acquisition was financed by the issuance of $100 million in notes by NRG Thermal. See Note 8, Long-Term Debt, for information related to the notes issued.
     South Trent — On June 14, 2010, NRG acquired South Trent Wind LLC, owner of the South Trent wind farm, or South Trent, a 101 MW wind farm near Sweetwater, Texas, for a total purchase price of $111 million. South Trent commenced operations in January 2009 and consists of 44 turbines producing up to 2.3 MW of power each. The project has a 20-year PPA, which commenced January 2009, for all generation from the site. In connection with the acquisition, NRG paid $32 million in cash and South Trent entered into a financing arrangement that includes a $79 million term loan. See Note 8, Long-Term Debt, for information related to this financing arrangement.
Dispositions
     Padoma — On January 11, 2010, NRG sold its terrestrial wind development company, Padoma Wind Power LLC, or Padoma, to Enel North America, Inc., or Enel. NRG retained its existing ownership interest in its three Texas wind farms: Sherbino, Elbow Creek and Langford. In addition, NRG will maintain a strategic partnership with Enel to evaluate potential opportunities in renewable energy, including the opportunity to participate in wind projects currently in development. NRG recognized a gain on the sale of Padoma of $23 million, which was recorded as a component of operating income in the statement of operations.
     MIBRAG — On June 10, 2009, NRG sold its 50% ownership interest in Mibrag B.V. whose principal holding was MIBRAG. For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40 U.S.$/EUR), net of transaction costs. During the three and six months ended June 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. For the three and six months ended June 30, 2009, NRG recorded an exchange loss of $15 million and $24 million, respectively, on the contract within Other income/(expense), net.

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Note 5 — 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
            December 31,           December 31,
    June 30, 2010   2009   June 30, 2010   2009
            (In millions)        
Assets:
                               
Cash and cash equivalents
  $ 2,168     $ 2,304     $ 2,168     $ 2,304  
Funds deposited by counterparties
    310       177       310       177  
Restricted cash
    13       2       13       2  
Cash collateral paid in support of energy risk management activities
    391       361       391       361  
Investment in available-for-sale securities (classified within other non-current assets):
                               
Debt securities
    10       9       10       9  
Marketable equity securities
    3       5       3       5  
Trust fund investments
    362       369       362       369  
Notes receivable
    221       231       232       238  
Derivative assets
    2,710       2,319       2,710       2,319  
Restricted cash supporting funded letter of credit facility
    1,300             1,300        
Liabilities:
                               
Long-term debt, including current portion
    8,069       8,295       7,991       8,211  
Funded letter of credit
    1,300             1,250        
Cash collateral received in support of energy risk management activities
    310       177       310       177  
Derivative liabilities
  $ 1,917     $ 1,860     $ 1,917     $ 1,860  
 

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Recurring Fair Value Measurements
     The following table presents assets and liabilities measured and recorded at fair value on the Company’s condensed consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:
                                 
(In millions)   Fair Value
As of June 30, 2010   Level 1   Level 2   Level 3   Total
 
Cash and cash equivalents
  $ 2,168     $     $     $ 2,168  
Funds deposited by counterparties
    310                   310  
Restricted cash
    13                   13  
Cash collateral paid in support of energy risk management activities
    391                   391  
Investment in available-for-sale securities (classified within other non-current assets):
                               
Debt securities
                10       10  
Marketable equity securities
    3                   3  
Trust fund investments
                               
Cash and cash equivalents
    9                   9  
U.S. government and federal agency obligations
    27                   27  
Federal agency mortgage-backed securities
          61             61  
Commercial mortgage-backed securities
          10             10  
Corporate debt securities
          50             50  
Marketable equity securities
    172             32       204  
Foreign government fixed income securities
          1             1  
Derivative assets
                               
Commodity contracts
    629       2,005       65       2,699  
Interest rate contracts
                11       11  
Restricted cash supporting funded letter of credit facility
    1,300                   1,300  
 
Total assets
  $ 5,022     $ 2,127     $ 118     $ 7,267  
 
 
                               
Cash collateral received in support of energy risk management activities
  $ 310     $     $     $ 310  
Derivative liabilities
                               
Commodity contracts
    681       967       152       1,800  
Interest rate contracts
          117             117  
 
Total liabilities
  $ 991     $ 1,084     $ 152     $ 2,227  
 
                                 
(In millions)   Fair Value
As of December 31, 2009   Level 1   Level 2   Level 3   Total
 
Cash and cash equivalents
  $ 2,304     $     $     $ 2,304  
Funds deposited by counterparties
    177                   177  
Restricted cash
    2                   2  
Cash collateral paid in support of energy risk management activities
    361                   361  
Investment in available-for-sale securities (classified within other non-current assets):
                               
Debt securities
                9       9  
Marketable equity securities
    5                   5  
Trust fund investments
    214       118       37       369  
Derivative assets
    489       1,767       63       2,319  
 
Total assets
  $ 3,552     $ 1,885     $ 109     $ 5,546  
 
Cash collateral received in support of energy risk management activities
  $ 177     $     $     $ 177  
Derivative liabilities
    501       1,283       76       1,860  
 
Total liabilities
  $ 678     $ 1,283     $ 76     $ 2,037  
 

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     There have been no transfers during the three months and six months ended June 30, 2010, between Levels 1 and 2. The following table reconciles the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements using significant unobservable inputs:
                                                                 
    Three months ended June 30, 2010   Six months ended June 30, 2010
    Debt   Trust Fund                   Debt   Trust Fund        
(In millions)   Securities   Investments   Derivatives(a)   Total   Securities   Investments   Derivatives(a)   Total
 
Beginning Balance
  $ 9     $ 37     $ (25 )   $ 21     $ 9     $ 37     $ (13 )   $ 33  
Total gains/(losses) (realized and unrealized)
                                                               
Included in earnings
                (63 )     (63 )                 (31 )     (31 )
Included in OCI
    1                   1       1                   1  
Included in nuclear decommissioning obligations
          (5 )           (5 )           (5 )           (5 )
Purchases
                8       8                   9       9  
Transfer into Level 3 (b)
                15       15                   (47 )     (47 )
Transfer out of Level 3 (b)
                (11 )     (11 )                 6       6  
 
Ending balance as of June 30, 2010
  $ 10     $ 32     $ (76 )   $ (34 )   $ 10     $ 32     $ (76 )   $ (34 )
 
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, 2010
  $     $     $ (61 )   $ (61 )   $     $     $ (36 )   $ (36 )
 
                                                                 
    Three months ended June 30, 2009   Six months ended June 30, 2009
    Debt   Trust Fund                   Debt   Trust Fund        
(In millions)   Securities   Investments   Derivatives(a)   Total   Securities   Investments   Derivatives(a)   Total
 
Beginning Balance
  $ 7     $ 27     $ 126     $ 160     $ 7     $ 31     $ 49     $ 87  
Total gains/(losses) (realized and unrealized)
                                                               
Included in earnings
                (49 )     (49 )                 (30 )     (30 )
Included in nuclear decommissioning obligations
          6             6             2             2  
Purchases/(sales), net
          1       (8 )     (7 )           1       (4 )     (3 )
Transfer in/(out) of Level 3 (b)
                (19 )     (19 )                 35       35  
 
Ending balance as of June 30, 2009
  $ 7     $ 34     $ 50     $ 91     $ 7     $ 34     $ 50     $ 91  
 
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
  $     $     $ (1 )   $ (1 )   $     $     $ 28     $ 28  
 
(a)   Consists of derivative assets and liabilities, net.
 
(b)   Transfers in/(out) of Level 3 are related to the availability of external broker quotes. All transfers out are to Level 2.
     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 June 30, 2010, the credit reserve resulted in an $11 million decrease in fair value which is composed of a $6 million loss in OCI and a $5 million loss in operating revenue and cost of operations.
   Concentration of Credit Risk
     In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2009, the following item is a discussion of the concentration of credit risk for the Company’s financial instruments. 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. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply and retail customer credit risk through its retail load activities.
     Counterparty Credit Risk
     The Company monitors and manages counterparty 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, prepayment arrangements, or volumetric limits; (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 credit risk with a diversified portfolio of counterparties. 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.

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     As of June 30, 2010, total counterparty credit exposure to substantially all counterparties was $1.5 billion and NRG held cash collateral against those positions of $310 million and letters of credit of $11 million, resulting in a net exposure of $1.2 billion. Total counterparty credit exposure is discounted at the risk free rate.
     The following table highlights the counterparty 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 Normal Sale, or NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.
         
    Net Exposure(a)
Category   (% of Total)
 
Financial institutions
    59 %
Utilities, energy, merchants, marketers and other
    31  
Coal suppliers
    4  
ISOs
    6  
 
Total as of June 30, 2010
    100 %
 
         
    Net Exposure(a)
Category   (% of Total)
 
Investment grade
    88 %
Non-Investment grade
    2  
Non-rated
    10  
 
Total as of June 30, 2010
    100 %
 
(a)  
Counterparty credit exposure excludes California tolling, Northeast load obligations, certain 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. NRG also excludes uranium and coal transportation contracts from counterparty credit exposure because of the illiquidity of the reference markets. Credit exposure also excludes any exposure NRG has to counterparties of non-recourse subsidiaries.
     NRG has counterparty credit risk exposure to certain counterparties representing more than 10% of total net exposure and the aggregate of such counterparties was $409 million. Approximately 89% of NRG’s positions relating to credit risk roll-off by the end of 2012. 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 or results of operations from nonperformance by any of NRG’s counterparties.
   Retail Customer Credit Risk
     NRG is exposed to retail credit risk through the Company’s competitive electricity supply business, which serves C&I customers and the Mass market in Texas. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.
     As of June 30, 2010, the Company’s retail customer credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.
     NRG is also exposed to retail customer credit risk relating to its Mass customers, which may result in a write-off of bad debt. During 2010, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the Company’s customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.
     This footnote should be read in conjunction with the complete description under Note 5, Fair Value of Financial Instruments, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2009.

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Note 6 — Nuclear Decommissioning Trust Fund
     NRG’s nuclear decommissioning trust fund assets, which are for its portion of the decommissioning of the South Texas Project, or STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the nuclear decommissioning trust fund in accordance with ASC-980 — Regulated Operations, or ASC 980. Since the Company is in compliance with the Public Utility Commission of Texas, or PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other than-temporary-impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.
     The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds as of June 30, 2010, and December 31, 2009, as well as information about the contractual maturities of those securities. The cost of securities sold is determined on the specific identification method.
                                                                 
    As of June 30, 2010   As of December 31, 2009
                            Weighted-                           Weighted-
                            average                           average
    Fair   Unrealized   Unrealized   maturities   Fair   Unrealized   Unrealized   maturities
(In millions, except otherwise noted)   Value   gains   losses   (in years)   Value   gains   losses   (in years)
 
Cash and cash equivalents
  $ 9     $     $           $ 4     $     $        
U.S. government and federal agency obligations
    25       2             11       23       1             8  
Federal agency mortgage-backed securities
    61       3             22       60       2             23  
Commercial mortgage-backed securities
    10             1       30       10             1       29  
Corporate debt securities
    50       3             10       48       3       1       10  
Marketable equity securities
    204       73       3             220       89       2        
Foreign government fixed income securities
    1                   7       2                   6  
 
Total
  $ 360     $ 81     $ 4             $ 367     $ 95     $ 4          
 
     The following tables summarize proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales.
                 
    Six months ended June 30,
(In millions)   2010   2009
 
Realized gains
  $ 2     $ 2  
Realized losses
    2       5  
Proceeds from sale of securities
    67       157  
 

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Note 7 — Accounting for Derivative Instruments and Hedging Activities
     ASC 815 requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a 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 accumulated 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.
     For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established per ASC 815, certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG’s energy related commodity contracts, interest rate swaps, and foreign exchange contracts.
     As the Company engages principally in the trading and marketing of its generation assets and retail business, some of NRG’s commercial activities qualify for hedge accounting under the requirements of ASC 815. In order for the generation assets to qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company’s baseload plants. For this reason, many trades in support of NRG’s baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG’s peaking unit’s asset optimization 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 subject to limits within the Company’s Risk Management Policy.
Energy-Related Commodities
     To manage the commodity price risk associated with the Company’s competitive supply activities and the price risk associated with wholesale and retail power sales from the Company’s electric generation facilities, NRG may enter into a variety of derivative and non-derivative hedging instruments, utilizing the following:
    Forward contracts, which commit NRG to sell or purchase energy commodities or purchase fuels in the future.
    Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument.
    Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity.
    Option contracts, which convey the right or obligation to purchase or sell a commodity.
    Weather and hurricane derivative products used to mitigate a portion of Reliant Energy’s lost revenue due to weather.
     The objectives for entering into derivative contracts designated as hedges include:
    Fixing the price for a portion of anticipated future electricity sales through the use of various derivative instruments including gas collars and swaps at a level that provides an acceptable return on the Company’s electric generation operations.
    Fixing the price of a portion of anticipated fuel purchases for the operation of NRG’s power plants.
     As of June 30, 2010, NRG had cash flow hedge energy-related derivative financial instruments extending through December 2013.
     NRG’s trading activities are subject to limits within 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.

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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 June 30, 2010, NRG had interest rate derivative instruments extending through June 2028, the majority 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 open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of June 30, 2010, and December 31, 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
        June 30, 2010   December 31, 2009
Commodity   Units   (In millions)
 
Emissions
  Short Ton     (7 )     (2 )
Coal
  Short Ton     42       55  
Natural Gas
  MMBtu     (299 )     (484 )
Oil
  Barrel           1  
Power
  MWh     11       5  
Capacity
  MW/Day     (3 )     (2 )
Interest
  Dollars   $ 3,203     $ 3,291  
 
Fair Value of Derivative Instruments
     The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company’s derivative assets or liabilities are recorded on a separate line item on the balance sheet. The Company has chosen not to offset positions as permitted in ASC 815. As of June 30, 2010, the Company recorded $391 million of cash collateral paid and $310 million of cash collateral received on its balance sheet.
     The following table summarizes the fair value within the derivative instrument valuation on the balance sheet as of June 30, 2010, and December 31, 2009:
                                 
    Fair Value
    Derivative Assets   Derivative Liabilities
    June 30,   December 31,   June 30,   December 31,
(In millions)   2010   2009   2010   2009
 
Derivatives Designated as Cash Flow or Fair Value Hedges:
                               
Interest rate contracts current
  $     $     $ 48     $ 2  
Interest rate contracts long-term
    11       8       69       106  
Commodity contracts current
    370       300       8       12  
Commodity contracts long-term
    511       508       1       6  
 
Total Derivatives Designated as Cash Flow or Fair Value Hedges
    892       816       126       126  
 
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
                               
Commodity contracts current
    1,430       1,336       1,428       1,459  
Commodity contracts long-term
    388       167       363       275  
 
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges
    1,818       1,503       1,791       1,734  
 
Total Derivatives
  $ 2,710     $ 2,319     $ 1,917     $ 1,860  
 

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Accumulated Other Comprehensive Income
     The following table summarizes the effects of ASC 815 on NRG’s Accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:
                                                 
    Three months ended June 30, 2010   Six months ended June 30, 2010
    Energy   Interest           Energy   Interest    
(In millions)   Commodities   Rate   Total   Commodities   Rate   Total
 
Beginning Balance
  $ 719     $ (56 )   $ 663     $ 461     $ (55 )   $ 406  
Reclassified from Accumulated OCI to income:
                                               
- Due to realization of previously deferred amounts
    (128 )     (2 )     (130 )     (234 )           (234 )
Mark-to-market of cash flow hedge accounting contracts
    (16 )     (8 )     (24 )     348       (11 )     337  
 
Accumulated OCI balance at June 30, 2010, net of $308 tax
  $ 575     $ (66 )   $ 509     $ 575     $ (66 )   $ 509  
 
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $186 tax
  $ 348     $ (32 )   $ 316     $ 348     $ (32 )   $ 316  
 
(Losses)/gains recognized in income from the ineffective portion of cash flow hedges
  $ (12 )   $ 2     $ (10 )   $ (14 )   $ 2     $ (12 )
 
                                                 
    Three months ended June 30, 2009   Six months ended June 30, 2009
    Energy   Interest           Energy   Interest    
(In millions)   Commodities   Rate   Total   Commodities   Rate   Total
 
Beginning Balance
  $ 567     $ (79 )   $ 488     $ 406     $ (91 )   $ 315  
Reclassified from Accumulated OCI to income:
                                               
- Due to realization of previously deferred amounts
    (76 )     (1 )     (77 )     (188 )           (188 )
- Due to discontinuation of cash flow hedge accounting
                      (135 )           (135 )
Mark-to-market of cash flow hedge accounting contracts
    (46 )     14       (32 )     362       25       387  
 
Accumulated OCI balance at June 30, 2009, net of $233 tax
  $ 445     $ (66 )   $ 379     $ 445     $ (66 )   $ 379  
 
(Losses)/gains recognized in income from the ineffective portion of cash flow hedges
  $ (3 )   $     $ (3 )   $ 1     $     $ 1  
 
     Amounts reclassified from Accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts.
     Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of July 31, 2008, the Company’s regression analysis for natural gas prices to ERCOT power prices, while positively correlated, did not meet the required threshold for cash flow hedge accounting for calendar years 2012 and 2013. As a result, the Company de-designated its 2012 and 2013 ERCOT cash flow hedges as of July 31, 2008, and prospectively marked these derivatives to market. On April 1, 2009, the required correlation threshold for cash flow hedge accounting was achieved for these transactions, and accordingly, these hedges were re-designated as cash flow hedges.
     As discussed in Note 3, Business Acquisitions, to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2009, on October 5, 2009, the Company amended the CSRA with Merrill Lynch. In connection with the CSRA Amendment, NRG net settled certain in-the-money transactions with Morgan Stanley. As these transactions were net settled, $245 million in OCI was frozen and is recognized into income as the underlying power from the baseload plants is generated.
     The following table summarizes the amount of gain/(loss) resulting from fair value hedges reflected in interest income/(expense) for interest rate contracts:
                                 
    Three months ended June 30,   Six months ended June 30,
(In millions)   2010   2009   2010   2009
 
Derivative
  $     $ (7 )   $ 3     $ (8 )
Senior Notes (hedged item)
  $     $ 7     $ (3 )   $ 8  
 

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     Impact of Derivative Instruments on the Statement of Operations
     In accordance with ASC 815, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedge derivatives and ineffectiveness of hedge derivatives are reflected in current period earnings.
     The following table summarizes the pre-tax effects of economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activity on NRG’s statement of operations. These amounts are included within operating revenues and cost of operations.
                                 
    Three months ended June 30,   Six months ended June 30,
(In millions)   2010   2009   2010   2009
 
Unrealized mark-to-market results
                               
Reversal of previously recognized unrealized gains on settled positions related to economic hedges
  $ (51 )   $ (18 )   $ (91 )   $ (34 )
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009
    60       210       150       210  
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity
    8       (35 )     26       (104 )
Net unrealized gains/(losses) on open positions related to economic hedges
    48       (40 )     (70 )     309  
(Losses)/gains on ineffectiveness associated with open positions treated as cash flow hedges
    (12 )     (3 )     (14 )     1  
Net unrealized gains on open positions related to trading activity
    9       1       23       8  
 
Total unrealized gains
  $ 62     $ 115     $ 24     $ 390  
 
                                 
    Three months ended June 30,   Six months ended June 30,
(In millions)   2010   2009   2010   2009
 
Revenue from operations — energy commodities
  $ (83 )   $ (210 )   $ (14 )   $ 117  
Cost of operations
    145       325       38       273  
 
Total impact to statement of operations
  $ 62     $ 115     $ 24     $ 390  
 
     Reliant Energy’s loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and are reflected in the cost of operations during the same period.
     For the six months ended June 30, 2010, the $70 million loss from economic hedge positions is the result of a decrease in value of forward purchases and sales of natural gas, electricity and fuel due to a decrease in forward power and gas prices.
     For the six months ended June 30, 2009, the $309 million gain from economic hedge positions includes $217 million recognized in earnings from previously deferred amounts in Accumulated OCI as the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New York due to lower expected generation, and $92 million of increase in value of forward purchases and sales of electricity and fuel due to a decrease in forward power and gas prices.
     Discontinued Normal Purchase and Sale for Coal Purchases — Due to lower coal-fired generation during the first quarter 2009, the Company’s coal consumption was lower than forecasted. The Company net settled some of its coal purchases under NPNS designation and thus was not able to assert physical delivery under these coal contracts. The forward positions previously treated as accrual accounting were reclassified into mark-to-market accounting during the first quarter of 2009 and prospectively. The impact of discontinuance of coal NPNS designated transactions resulted in a derivative loss of $29 million that was reflected in the cost of operations for the six months ended June 30, 2009.

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     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, or require the Company to post additional collateral if there was a one notch downgrade in the Company’s credit rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of June 30, 2010, was $63 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of June 30, 2010, was $11 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $15 million as of June 30, 2010.
     See Note 5, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.
Note 8 — Long-Term Debt
     In March 2010, NRG made a repayment of approximately $229 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.
Amendment and Extension of Maturity Dates
     On June 30, 2010, NRG completed an amendment and extension of the Senior Credit Facility, resulting in the following:
   
NRG extended the maturity date for approximately $1.0 billion of its $2.0 billion outstanding Term Loan Facility to August 31, 2015, with the remaining amount due on the original maturity date of February 1, 2013. The interest rate for the extended portion of the facility increased from LIBOR+1.75% to LIBOR+3.25%;
   
Borrowing capacity under the Revolving Credit Facility was reduced from $1.0 billion to $875 million and its maturity was extended to August 31, 2015. The interest rate for the amended Revolving Credit Facility is LIBOR+3.25%;
   
The existing Synthetic Letter of Credit Facility was converted into a term loan-backed funded letter of credit facility, or Funded Letter of Credit Facility, with the term loan reflected as a non-current liability and the proceeds of the term loan reflected as non-current restricted cash on NRG’s balance sheet. Of the total $1.3 billion borrowed under the term loan, $500 million will mature on February 1, 2013 and bear interest at LIBOR+1.75%, while $800 million will mature August 31, 2015 and bear interest at LIBOR+3.25%.
     
Restricted cash supporting funded letter of credit — Pursuant to the letter of credit reimbursement agreements entered into as of June 30, 2010, or the LC Agreements, and the Senior Credit Facility, as amended, NRG made capital contributions to NRG LC Facility Company, or LCFC, a separate, bankruptcy-remote entity that is a wholly-owned subsidiary of NRG. In addition, pursuant to reimbursement agreements related to the LC Agreements, NRG or its subsidiaries is liable for certain reimbursement obligations to LCFC. As of June 30, 2010, LCFC has cash invested in short-term certificates of deposit with an aggregate market value of $1.3 billion. Pursuant to the LC Agreements, which have a maximum committed amount of $1.3 billion, LCFC is liable on various letters of credit issued by Deutsche Bank AG, New York Branch and Citibank, N.A. These letters of credit will be used to support the businesses of NRG and certain of its other subsidiaries and equity investments. LCFC has secured its reimbursement and other obligations under the LC Agreements with a pledge of the cash and cash equivalents that it owns. The LC Agreements require LCFC’s assets to be used first and foremost to satisfy claims of creditors of LCFC. Although the cash and cash equivalents held by LCFC are included in the consolidated assets of NRG, such cash and cash equivalents are not available to creditors of NRG.
   
Expenses of approximately $45 million, including fees to the lenders and other fees, were deferred and will be expensed in part over the original term of maturity through 2013 and in part over the amended maturity through 2015.
     As of June 30, 2010, NRG had issued $820 million of letters of credit under the Funded Letter of Credit Facility, leaving $480 million available for future issuances. Under the Revolving Credit Facility as of June 30, 2010, NRG had issued a letter of credit of $36 million, leaving $839 million available.

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     Dunkirk Power LLC Tax-Exempt Bonds
     On February 1, 2010, the Company fixed the rate on the Dunkirk bonds originally issued in April 2009, at 5.875%. In addition, the $59 million letter of credit issued by NRG in support of the bonds was cancelled and replaced with an NRG guarantee.
Debt Related to Capital Allocation Program
     On March 3, 2010, the Company completed the early unwinding of the CSF I Debt by remitting a cash payment to Credit Suisse, or CS, of $242 million to settle the outstanding principal and interest, as compared to $249 million that would have been due at maturity in June 2010. As part of the unwind, CS returned to NRG 6,600,000 shares of NRG common stock borrowed under the Share Lending Agreement, or SLA, between the parties and released all 12,441,973 shares of NRG common stock held as collateral for the CSF I Debt. The 6,600,000 shares of NRG common stock were returned to treasury stock and will no longer be treated as outstanding for corporate law purposes. The Company has now settled all obligations related to the CSF I and II Debt entered into in 2006, as amended from time to time, as well as the SLA entered into in February 2009.
Blythe Credit Agreement
     On June 24, 2010, NRG Solar Blythe LLC, or Blythe, entered into a credit agreement with a bank, or the Blythe Credit Agreement, for a $30 million term loan which has an interest rate of LIBOR plus an applicable margin which escalates 0.25% every three years and ranges from 2.5% at closing to 3.75% in year fifteen. The term loan matures in June 2028, amortizes based upon a predetermined schedule, and is secured by all of the assets of Blythe. The bank has also issued two letters of credit on behalf of Blythe totaling approximately $6.4 million. Blythe pays an availability fee of 100% of the applicable margin on these issued letters of credit.
     Also related to the Blythe Credit Agreement, on June 25, 2010, Blythe entered into a fixed for floating interest rate swap for 75% of the outstanding term loan amount, intended to hedge the risks associated with floating interest rates. Blythe will pay its counterparty the equivalent of a 3.563% fixed interest payment on a predetermined notional value, and Blythe will receive quarterly the equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by Blythe and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. The notional amount of the swap, which matures on June 25, 2028, is $22 million and amortizes in proportion to the loan.
South Trent Financing Agreement
     On June 14, 2010 NRG completed the acquisition of the South Trent, as discussed in Note 4, Business Acquisitions and Dispositions. As part of the purchase price consideration, South Trent entered into the Amended and Restated Financing Agreement, or Financing Agreement, with a group of lenders, which matures on June 14, 2020. The Financing Agreement includes a $79 million term loan, as well as a $10 million letter of credit facility in support of the PPA, for which the full amount had been issued as of June 30, 2010. The Financing Agreement also provides for up to $8 million in additional letter of credit facilities, none of which are utilized as of June 30, 2010. The term loan accrues interest at LIBOR plus a margin based upon a grid, which is initially 2.50% and increases every two years by 12.5 basis points. The term loan amortizes quarterly based upon a predetermined schedule with the unamortized portion due at maturity.
     Under the terms of the Financing Agreement, South Trent was required to enter into interest rate protection agreements that would fix the interest rate for a minimum of 75% of the outstanding principal amount. Accordingly, on June 14, 2010, South Trent entered into five interest rate swaps, intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, South Trent will pay its counterparty the equivalent of a 3.265% fixed interest payment on a predetermined notional value, and South Trent will receive the quarterly equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by South Trent and its counterparties are made quarterly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which mature on June 14, 2020, is $59 million. The swaps amortize in proportion to the loan.
     South Trent also entered into a series of forward-starting interest rate swaps that will become effective June 14, 2020, and are effective for eight years. The swaps are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, South Trent will pay its counterparty the equivalent of a 4.95% fixed interest payment on a predetermined notional value, and receive the quarterly equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by South Trent and its counterparties will be made quarterly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which will mature on June 14, 2028, is $21 million.

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NRG Thermal Financing
     On June 22, 2010 NRG Thermal’s largest subsidiary, NRG Energy Center Minneapolis LLC, or NRG Thermal Minneapolis, issued $100 million of 5.95% Series C notes due June 23, 2025, or the Series C Notes. The Series C Notes are secured by substantially all of the assets of NRG Energy Center Minneapolis. NRG Thermal has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interest in all of NRG Thermal’s subsidiaries. At the same time, NRG Thermal amended agreements for its other outstanding notes to conform to the covenants of the Series C Notes. The proceeds of the loan were used to finance the acquisition of Northwind Phoenix, as discussed in Note 4, Business Acquisitions and Dispositions.
     GenConn Energy LLC related financings
     NRG Connecticut Peaking Development LLC made funding requests under the equity bridge loan, or EBL, during the quarter. The EBL is backed by a letter of credit issued by NRG under its Funded Letter of Credit Facility equal to 104% of the amount outstanding. The proceeds of the EBL received through June 30, 2010, were $115 million and the remaining amounts will be drawn as necessary to fund interest on the EBL as the maximum amount permitted to be drawn for project costs for both projects has been met. Of the $115 million, $55 million was drawn to fund Devon project costs and will become due and payable upon the commercial operation date, or COD, of the Devon project, which is expected to occur in the third quarter of 2010.
     Borrowings of an equity method investment — In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a seven-year term loan facility, and also entered into a five-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 in June 2010 GenConn began to draw for the Middletown project. As of June 30, 2010, $109 million had been drawn.
     NINA Financing
     On May 28, 2010, NINA borrowed $3 million under the TANE Facility. On June 1, 2010, NINA repaid $20 million outstanding under its revolving credit facility, and the facility was terminated.

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Note 9 — Changes in Capital Structure
     The following table reflects the changes in NRG’s common stock issued and outstanding during the six months ended June 30, 2010:
                                 
    Authorized   Issued   Treasury   Outstanding
 
Balance as of December 31, 2009
    500,000,000       295,861,759       (41,866,451 )     253,995,308  
Shares issued under LTIP
          179,259             179,259  
Shares issued under NRG Employee Stock Purchase Plan, or ESPP
                54,845       54,845  
Capital Allocation Plan
                (2,214,000 )     (2,214,000 )
Shares returned by affiliates of CS
                (6,600,000 )     (6,600,000 )
4% Preferred Stock conversion
          7,701,450             7,701,450  
 
Balance as of June 30, 2010
    500,000,000       303,742,468       (50,625,606 )     253,116,862  
 
Employee Stock Purchase Plan
     As of June 30, 2010, there were 363,623 shares of treasury stock reserved for issuance under the ESPP. In July 2010, 66,145 shares of common stock were issued to employee accounts from treasury stock.
2010 Capital Allocation Plan
     As part of the Company’s 2010 Capital Allocation Plan, the Company repurchased $50 million of NRG’s common stock during the quarter ended June 30, 2010. NRG intends to complete the remainder of its $180 million of share repurchases by the end of 2010, subject to market prices, financial restrictions under the Company’s debt facilities and as permitted by securities laws.
Share Lending Agreements
     As part of the CSF I Debt unwind on March 3, 2010, CS returned to NRG 6,600,000 shares of NRG common stock borrowed under the SLA between the parties. The 6,600,000 shares of NRG common stock were returned to treasury stock and will no longer be treated as outstanding for corporate law purposes. See Note 8, Long-Term Debt, to this Form 10-Q for more information.
4% Preferred Stock
     As of January 21, 2010, the Company completed the redemption of all remaining outstanding shares of 4% Preferred Stock, with holders converting 154,029 Preferred Stock shares into 7,701,450 shares of common stock and the Company redeeming 28 Preferred Stock shares for $28 thousand in cash.

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Note 10 — Equity Compensation
Non-Qualified Stock Options, or NQSOs
     The following table summarizes the Company’s NQSO activity as of June 30, 2010, and changes during the six months then ended:
                         
            Weighted   Aggregate Intrinsic
            Average   Value
    Shares   Exercise Price   (In millions)
 
Outstanding as of December 31, 2009
    4,793,585     $ 25.07          
Granted
    754,200       23.79          
Exercised
    (111,331 )     22.12          
Forfeited
    (331,669 )     30.16          
         
Outstanding at June 30, 2010
    5,104,785       24.61     $ 10  
Exercisable at June 30, 2010
    3,288,301     $ 23.65     $ 10  
 
     The weighted average grant date fair value of NQSOs granted for the six months ended June 30, 2010, was $10.67.
     Restricted Stock Units, or RSUs
     The following table summarizes the Company’s non-vested RSU awards as of June 30, 2010, and changes during the six months then ended:
                 
            Weighted Average
            Grant-Date
    Units   Fair Value Per Unit
 
Non-vested as of December 31, 2009
    1,614,769     $ 30.78  
Granted
    352,600       23.66  
Vested
    (68,240 )     28.56  
Forfeited
    (109,180 )     30.12  
 
Non-vested as of June 30, 2010
    1,789,949     $ 29.50  
 
     Performance Units, or PUs
     The following table summarizes the Company’s non-vested PU awards as of June 30, 2010, and changes during the six months then ended:
                 
            Weighted Average
            Grant- Date
    Units   Fair Value Per Unit
 
Non-vested as of December 31, 2009
    617,300     $ 24.27  
Granted
    348,500       23.81  
Forfeited
    (194,400 )     22.73  
 
Non-vested as of June 30, 2010
    771,400     $ 24.45  
 
     In the six months ended June 30, 2010, there were no performance unit payouts in accordance with the terms of the performance units.
     Deferral Stock Units, or DSUs
     The following table summarizes the Company’s outstanding DSU awards as of June 30, 2010, and changes during the six months then ended:
                 
            Weighted Average
            Grant- Date
    Units   Fair Value Per Unit
 
Outstanding as of December 31, 2009
    304,049     $ 19.34  
Granted
    59,067       22.18  
Conversions
    (28,395 )     21.77  
 
Outstanding as of June 30, 2010
    334,721     $ 19.63  
 

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Note 11 — Earnings Per Share
     Basic earnings per share attributable to NRG common stockholders is computed by dividing net income attributable to NRG Energy Inc. adjusted for accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding.
     Diluted earnings per share 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.
     On March 3, 2010, as part of the CSF I Debt unwind, CS returned 6,600,000 shares of NRG common stock borrowed under the SLA between the parties. These shares had not been treated as outstanding for earnings per share purposes because CS was required to return all borrowed shares (or identical shares) upon termination of the SLA. See Note 8, Long-Term Debt, to this Form 10-Q, for more information on the SLA.
     The reconciliation of basic earnings per common share to diluted earnings per share attributable to NRG is as follows:
                                 
    Three months ended   Six months ended
    June 30,   June 30,
(In millions, except per share data)   2010   2009   2010   2009
 
Basic earnings per share attributable to NRG common stockholders
                               
Numerator:
                               
Net income attributable to NRG Energy, Inc.
  $ 211     $ 433     $ 269     $ 631  
Preferred stock dividends
    (3 )     (7 )     (5 )     (21 )
 
Net income attributable to NRG Energy, Inc. available to common stockholders
  $ 208     $ 426     $ 264     $ 610  
 
Denominator:
                               
Weighted average number of common shares outstanding
    255       253       254       245  
Basic earnings per share:
                               
Net income attributable to NRG Energy, Inc.
  $ 0.82     $ 1.68     $ 1.04     $ 2.49  
 
Diluted earnings per share attributable to NRG common stockholders
                               
Numerator:
                               
Net income available to common stockholders
  $ 208     $ 426     $ 264     $ 610  
Add preferred stock dividends for dilutive preferred stock
          4             14  
 
Net income attributable to NRG Energy, Inc. available to common stockholders
  $ 208     $ 430     $ 264     $ 624  
 
Denominator:
                               
Weighted average number of common shares outstanding
    255       253       254       245  
Incremental shares attributable to the issuance of equity compensation (treasury stock method)
    1       1       1       1  
Incremental shares attributable to assumed conversion features of outstanding preferred stock (if-converted method)
          21       1       29  
 
Total dilutive shares
    256       275       256       275  
Diluted earnings per share:
                               
 
Net income attributable to NRG Energy, Inc.
  $ 0.81     $ 1.56     $ 1.03     $ 2.27  
 
     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 six months ended June 30:
                                 
    Three months ended June 30,   Six months ended June 30,
(In millions of shares)   2010   2009   2010   2009
 
Equity compensation — NQSOs and PUs
    6       5       6       5  
Embedded derivative of 3.625% redeemable perpetual preferred stock
    16       16       16       16  
Embedded derivative of CSF II Debt
          8             8  
 
Total
    22       29       22       29  
 

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Note 12 — Segment Reporting
     NRG’s segment structure has changed to reflect the Company’s acquisition of Reliant Energy along with the previously reported core areas of operation which are primarily the geographic regions of the Company’s wholesale power generation, thermal and chilled water business, and corporate activities. Within NRG’s wholesale power generation operations, there are distinct components with separate operating results and management structures for the following regions: Texas, Northeast, South Central, West and International.
                                                                                 
(In millions)           Wholesale Power Generation                
Three months ended   Reliant                   South                        
June 30, 2010   Energy   Texas(a)   Northeast   Central   West   International   Thermal   Corporate   Elimination   Total
 
Operating revenues
  $ 1,282     $ 692     $ 205     $ 152     $ 32     $ 30     $ 27     $ (4 )   $ (283 )   $ 2,133  
Depreciation and amortization
    29       124       31       16       3             3       2             208  
Equity in earnings of unconsolidated affiliates
          1       (1 )           1       11             (1 )           11  
Income/(loss) before income taxes
    277       157       (2 )     4       8       31       (2 )     (147 )     1       327  
Net income/(loss)
    277       157       (2 )     4       8       21       (2 )     (254 )     1       210  
Net loss attributable to non-controlling interest
          (1 )                                               (1 )
 
Net income/(loss) attributable to NRG Energy, Inc.
  $ 277     $ 158     $ (2 )   $ 4     $ 8     $ 21     $ (2 )   $ (254 )   $ 1     $ 211  
 
Total assets
  $ 1,930     $ 13,363     $ 1,843     $ 884     $ 372     $ 672     $ 328     $ 27,303     $ (21,592 )   $ 25,103  
 
(a)   Includes inter-segment sales of $281 million to Reliant Energy.
                                                                                 
(In millions)           Wholesale Power Generation                
Three months ended   Reliant                   South                        
June 30, 2009   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  
 
(a)   Reliant Energy results are for the period May 1, 2009, to June 30, 2009.
 
(b)   Includes inter-segment sales of $69 million to Reliant Energy.

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(In millions)           Wholesale Power Generation                
Six months ended   Reliant                   South                        
June 30, 2010   Energy   Texas(a)   Northeast   Central   West   International   Thermal   Corporate   Elimination   Total
 
Operating revenues
  $ 2,458     $ 1,562     $ 484     $ 295     $ 67     $ 65     $ 63     $ (2 )   $ (644 )   $ 4,348  
Depreciation and amortization
    59       241       63       32       6             5       4             410  
Equity in earnings of unconsolidated affiliates
          11       (1 )           1       15             (1 )           25  
Income/(loss) from continuing operations before income taxes
    89       532       50             14       41       2       (279 )     1       450  
Net income/(loss)
    89       532       50             14       29       2       (449 )     1       268  
Net loss attributable to non-controlling interest
          (1 )                                               (1 )
 
Net income/(loss) attributable to NRG Energy, Inc.
  $ 89     $ 533     $ 50     $     $ 14     $ 29     $ 2     $ (449 )   $ 1     $ 269  
 
(a)   Includes inter-segment sales of $642 million to Reliant Energy.
                                                                                 
In millions)   Wholesale Power Generation                
Six months ended   Reliant                   South                        
June 30, 2009   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  
 
(a)   Reliant Energy results are for the period May 1, 2009, to June 30, 2009.
 
(b)   Includes inter-segment sales of $69 million to Reliant Energy.

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Note 13 — Income Taxes
Effective Tax Rate
          The Company’s Income tax provision consisted of the following:
                                 
    Three months ended June 30,   Six months ended June 30,
(In millions except otherwise noted)   2010   2009   2010   2009
 
Income tax expense
  $ 117     $ 150     $ 182     $ 448  
Effective tax rate
    35.8 %     25.8 %     40.4 %     41.5 %
 
          For the three months ended June 30, 2010, NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes as well as recording federal and state tax expense and interest for unrecognized tax benefits. For the three months ended June 30, 2009, NRG’s effective tax rate was different than the statutory rate of 35% primarily due to a net state and local income tax benefit as a result of the Reliant Energy acquisition, and the sale of the MIBRAG facility.
          For the six months ended June 30, 2010, NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes as well as recording federal and state tax expense and interest for unrecognized tax benefits. For the six months ended June 30, 2009, NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to an increase in valuation allowance as a result of capital losses generated in the six month period for which there were no projected capital gains or available tax planning strategies. Furthermore, the effective tax rate was decreased by the sale of the MIBRAG facility as well as a net state and local income tax benefit as a result of the Reliant Energy acquisition.
     Unrecognized tax benefits
          As of June 30, 2010, NRG has recorded a $512 million non-current tax liability for unrecognized tax benefits, primarily resulting from taxable earnings for the period for which there are no net operating losses available to offset for financial statement purposes. NRG has accrued interest related to these unrecognized tax benefits of approximately $17 million for the six months ended June 30, 2010, and has accrued approximately $34 million since adoption. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense.
          The Company continues to be under examination by the Internal Revenue Service for the years 2004 through 2006, as well as various state jurisdictions for multiple years.
     Tax Receivable and Payable
          As of June 30, 2010, NRG recorded a current tax payable of approximately $22 million that represents a tax liability due for domestic state taxes of approximately $14 million, as well as foreign taxes payable of approximately $8 million. In addition, as of June 30, 2010, NRG had a domestic tax receivable of $77 million for property tax refunds primarily due to the New York State Empire Zone program.

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Note 14 — Benefit Plans and Other Postretirement Benefits
     NRG Defined Benefit Plans
          NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-Bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation solely by eligible employees. The total amount of employer contributions paid for the six months ended June 30, 2010, was $11 million. NRG expects to make approximately $7 million in further contributions for the remainder of 2010.
          The net periodic pension cost related to all of the Company’s defined benefit pension plans includes the following components:
                                 
    Defined Benefit Pension Plans
    Three months ended June 30,   Six months ended June 30,
(In millions)   2010   2009   2010   2009
 
Service cost benefits earned
  $ 4     $ 3     $ 7     $ 7  
Interest cost on benefit obligation
    5       5       10       10  
Prior service cost
          1             1  
Expected return on plan assets
    (6 )     (4 )     (10 )     (8 )
 
Net periodic benefit cost
  $ 3     $ 5     $ 7     $ 10  
 
          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)   2010   2009   2010   2009
 
Service cost benefits earned
  $     $ 1     $ 1     $ 2  
Interest cost on benefit obligation
    2       1       3       3  
 
Net periodic benefit cost
  $ 2     $ 2     $ 4     $ 5  
 
     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 six months ended June 30, 2010 was $1 million.
          The Company recognized net periodic costs related to its 44% interest in STP defined benefits as follows:
                                 
    Three months ended June 30,   Six months ended June 30,
(In millions)   2010   2009   2010   2009
 
Net periodic benefit costs
  $ 2     $ 2     $ 4     $ 5  
 

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Note 15 — Commitments and Contingencies
     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 June 30, 2010, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.
     Nuclear Innovation North America, LLC
          CPS Settlement — On March 1, 2010, an agreement was reached with CPS for NINA to acquire a controlling interest in the STP Units 3 and 4 Project through a settlement of litigation between the parties. As part of the agreement, NINA increased its ownership in the STP Units 3 and 4 Project from 50% to 92.375% and assumed full management control of the project. NRG also will pay $80 million to CPS, subject to the United States Department of Energy’s, or U.S. DOE, approval of a fully executed term sheet for a conditional U.S. DOE loan guarantee. The first $40 million would be promptly paid after acceptance of the guarantee with the remaining $40 million paid six months later. NRG also agreed to donate an additional $10 million, unconditionally, over four years in annual payments of $2.5 million to the Residential Energy Assistance Partnership, or REAP, in San Antonio. The first $2.5 million payment to REAP was made on March 17, 2010. In connection with the agreement, the Company capitalized $90 million to construction in progress within property, plant and equipment, and as of June 30, 2010, $87.5 million in liabilities remains on the condensed consolidated balance sheet for the obligations to CPS and REAP. As part of the agreement with CPS, all litigation was dismissed with prejudice.
          NINA Investment and Option Agreement — On May 10, 2010, NINA and Tokyo Electric Power Company of Japan, or TEPCO, signed an Investment and Option Agreement whereby TEPCO agreed to acquire up to a 20% interest in NINA Investments Holdings LLC, or Holdings, a wholly-owned subsidiary of NINA, which indirectly holds NINA’s ownership interest in the STP Units 3 and 4 Project. TEPCO will initially invest $155 million for a 10% share of Holdings, which includes a $30 million option premium payment to Holdings. This option, which expires approximately one year from the date of signing the Investment and Option Agreement, will enable TEPCO to buy an additional 10% of Holdings for another payment of $125 million. Pursuant to the terms of the Agreement, the closing is contingent upon NINA’s acceptance of a U.S. DOE loan guarantee commitment. Upon its initial investment, TEPCO will hold a 9.238% interest in the STP Units 3 and 4 Project, diluting NINA’s investment to 83.137% (75.11% for NRG). If TEPCO exercises its option to increase its ownership of Holdings another 10%, it will own 18.475% of the STP Units 3 and 4 Project, diluting NINA’s investment to 73.90% (66.8% for NRG).
          U.S. DOE Loan Guarantee — In early 2010, NRG announced that if the STP Units 3 and 4 Project did not receive a loan guarantee from the U.S. DOE in a timely fashion, it was the intention of the Company both to reduce substantially its commitment to fund on-going project expenditures as well as to reduce development spending on the project overall while the outcome of the loan guarantee was uncertain. At the end of the second quarter, with the outcome of the loan guarantee uncertain, NRG began to curtail substantially its funding of on-going development expenses, immediately reducing its spend by approximately 70%. Working with NRG’s partner (which agreed to step-up its commitment) and with other counterparties involved in the project, NRG also reduced the current spend rate on project development but did so in a manner which allowed the project to stay on its current schedule. NRG presently is in discussions with its partner and counterparties about a second phase of spending reductions. Should NRG and its partners withdraw support from the project this may result in a reassessment of the probability of success of the project and an impairment of the value of the capitalized assets for STP Units 3 and 4. An impairment to NRG would result in a permanent write-down of $498 million of construction-in-progress capitalized through June 30, 2010, plus any amounts capitalized through the impairment date. The likelihood of NINA receiving a loan guarantee is largely dependent upon additional appropriations for nuclear development by Congress or other means of properly securing the necessary funding for additional nuclear loan guarantee volume. On July 1, 2010, the U.S. House of Representatives passed an Emergency Supplemental Appropriations bill for fiscal year 2010, which included an additional $9 billion in loan guarantee authority for nuclear power facilities. The $9 billion in nuclear loan guarantee volume accelerates into 2010 a portion of the $36 billion in additional loan guarantee authority requested by the Obama administration for fiscal year 2011. The legislation passed by the House of Representatives, however, was rejected by the U.S. Senate. If Congress fails to agree on the necessary appropriation this session, the required funding will be subject to the normal fiscal year 2011 budget appropriation process, which as currently contemplated, would provide enough appropriations for the benefit of a loan guarantee to the STP Units 3 and 4 Project.

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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. 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 be at amounts that are different from its currently recorded reserves and that such difference could be material.
          In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect NRG’s consolidated financial position, results of operations, or cash flows.
     California Department of Water Resources
          This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the Federal Energy Regulatory Commission, or FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC’s review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP’s appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008 the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller’s market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit’s decision agreeing that the case should be remanded to the FERC to clarify the FERC’s 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008 decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008 decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court’s June 26, 2008 decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their reply.
          At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG’s financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy’s 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.

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          On January 14, 2010, the U.S. Supreme Court issued its decision in an unrelated proceeding involving the Mobile-Sierra doctrine that will affect the standard of review applied to the CDWR contract on remand before the FERC. In NRG Power Marketing v. Maine Public Utilities Commission, the Supreme Court held that the Mobile-Sierra presumption regarding the reasonableness of contract rates does not depend on the identity of the complainant who seeks a FERC investigation/refund.
     Louisiana Generating, LLC
          On February 11, 2009, the U.S. Department of Justice, or U.S. DOJ, acting at the request of the U.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC, or LaGen, 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 LaGen 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, LaGen made several filings. It filed an objection in the Cajun Electric Cooperative Power, Inc.’s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. It also filed a complaint in the same bankruptcy proceeding in the same court seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for the violations alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have merit. On April 15, 2010, the bankruptcy court signed an order granting LaGen’s stipulation of voluntary dismissal without prejudice of its adversary bankruptcy action.
          On June 8, 2009, the parties filed a joint status report in the U.S. DOJ lawsuit setting forth their views of the case and proposing a trial schedule. On June 18, 2009, LaGen filed a motion to bifurcate the U.S. DOJ lawsuit into separate liability and remedy phases, and on June 30, 2009, the U.S. DOJ filed its opposition. On April 28, 2010, the district court entered a Joint Case Management Order, and LaGen’s motion for bifurcation was effectively granted, in that the district court set trial on the liability phase for mid-2011, and, if necessary, trial on the damages (remedy) phase for mid-2012. On August 24, 2009, LaGen filed a motion to dismiss this lawsuit, and on September 25, 2009, the U.S. DOJ filed its opposition to the motion to dismiss. On February 18, 2010, the LDEQ filed a motion to intervene in the above lawsuit and a complaint against LaGen for alleged violations of Louisiana’s Prevention of Significant Deterioration, or PSD regulations, and Louisiana’s Title V operating permit program. LDEQ seeks substantially similar relief to that requested by the U.S. DOJ. On February 19, 2010, the district court granted LDEQ’s motion to intervene. On April 26, 2010, LaGen filed a motion to dismiss LDEQ’s complaint. On July 21, 2010, LaGen argued its motions to dismiss, while the U.S. DOJ and LDEQ argued in opposition to the motions. The judge ordered the parties to submit further briefing within thirty days.
          On February 18, 2010, the Louisiana Department of Environmental Quality, or LDEQ, filed a motion to intervene in the above lawsuit and a complaint against LaGen for alleged violations of Louisiana’s Prevention of Significant Deterioration, or PSD regulations and Louisiana’s Title V operating permit program. LDEQ seeks substantially similar relief to that requested by the U.S. DOJ. On February 19, 2010, the district court granted LDEQ’s motion to intervene. On April 26, 2010, LaGen filed a motion to dismiss LDEQ’s complaint. On April 28, 2010, the district court entered a Joint Case Management Order in this matter. As a result of entering this order, LaGen’s motion for bifurcation was effectively granted. As such, the first trial on liability will take place on or about May 2011. The second trial on the remedy will take place on or about March 2012. On July 21, 2010, LaGen argued its motions to dismiss, while the U.S. DOJ and LDEQ argued in opposition to the motions. The judge ordered the parties to submit further briefing within thirty days.

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     Dunkirk Construction Litigation
          In 2005, NRG entered into a Consent Decree with the New York State Department of Environmental Conservation whereby it agreed to reduce certain emissions generated by its Huntley and Dunkirk power plants. Pursuant to the Consent Decree, on November 21, 2007, Clyde Bergemann EEC, or CBEEC, and NRG entered into a firm fixed price contract for the supply of equipment, material and services for six fabric filters for NRG’s Dunkirk Electric Power Generating Station. Subsequent to contracting with NRG, CBEEC subcontracted with Hohl Industrial Services, Inc., or Hohl, to perform steel erection and equipment installation at Dunkirk.
          On August 28, 2009, Hohl filed its original complaint against NRG, its subsidiary Dunkirk Power LLC, or Dunkirk Power, and CBEEC among others for claims of breach of contract, quantum meruit, unjust enrichment and foreclosure of mechanics’ liens. As part of CBEEC’s contractual obligation to NRG, CBEEC agreed to defend NRG, under a reservation of rights. CBEEC filed an answer to the above complaint on behalf of itself, NRG, and Dunkirk Power on October 5, 2009. On December 16, 2009, CBEEC filed a Motion for Summary Judgment on behalf of itself, NRG, and Dunkirk Power. On February 1, 2010, NRG and Dunkirk Power filed a Motion for Leave to file an Amended Answer with Cross-Claims against CBEEC. NRG asserted breach of contract claims seeking liquidated damages for the delays caused by CBEEC. NRG also retained its own counsel to represent its interest in the cross-claims and reserved its rights to seek reimbursement from CBEEC. On February 17, 2010, CBEEC filed an Amended Answer with Affirmative Defenses, Counterclaims and Cross-Claims against NRG, in which it sought $30 million alleging breach of contract, quantum meruit, unjust enrichment, and foreclosure of two mechanic’s liens, as a result of alleged delays caused by NRG and Dunkirk Power. On March 5, 2010, CBEEC and NRG resolved their disputed cross-claims. In April 2010, the other parties to this litigation settled their disputes which settlement is expected to be final in the third quarter of 2010.
   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 PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers’ monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI, totaled $385 million for RERS’s “Price to Beat” Customers. It is unclear what the actual number may be. “Price to Beat” was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT’s order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment with the Court of Appeals for the Third District of Texas with the first such appeal filed on the same date as the state district court judgment and the last such appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District reversed the lower court’s decision ruling that CenterPoint Energy’s stranded cost recovery should exclude only EMCs credited to RERS for its “Price to Beat” customers. On June 2, 2008, CenterPoint Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Court agreed to consider the CenterPoint Energy appeal as well as two related petitions for review filed by other entities. Oral argument occurred on October 6, 2009.
          In November 2008, CenterPoint Energy and Reliant Energy Inc., or REI, 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.

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Note 16 — Regulatory Matters
          NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG’s wholesale and retail businesses.
          In addition to the regulatory proceedings noted below, NRG and its subsidiaries are a party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect NRG’s consolidated financial position, results of operations, or cash flows.
          PJM — 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 Reliability Pricing Model, or RPM transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint had sought to replace the auction-determined results for installed capacity for the 2008/2009, 2009/2010, and 2010/2011 delivery years with administratively-determined prices. On August 14, 2009, the MDPSC and the New Jersey Board of Public Utilities filed an appeal of FERC’s orders to the U.S. Court of Appeals for the Fourth Circuit, and a successful appeal could disrupt the auction-determined results and create a refund obligation for market participants. The case has been transferred to the U.S. Court of Appeals for the DC Circuit.
          Midwest ISO v. PJM — On March 8, 2010, Midwest ISO filed a complaint against PJM seeking payments from PJM related to inter-market operations and settlements for congestion costs between the systems for the period from April 2005 to the present. If the Midwest ISO’s allegations are true, PJM may have significant liability. If PJM makes any payments to the Midwest ISO related to these claims, PJM is expected to seek to recover the payments from entities that served load and held transmission congestion rights on PJM during the period in dispute, including NRG, which provided basic generation service and thus effectively served load. At this time, NRG’s share of any payment by PJM is not expected to be material.
          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. REPS, other market participants, ERCOT, and PUCT staff opposed Constellation’s complaint. On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation’s complaint. On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other. On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the trial court’s decision. If all appeals are unsuccessful, on remand to the PUCT, it would determine the appropriate methodology for giving effect to the trial court’s decision. It is not known at this time whether only Constellation’s under-scheduling charges, the under-scheduling charges of all other QSEs that disputed REPS charges for the same time frame, the entire market, or some other approach would be used for any resettlement.
          Under the PUCT ordered formula, Qualified Scheduling Entities, or QSEs, who under-scheduled capacity within any of ERCOT’s four congestion zones were assessed under-scheduling charges which defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving QSEs. Under the Court’s decision, all RPRS costs would be assigned to all load-serving QSEs based upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled capacity. If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS costs, REPS’s share of the total RPRS costs allocated to QSEs would increase.

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Note 17 — Environmental Matters
          The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the United States. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG’s facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. New legislation and regulations to mitigate the effects of Greenhouse Gases, or GHG including carbon dioxide, or CO2 from power plants, are under consideration at the federal and state levels. In general, the effect of such future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the Company’s operations.
     Environmental Capital Expenditures
          Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2010 through 2014 to meet NRG’s environmental commitments will be approximately $0.9 billion 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, sulfur dioxide, or SO2, nitrogen oxide, or 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 a section of the Clean Water Act regulating cooling water intake structures, or 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, Clean Air Transport Rule, or CATR, 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.
          NRG’s current contracts with the Company’s rural electrical customers in the South Central region allow for recovery of a portion of the regions’ capital costs once in operation, along with a capital return incurred by complying with new laws, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital project and the remaining duration of the contracts.
     Northeast Region
          In January 2006, NRG’s Indian River Operations, Inc. received a letter of informal notification from DNREC stating that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily 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, 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 DNREC and other trustees to close out the assessment phase.
          Pursuant to a consent order dated September 25, 2007, between NRG and DNREC, NRG agreed to operate the four units at the Indian River plant in a manner that would limit the emissions of NOx and SO2, and to mothball Units 1 and 2 on May 1, 2011 and May 1, 2010, respectively. In addition, Units 3 and 4, with a combined generating capacity of approximately 565 MW, could not operate beyond December 31, 2011 unless appropriate control technology was installed on each unit. Unit 2 was mothballed as planned on May 1, 2010. On July 21, 2010, the court approved an amended consent order, pursuant to which NRG will retire Unit 3 (155 MW) by December 31, 2013, thereby extending the operable period of the unit by two years without installing additional control technology. Units 1, 2 and 4 are not affected by the amended consent order.
     South Central Region
          On February 11, 2009, the U.S. DOJ acting at the request of the U.S. EPA commenced a lawsuit against LaGen 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 LaGen on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be found in Note 15, Commitments and Contingencies, to this Form 10-Q, Louisiana Generating, LLC.

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Note 18 — Condensed Consolidating Financial Information
     As of June 30, 2010, 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 notes are guaranteed by certain of NRG’s current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.
     Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of June 30, 2010:
     
Arthur Kill Power LLC
  NRG Generation Holdings, Inc.
Astoria Gas Turbine Power LLC
  NRG Huntley Operations Inc.
Berrians I Gas Turbine Power LLC
  NRG International LLC
Big Cajun II Unit 4 LLC
  NRG MidAtlantic Affiliate Services Inc.
Cabrillo Power I LLC
  NRG Middletown Operations Inc.
Cabrillo Power II LLC
  NRG Montville Operations Inc.
Carbon Management Solutions LLC
  NRG New Jersey Energy Sales LLC
Clean Edge Energy LLC
  NRG New Roads Holdings LLC
Conemaugh Power LLC
  NRG North Central Operations, Inc.
Connecticut Jet Power LLC
  NRG Northeast Affiliate Services Inc.
Devon Power LLC
  NRG Norwalk Harbor Operations Inc.
Dunkirk Power LLC
  NRG Operating Services Inc.
Eastern Sierra Energy Company
  NRG Oswego Harbor Power Operations Inc.
Elbow Creek Wind Project LLC
  NRG Power Marketing LLC
El Segundo Power, LLC
  NRG Retail LLC
El Segundo Power II LLC
  NRG Saguaro Operations Inc.
GCP Funding Company LLC
  NRG South Central Affiliate Services Inc.
Huntley IGCC LLC
  NRG South Central Generating LLC
Huntley Power LLC
  NRG South Central Operations Inc.
Indian River IGCC LLC
  NRG South Texas LP
Indian River Operations Inc.
  NRG Texas LLC
Indian River Power LLC
  NRG Texas C & I Supply LLC
James River Power LLC
  NRG Texas Holding Inc.
Keystone Power LLC
  NRG Texas Power LLC
Langford Wind Power, LLC
  NRG West Coast LLC
Louisiana Generating LLC
  NRG Western Affiliate Services Inc.
Middletown Power LLC
  Oswego Harbor Power LLC
Montville IGCC LLC
  Reliant Energy Power Supply, LLC
Montville Power LLC
  Reliant Energy Retail Holdings, LLC
NEO Corporation
  Reliant Energy Retail Services, LLC
NEO Freehold-Gen LLC
  RE Retail Receivables, LLC
NEO Power Services Inc.
  RERH Holdings, LLC
New Genco GP LLC
  Reliant Energy Services Texas LLC
Norwalk Power LLC
  Reliant Energy Texas Retail LLC
NRG Affiliate Services Inc.
  Saguaro Power LLC
NRG Arthur Kill Operations Inc.
  Somerset Operations Inc.
NRG Artesian Energy LLC
  Somerset Power LLC
NRG Astoria Gas Turbine Operations Inc.
  Texas Genco Financing Corp.
NRG Bayou Cove LLC
  Texas Genco GP, LLC
NRG Cabrillo Power Operations Inc.
  Texas Genco Holdings, Inc.
NRG California Peaker Operations LLC
  Texas Genco LP, LLC
NRG Cedar Bayou Development Company LLC
  Texas Genco Operating Services, LLC
NRG Connecticut Affiliate Services Inc.
  Texas Genco Services, LP
NRG Construction LLC
  Vienna Operations, Inc.
NRG Devon Operations Inc.
  Vienna Power LLC
NRG Dunkirk Operations, Inc.
  WCP (Generation) Holdings LLC
NRG Energy Services LLC
  West Coast Power LLC
NRG El Segundo Operations Inc.
   

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

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended June 30, 2010
                                         
                    NRG Energy,            
    Guarantor   Non-Guarantor   Inc.           Consolidated
(In millions)   Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations(a)   Balance
 
Operating Revenues
                                       
Total operating revenues
  $ 2,066     $ 74     $     $ (7 )   $ 2,133  
 
Operating Costs and Expenses
                                       
Cost of operations
    1,283       53             (7 )     1,329  
Depreciation and amortization
    202       4       2             208  
Selling, general and administrative
    72       2       65             139  
Development costs
          3       10             13  
 
Total operating costs and expenses
    1,557       62       77       (7 )     1,689  
 
Operating Income/(Loss)
    509       12       (77 )           444  
Other Income/(Expense)
                                       
Equity in earnings of consolidated subsidiaries
    15             332       (347 )      
Equity in earnings of unconsolidated affiliates
    1       10                   11  
Other income, net
    2       14       3             19  
Interest expense
    (6 )     (9 )     (132 )           (147 )
 
Total other income/(expense)
    12       15       203       (347 )     (117 )
 
Income/(Losses) Before Income Taxes
    521       27       126       (347 )     327  
Income tax expense/(benefit)
    190       12       (85 )           117  
 
Net Income
    331       15       211       (347 )     210  
Less: Net loss attributable to noncontrolling interest
    (1 )                       (1 )
 
Net Income attributable to NRG Energy, Inc.
  $ 332     $ 15     $ 211     $ (347 )   $ 211  
 
(a)   All significant intercompany transactions have been eliminated in consolidation.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Six Months Ended June 30, 2010
                                         
                    NRG Energy,            
    Guarantor   Non-Guarantor   Inc.           Consolidated
(In millions)   Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations(a)   Balance
 
Operating Revenues
                                       
Total operating revenues
  $ 4,193     $ 169     $     $ (14 )   $ 4,348  
 
Operating Costs and Expenses
                                       
Cost of operations
    2,856       119       7       (14 )     2,968  
Depreciation and amortization
    392       14       4             410  
Selling general and administrative
    139       5       125             269  
Development costs
          6       16             22  
 
Total operating costs and expenses
    3,387       144       152       (14 )     3,669  
 
Gain on sale of assets
                23             23  
 
Operating Income/(Loss)
    806       25       (129 )           702  
Other Income/(Expense)
                                       
Equity in earnings of consolidated subsidiaries
    22             526       (548 )      
Equity in earnings of unconsolidated affiliates
    1       24                   25  
Other income, net
    3       17       3             23  
Interest expense
    (11 )     (23 )     (266 )           (300 )
 
Total other income/(expense)
    15       18       263       (548 )     (252 )
 
Income/(Losses) Before Income Taxes
    821       43       134       (548 )     450  
Income tax expense/(benefit)
    301       16       (135 )           182  
 
Net Income
    520       27       269       (548 )     268  
Less: Net loss attributable to noncontrolling interest
    (1 )                       (1 )
 
Net Income attributable to NRG Energy, Inc.
  $ 521     $ 27     $ 269     $ (548 )   $ 269  
 
(a)   All significant intercompany transactions have been eliminated in consolidation.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 2010
                                         
    Guarantor   Non-Guarantor   NRG Energy, Inc.           Consolidated
(In millions)   Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations(a)   Balance
 
ASSETS
Current Assets
                                       
Cash and cash equivalents
  $ 34     $ 154     $ 1,980     $     $ 2,168  
Funds deposited by counterparties
    310                         310  
Restricted cash
    1       12                   13  
Accounts receivable, net
    876       33                   909  
Inventory
    527       8                   535  
Derivative instruments valuation
    1,800                         1,800  
Cash collateral paid in support of energy risk management activities
    389       2                   391  
Prepayments and other current assets
    62       55       240       (114 )     243  
 
Total current assets
    3,999       264       2,220       (114 )     6,369  
 
Net property, plant and equipment
    10,515       1,125       153             11,793  
 
Other Assets
                                       
Investment in subsidiaries
    753       258       20,751       (21,762 )      
Equity investments in affiliates
    42       352                   394  
Capital leases and notes receivable, less current portion
    5,626       431       3,169       (8,792 )     434  
Goodwill
    1,713       3                   1,716  
Intangible assets, net
    1,567       58       33       (32 )     1,626  
Nuclear decommissioning trust fund
    360                         360  
Derivative instruments valuation
    899             11             910  
Restricted cash supporting funded letter of credit facility
          1,300                   1,300  
Other non-current assets
    39       13       149             201  
 
Total other assets
    10,999       2,415       24,113       (30,586 )     6,941  
 
Total Assets
  $ 25,513     $ 3,804     $ 26,486     $ (30,700 )   $ 25,103  
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
                                       
Current portion of long-term debt and capital leases
  $ 58     $ 159     $ 20     $ (58 )   $ 179  
Accounts payable
    (3,111 )     483       3,318             690  
Derivative instruments valuation
    1,434       2       48             1,484  
Deferred income taxes
    (4 )           248             244  
Cash collateral received in support of energy risk management activities
    310                         310  
Accrued expenses and other current liabilities
    345       33       302       (57 )     623  
 
Total current liabilities
    (968 )     677       3,936       (115 )     3,530  
 
Other Liabilities
                                       
Long-term debt and capital leases
    2,936       853       12,994       (8,792 )     7,991  
Funded letter of credit
                1,300             1,300  
Nuclear decommissioning reserve
    309                         309  
Nuclear decommissioning trust liability
    234                         234  
Deferred income taxes
    2,231       (193 )     (270 )           1,768  
Derivative instruments valuation
    364       40       29             433  
Out-of-market contracts
    283       6             (31 )     258  
Other non-current liabilities
    739       27       236             1,002  
 
Total non-current liabilities
    7,096       733       14,289       (8,823 )     13,295  
 
Total liabilities
    6,128       1,410       18,225       (8,938 )     16,825  
 
3.625% Preferred Stock
                248             248  
Stockholders’ Equity
    19,385       2,394       8,013       (21,762 )     8,030  
 
Total Liabilities and Stockholders’ Equity
  $ 25,513     $ 3,804     $ 26,486     $ (30,700 )   $ 25,103  
 
(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 Six Months Ended June 30, 2010
                                         
            Non-   NRG Energy,            
    Guarantor   Guarantor   Inc.           Consolidated
(In millions)   Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations(a)   Balance
 
Cash Flows from Operating Activities
                                       
Net income
  $ 520     $ 27     $ 269     $ (548 )   $ 268  
Adjustments to reconcile net income to net cash provided by operating activities:
                                       
Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries
    10       (11 )     (489 )     481       (9 )
Depreciation and amortization
    392       14       4             410  
Provision for bad debts
    22                         22  
Amortization of nuclear fuel
    19                         19  
Amortization of financing costs and debt discount/premiums
          3       12             15  
Amortization of intangibles and out-of-market contracts
    1                         1  
Changes in deferred income taxes and liability for unrecognized tax benefits
    300       2       (123 )           179  
Changes in nuclear decommissioning trust liability
    9                         9  
Changes in derivatives
    (57 )     2                   (55 )
Changes in collateral deposits supporting energy risk management activities
    (30 )                       (30 )
Loss/(gain) on sale of assets
    12             (23 )           (11 )
Loss on sale of emission allowances
    3                         3  
Amortization of unearned equity compensation
                15             15  
Changes in option premiums collected, net of acquisition
    34                         34  
Cash (used)/provided by changes in other working capital, net of acquisitions
    (505 )     (75 )     315             (265 )
 
Net Cash Provided/(Used) by Operating Activities
    730       (38 )     (20 )     (67 )     605  
 
Cash Flows from Investing Activities
                                       
Intercompany (loans to)/receipts from subsidiaries
    (739 )           (142 )     881        
Acquisition of businesses
          (141 )                 (141 )
Investment in subsidiaries
          1,721       (1,721 )            
Capital expenditures
    (145 )     (159 )     (26 )           (330 )
Increase in restricted cash, net
          (11 )                 (11 )
Decrease in notes receivable
          15                   15  
Purchases of emission allowances
    (45 )                       (45 )
Proceeds from sale of emission allowances
    11                         11  
Investments in nuclear decommissioning trust fund securities
    (76 )                       (76 )
Proceeds from sales of nuclear decommissioning trust fund securities
    67                         67  
Proceeds from renewable energy grants
    84       18                   102  
Proceeds from sale of assets, net
    1             29             30  
Other
          (2 )     (5 )           (7 )
 
Net Cash (Used)/Provided by Investing Activities
    (842 )     1,441       (1,865 )     881       (385 )
 
Cash Flows from Financing Activities
                                       
(Payments)/proceeds from intercompany loans
    127       15       739       (881 )      
Payment of intercompany dividends
    (30 )     (37 )           67        
Payment of dividends to preferred stockholders
                (5 )           (5 )
Payments for treasury stock
                (50 )           (50 )
Net receipt from acquired derivatives that include financing elements
    27                         27  
Installment proceeds from sale of non-controlling interest in subsidiary
          50                   50  
Proceeds from issuance of long-term debt
    3       138                   141  
Proceeds from issuance of term loan for funded letter of credit facility
                1,300             1,300  
Increase in restricted cash supporting funded letter of credit facility
          (1,300 )                 (1,300 )
Proceeds from issuance of common stock
                2             2  
Payment of deferred debt issuance costs
    (1 )     (7 )     (45 )           (53 )
Payment of short and long-term debt
          (219 )     (240 )           (459 )
 
Net Cash Provided/(Used) by Financing Activities
    126       (1,360 )     1,701       (814 )     (347 )
Effect of exchange rate changes on cash and cash equivalents
          (9 )                 (9 )
 
Net Increase/(Decrease) in Cash and Cash Equivalents
    14       34       (184 )           (136 )
Cash and Cash Equivalents at Beginning of Period
    20       120       2,164             2,304  
 
Cash and Cash Equivalents at End of Period
  $ 34     $ 154     $ 1,980     $     $ 2,168  
 
(a)   All significant intercompany transactions have been eliminated in consolidation.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended 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/(expense), net
    2       (12 )     (1 )           (11 )
Interest expense
    (18 )     (38 )     (103 )           (159 )
 
Total other income/(expense)
    107       80       373       (597 )     (37 )
 
Income/(Loss) 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/(Loss) attributable to NRG Energy, Inc.
  $ 264     $ 333     $ 433     $ (597 )   $ 433  
 
(a)   All significant intercompany transactions have been eliminated in consolidation.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the 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/(expense), net
    3       (19 )     2             (14 )
Interest expense
    (66 )     (59 )     (172 )           (297 )
 
Total other income/(expense)
    70       73       704       (1,003 )     (156 )
 
Income/(Loss) 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.

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2009
                                         
            Non-                
    Guarantor   Guarantor   NRG Energy, Inc.           Consolidated
(In millions)   Subsidiaries   Subsidiaries   (Note Issuer)   Eliminations(a)   Balance
 
ASSETS
Current Assets
                                       
Cash and cash equivalents
  $ 20     $ 120     $ 2,164     $     $ 2,304  
Funds deposited by counterparties
    177                         177  
Restricted cash
    1       1                   2  
Accounts receivable-trade, net
    837       39                   876  
Inventory
    529       12                   541  
Derivative instruments valuation
    1,636                         1,636  
Cash collateral paid in support of energy risk management activities
    359       2                   361  
Prepayments and other current assets
    194       61       157       (101 )     311  
 
Total current assets
    3,753       235       2,321       (101 )     6,208  
 
Net Property, Plant and Equipment
    10,494       1,009       61             11,564  
 
Other Assets
                                       
Investment in subsidiaries
    613       222       16,862       (17,697 )      
Equity investments in affiliates
    42       367                   409  
Capital leases and note receivable, less current portion
    4,982       504       3,027       (8,009 )     504  
Goodwill
    1,718                         1,718  
Intangible assets, net
    1,755       20       33       (31 )     1,777  
Nuclear decommissioning trust fund
    367                         367  
Derivative instruments valuation
    718             8       (43 )     683  
Other non-current assets
    29       8       111             148  
 
Total other assets
    10,224       1,121       20,041       (25,780 )     5,606  
 
Total Assets
  $ 24,471     $ 2,365     $ 22,423     $ (25,881 )   $ 23,378  
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
                                       
Current portion of long-term debt and capital leases
  $ 58     $ 310     $ 261     $ (58 )   $ 571  
Accounts payable
    (852 )     393       1,156             697  
Derivative instruments valuation
    1,469       2       2             1,473  
Deferred income taxes
    456       11       (270 )           197  
Cash collateral received in support of energy risk management activities
    177                         177  
Accrued expenses and other current liabilities
    261       82       347       (43 )     647  
 
Total current liabilities
    1,569       798       1,496       (101 )     3,762  
 
Other Liabilities
                                       
Long-term debt and capital leases
    2,533       1,003       12,320       (8,009 )     7,847  
Nuclear decommissioning reserve
    300                         300  
Nuclear decommissioning trust liability
    255                         255  
Deferred income taxes
    1,711       (165 )     237             1,783  
Derivative instruments valuation
    323       28       79       (43 )     387  
Out-of-market contracts
    318       7             (31 )     294  
Other non-current liabilities
    431       16       359             806  
 
Total non-current liabilities
    5,871       889       12,995       (8,083 )     11,672  
 
Total liabilities
    7,440       1,687       14,491       (8,184 )     15,434  
 
3.625% Preferred Stock
                247             247  
Stockholders’ Equity
    17,031       678       7,685       (17,697 )     7,697  
 
Total Liabilities and Stockholders’ Equity
  $ 24,471     $ 2,365     $ 22,423     $ (25,881 )   $ 23,378  
 
(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 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     $ 630     $ (1,003 )   $ 630  
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/(used) by changes in other working capital, net of acquisition
    533       170       (941 )           (238 )
 
Net Cash Provided/(Used) by Operating Activities
    1,597       310       (525 )     (660 )     722  
 
Cash Flows from Investing Activities
                                       
Intercompany (loans to)/receipts 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)/Provided by Investing Activities
    (1,204 )     262       (299 )     741       (500 )
 
Cash Flows from Financing Activities
                                       
(Payments)/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) from financing element of acquired derivatives
    102       (124 )                 (22 )
Installment 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 Equivalent
    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.

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ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     As you read this discussion and analysis, refer to the Company’s Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and six months ended June 30, 2010, and 2009. Also refer to NRG’s Annual Report on Form 10-K for the year ended December 31, 2009, 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.

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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 provider in the ERCOT (Texas) market through Reliant Energy. 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 the supply of electricity and energy services to retail electricity customers in the Texas market.
     As of June 30, 2010, NRG had a total global generation portfolio of 187 active operating fossil fuel and nuclear generation units, at 44 power generation plants, with an aggregate generation capacity of approximately 23,985 MW, and approximately 255 MW under construction which includes partner interests of 125 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in operating renewable facilities with an aggregate generation capacity of 465 MW, consisting of four wind farms representing an aggregate generation capacity of 445 MW and a 20 MW solar facility. Within the United States, NRG has large and diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,980 MW of fossil fuel and nuclear generation capacity in 179 active generating units at 42 plants. The Company’s power generation facilities are most heavily concentrated in Texas (approximately 11,440 MW, including 445 MW from four wind farms), the Northeast (approximately 6,885 MW), South Central (approximately 2,855 MW), and West (approximately 2,150 MW, including 20 MW from a solar facility) regions of the United States, with approximately 115 MW of additional generation capacity from the Company’s thermal assets. In addition, through certain foreign subsidiaries, NRG has investments in power generation projects located in Australia and Germany with approximately 1,005 MW of generation capacity.
     NRG’s principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired, nuclear and renewable facilities, representing approximately 45%, 31%, 17%, 5% and 2% of the Company’s total domestic generation capacity, respectively. In addition, 9% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows those 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 the 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.
     Reliant Energy, the Company’s retail electricity provider, 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. Based on metered locations, as of June 30, 2010, Reliant Energy had approximately 1.5 million Mass customers and approximately 0.1 million C&I customers, with expected annual volumes for these customer classes of 20 TWhs and 25-30 TWhs, respectively.
     Furthermore, 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. These investments include low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, photovoltaic, biomass, “clean” coal and gasification, the retrofit of post-combustion carbon capture technologies, and developments in the electric vehicle ecosystem.
NRG’s Business Strategy
     NRG’s business strategy is intended to maximize shareholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the market’s increasing demand for sustainable and low carbon energy solutions. This dual strategy is designed to perfect the Company’s core business of competitive power generation and establish the Company as a leading provider of sustainable energy solutions, while utilizing the Company’s retail business to complement and advance both initiatives.

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     The Company’s core business is focused on: (i) top decile operating performance of its existing operating assets, (ii) optimal hedging of baseload and retail operations, while retaining optionality on the Company’s gas fleet, (iii) repowering of power generation assets at existing sites and reducing environmental impacts, (iv) pursuit of selective acquisitions, joint ventures, divestitures and investments, 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.
     In addition, the Company believes that success in providing energy solutions that address sustainability and climate change concerns will not only reduce the carbon and capital intensity of the Company in the future, it also will reduce the real and perceived linkage between the Company’s financial performance and prospects, and volatile commodity prices, particularly with respect to natural gas. The Company’s initiatives in this area of future growth are focused on: (i) low carbon baseload — primarily nuclear generation, (ii) renewables, with a concentration in solar and wind generation and development, (iii) fast start, high efficiency gas-fired capacity in the Company’s core regions, (iv) electric vehicle ecosystems, and (v) smart grid services. The Company’s advancements in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in the Company’s 2009 Annual Report on Form 10-K, the Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, and this Form 10-Q.
Environmental Matters
Environmental Regulatory Landscape
     A number of regulations that could significantly impact the power generation industry are in development or under review by the U.S. EPA: CAIR, MACT, NAAQS revisions, coal combustion byproducts, once-through cooling, and GHG regulations. While most of these regulations have been considered for some time, they are expected to gain clarity in 2010 through 2011. The timing and stringency of these regulations will provide a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. The Company has included capital to meet anticipated CAIR Phase I and II, CATR, MACT standards for mercury, and the installation of “Best Technology Available” under the 316(b) Rule in the current estimated environmental capital expenditure. While the Company cannot predict the impact of future regulations and would likely face additional investments over time, these expenditures, combined with the Company’s already existing air quality controls, use of Powder River Basin coal, closed cycle cooling, and dry ash handling systems position NRG well to meet more stringent requirements.
     The U.S. EPA released the proposed Clean Air Transport Rule, or CATR, on July 6, 2010. This rule is designed to replace CAIR and address the findings of the D.C. Court of Appeals that initially vacated the rule. It is designed to bring 31 states and D.C. into attainment with PM 2.5 and ozone national ambient air quality standards through emission reductions in SO2 and NOx. Proposed implementation would be through a cap and trade program starting in 2012 with constrained trading between states in the CATR regions. In 2014 the SO2 cap would be further reduced in certain states. Under CATR, CAIR use of discounted Acid Rain SO2 allowances would be discontinued and replaced with a completely distinct CATR SO2 allowance program. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain Program. NRG continues to evaluate the proposed rule and any impact it has to emission markets and currently estimates that the proposed rule, if it becomes effective, could result in up to a $50 million future impairment of the Company’s SO2 emission allowance intangible assets. NRG’s planned environmental capital expenditures are consistent with reductions anticipated in the rule.
     The New York State Department of Environmental Conservation finalized the NOx RACT Rule on July 14, 2010. This rule identifies new NOx emission limits for major sources which must be met by July 1, 2014. Plants can comply or request an alternate Reasonably Available Control Technology, or RACT, limit. All of NRG’s facilities are able to meet the new standards with the exception of Oswego, which will apply for an alternate limit.
     On May 4, 2010, the U.S. EPA proposed two options for the regulation of coal combustion residue, commonly known as coal ash. Under the Proposal’s first regulatory option, the U.S. EPA would reverse its August 1993 and May 2000 Bevill Regulatory Determinations and list coal ash as a special waste subject to regulation under hazardous waste regulations. The second regulatory option would leave the Bevill Determination in place and regulate disposal of coal ash as non-hazardous. Under both options, an exemption for the beneficial use of coal ash would remain in place. Additionally, under both options, the U.S. EPA would establish dam safety requirements to address the structural integrity of surface impoundments. While it is not possible to predict the impact of this rule until it is final, as proposed it is not expected to have a material impact on NRG’s operations, as all flyash disposal sites are dry landfills; however, should the U.S. EPA implement the hazardous waste option, NRG may incur significant costs due to loss of markets for beneficial reuse. Given the recent release of this proposed rule, NRG will continue to monitor developments and their respective impact on the Company’s operations.

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     On May 4, 2010, the California State Water Resources Control Board adopted a statewide 316(b) policy to mitigate once through cooling in California. Options for power plants with once through cooling include transitioning to a closed loop system, retirement or submitting an alternative plan that meets equivalent mitigation criteria. Specified compliance dates for NRG’s El Segundo and Encina Power Plants are December 31, 2015, and December 31, 2017, respectively. NRG is analyzing compliance through a mix of alternative mitigation plans and repowering.
     In June 2010, the U.S. EPA issued a Section 308 Information Collection Request to steam electric power generating plants across the industry, including 13 NRG facilities. The questionnaire focuses on water and wastewater discharges from power plants. The U.S. EPA indicated results will be used to develop new effluent guidelines for the industry.
     Finalization of the Endangerment Finding, a rule addressing tailpipe limitations for light duty vehicles, and a final interpretation of the Johnson Memorandum set the stage for regulation of GHGs from stationary sources. On June 3, 2010, the U.S. EPA published the final rule tailoring the applicability criteria that determine which new and modified sources will become subject to permitting requirements for GHGs under the Prevention of Significant Deterioration, or PSD and Title V programs of the Clean Air Act. The rule raised applicability triggers to 75,000 or 100,000 tons per year CO2 equivalents, or CO2e, and implemented the requirements in two phases on January 2, 2011 or July 2, 2011. The immediate impact to NRG’s new and modified facilities is not expected to be material; the Company will continue to evaluate the potential long-term impact as regulatory programs are implemented over time.
Climate Change Legislation
     In 2009, in the course of producing approximately 71 million MWh of electricity, NRG’s power plants emitted 59 million tonnes of CO2, of which 53 million tonnes were emitted in the United States, 3 million tonnes in Germany and 3 million tonnes in Australia. During the same period, NRG emitted approximately 8 million tons of CO2 in the RGGI region. The impact from legislation or federal, regional or state regulation of GHGs on the Company’s financial performance will depend on a number of factors, including the overall level of GHG reductions required under any such regulations, the price and availability of offsets, 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, under any such legislation or regulation, the impact on NRG would depend on the Company’s level of success in developing and deploying low and no carbon technologies such as those being pursued as discussed in the above.
     Congress has been unable to come to an agreement on climate legislation during this session. Lack of legislation will prolong the uncertainty of the nature and timing of GHG requirements and their resulting impact on NRG.
Regulatory Matters
     As operators of power plants and participants in wholesale energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the U.S. Commodity Futures Trading Commission, or CFTC, FERC, U.S. Nuclear Regulatory Commission, or NRC, PUCT and other public utility commissions in certain states where NRG’s generating or thermal assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which it participates. Certain of the Reliant Energy entities are competitive Retail Electric Providers, or REPs, and as such are subject to the rules and regulations of the PUCT governing REPs. NRG must also comply with the mandatory reliability requirements imposed by the North American Electric Reliability Corporation, or NERC, and the regional reliability councils in the regions where the Company operates. The operations of, and wholesale electric sales from, NRG’s Texas region are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce.
     Financial Reform — On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which, among other things, aims to improve transparency and accountability in derivative markets. While the Dodd-Frank Act increases the CFTC’s regulatory authority over over-the-counter derivatives, there is uncertainty on several issues related to market clearing, definitions of market participants, reporting, and capital requirements. Thus, while many details remain to be addressed in CFTC rulemaking proceedings, at this time the Company does not anticipate any material impact to its current hedging collateral strategy. NRG’s view is informed by a letter dated June 30, 2010 from Senate Banking Committee Chairman Dodd and Senate Agriculture Committee Chairman Lincoln clarifying that the legislative intent of the Dodd-Frank Act is not to impose margin requirements on end users that use swaps to hedge or mitigate commercial risks.

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     New England — On February 22, 2010, ISO-NE filed proposed amendments to its Forward Capacity Market, or FCM, design with FERC. A number of generators protested the ISO-NE filing, arguing that FERC should not accept the proposed amendments. On March 23, 2010, an association of generators filed a complaint alleging that the proposed FCM amendments are not just and reasonable due to market distortions such as out-of-market contracts, and thus would continue to under-compensate capacity suppliers in New England. On April 2, 2010, NRG and PSEG jointly filed a second complaint alleging that the existing FCM market fails to adequately establish zonal prices and thus does not adequately compensate suppliers for the locational value of their capacity. These complaints are seeking only prospective relief. Any changes to the FCM market in response to these complaints could benefit from the Company’s existing New England assets in future FCM auctions. On April 23, 2010, FERC issued an order consolidating the proceedings. In its order, FERC accepted some of the ISO-NE’s proposed changes, but also set several of the central issues for hearing and settlement processes.
     California — On May 4, 2010, the U.S. Court of Appeals for the D.C. Circuit in Southern California Edison Company v. FERC vacated FERC’s acceptance of station power rules for the CAISO market, and remanded the case for further proceedings at FERC. As a result of the court’s decision, NRG’s power plants may be prevented from netting their station power consumption against their sales on a monthly basis in the California markets, which could require NRG to purchase station power at retail rates. Additionally, the precedent announced in this case may affect station power tariffs in other markets.
Changes in Accounting Standards
     See Note 2, Summary of Significant Accounting Policies, to this Form 10-Q as found in Item 1 for a discussion of recent accounting developments.

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Consolidated Results of Operations
     The following table provides selected financial information for the Company:
                                                 
    Three months ended June 30,   Six months ended June 30,
(In millions except otherwise noted)   2010   2009   Change %   2010   2009   Change %
 
Operating Revenues
                                               
Energy revenue
  $ 605     $ 725       (17 )%   $ 1,283     $ 1,612       (20 )%
Capacity revenue
    206       253       (19 )     417       513       (19 )
Retail revenue
    1,341       1,250       7       2,586       1,250       107  
Risk management activities
    (2 )     (12 )     83       89       425       (79 )
Contract amortization
    (52 )     (53 )     2       (114 )     (32 )     (256 )
Thermal revenue
    20       21       (5 )     48       55       (13 )
Other revenues
    15       53       (72 )     39       72       (46 )
 
Total operating revenues
    2,133       2,237       (5 )     4,348       3,895       12  
 
Operating Costs and Expenses
                                               
Cost of sales
    1,129       1,175       (4 )     2,318       1,628       42  
Risk management activities
    (84 )     (204 )     59       51       (136 )     138  
Other cost of operations
    284       271       5       599       516       16  
 
Total cost of operations
    1,329       1,242       7       2,968       2,008       48  
Depreciation and amortization
    208       213       (2 )     410       382       7  
Selling, general and administrative
    139       131       6       269       214       26  
Acquisition-related transaction and integration costs
          23       (100 )           35       (100 )
Development costs
    13       9       44       22       22        
 
Total operating costs and expenses
    1,689       1,618       4       3,669       2,661       38  
Gain on sale of assets
                      23              
 
Operating income
    444       619       (28 )     702       1,234       (43 )
Other Income/(Expense)
                                               
Equity in earnings of unconsolidated affiliates
    11       5       120       25       27       (7 )
Gain on sale of equity method investments
          128       (100 )           128       (100 )
Other income/(expense), net
    19       (11 )     273       23       (14 )     264  
Interest expense
    (147 )     (159 )     (8 )     (300 )     (297 )     1  
 
Total other expense
    (117 )     (37 )     216       (252 )     (156 )     62  
 
Income before income tax expense
    327       582       (44 )     450       1,078       (58 )
Income tax expense
    117       150       (22 )     182       448       (59 )
 
Net Income
    210       432       (51 )     268       630       (57 )
 
Less: Net loss attributable to noncontrolling interest
    (1 )     (1 )           (1 )     (1 )      
 
Net income attributable to NRG Energy, Inc.
  $ 211     $ 433       (51 )   $ 269     $ 631       (57 )
 
Business Metrics
                                               
 
Average natural gas price — Henry Hub
($/MMBtu)
    4.09       3.68       11 %     4.69       4.13       14 %
 

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Management’s discussion of the results of operations for the three months ended June 30, 2010, and 2009:
     The table below represents the results of NRG excluding the impact of Reliant Energy, and adjusted for intercompany transactions between Reliant Energy and the Texas region, during the three months ended June 30, 2010, and 2009:
                                                                 
    2010   2009
            Reliant           Total excluding           Reliant           Total excluding
(In millions)   Consolidated   Energy   Eliminations   Reliant Energy   Consolidated   Energy(a)   Eliminations   Reliant Energy
 
Operating Revenues
                                                               
Energy revenue
  $ 605     $     $ 284     $ 889     $ 725     $     $ 54     $ 779  
Capacity revenue
    206             3       209       253             11       264  
Retail revenue
    1,341       1,341                   1,250       1,250              
Risk management activities
    (2 )           (19 )     (21 )     (12 )           2       (10 )
Contract amortization
    (52 )     (59 )           7       (53 )     (75 )           22  
Thermal revenue
    20                   20       21                   21  
Other revenues
    15             13       28       53             2       55  
 
Total operating revenues
    2,133       1,282       281       1,132       2,237       1,175       69       1,131  
Operating Costs and Expenses
                                                               
Cost of sales
    1,129       937       300       492       1,175       803       71       443  
Risk management activities
    (84 )     (76 )     (19 )     (27 )     (204 )     (189 )     (2 )     (17 )
Other operating costs
    284       49             235       271       41             230  
 
Total cost of operations
    1,329       910       281       700       1,242       655       69       656  
Depreciation and amortization
    208       29             179       213       43             170  
Selling, general and administrative
    139       64             75       131       49             82  
Acquisition-related transaction and integration costs
                            23                   23  
Development costs
    13                   13       9                   9  
 
Total operating costs and expenses
    1,689       1,003       281       967       1,618       747       69       940  
 
Operating income
  $ 444     $ 279     $     $ 165     $ 619     $ 428     $     $ 191  
 
(a)   Reliant Energy results are for the period May 1, 2009, to June 30, 2009.
Operating Revenues
     Operating revenues, excluding risk management activities, decreased by $114 million during the three months ended June 30, 2010, compared to the same period in 2009.
   
Retail revenue — increased by $91 million. This increase was driven by $354 million of revenue for the month of April included in 2010, which was offset by a decrease of $263 million from Mass, C&I and supply management revenues during the two month period ended June 30 2010, as compared to 2009. Mass revenues decreased by $143 million due to 12% lower revenue rates and 8% lower volumes due to fewer customers. C&I revenues decreased by $86 million due to 17% lower volumes driven by fewer customers.
 
   
Energy revenue — including intercompany revenue, increased $110 million during the three months ended June 30, 2010, compared to the same period in 2009:
  o  
Texas — increased by $64 million with $66 million increase driven by higher energy prices and an increase in margin on megawatt hours sold from market purchases of $12 million, offset by a $13 million decrease driven by reduction in generation. The average realized energy price increased by 11%, driven by a 14% increase in merchant prices and a 3% increase in contract prices. Intercompany sales to Reliant Energy, which eliminate in consolidation, were $284 million, an increase of $230 million over the two month period in 2009. Generation decreased by 2%, driven by an 18% decrease in nuclear plant generation and a 6% decrease in gas plant generation. The decrease in nuclear plant generation is due to an STP Unit 2 spring refueling outage in 2010. These decreases were offset by an increase in wind farm generation as Langford began commercial operation in December 2009.

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  o  
Northeast — increased by $36 million, with $32 million driven by higher energy prices and $4 million driven by 3% higher generation. Merchant energy prices were higher by an average of 50%. The increase in oil and gas generation is attributable to higher reliability run hours at the Connecticut plants.
 
  o  
South Central — increased by $15 million due to a $19 million increase in contract revenue offset by a decrease of $4 million in merchant energy revenues. The increase in contract energy price was driven by a $6 million increase in fuel cost pass-through from the cooperatives and a $12 million increase due to a new contract with a regional municipality. Total megawatt hour sales to the region’s contract customers were up 13% while the average realized price on contract energy sales was $27.77 per MWh in 2010 compared to $22.98 per MWh in 2009. Megawatt hours sold to the merchant market increased by 26% but lower realized merchant prices resulted in a decrease of $4 million.
   
Capacity revenue — including intercompany revenue, decreased $55 million during the three months ended June 30, 2010, compared to the same period in 2009:
  o  
Texas — decreased by $42 million resulting from a lower proportion of baseload contracts which contain a capacity component. Intercompany sales to Reliant Energy, which eliminate in consolidation, decreased by $8 million.
 
  o  
South Central — decreased by $7 million primarily due to expiration of a capacity agreement with a regional utility.
   
Contract amortization revenue — decreased by $1 million during the three months ended June 30, 2010, as compared to the same period in 2009. The contract amortization expense decreased by $16 million at Reliant Energy offset by a $15 million reduction in contract amortization revenue in the Texas region due to the lower volume of contracted energy.
   
Other revenues — decreased by $38 million during the three months ended June 30, 2010, as compared to the same period in 2009, driven by $7 million in lower emissions revenues and a $31 million non-cash gain related to the settlement of pre-existing in-the-money contracts with Reliant Energy recognized in 2009. The Texas region’s intercompany ancillary sales to Reliant Energy, which eliminate in consolidation, were $13 million, an increase of $12 million over the two month period in 2009.
Cost of Operations
Cost of operations, excluding risk management activities, decreased by $33 million during the three months ended June 30, 2010, compared to the same period in 2009.
   
Cost of sales — including intercompany purchases, decreased $46 million during the three months ended June 30, 2010, compared to the same period in 2009 due to:
  o  
Retail — increased by $134 million, with $280 million of costs for the month of April included in 2010. This increase was offset by a $151 million decrease in supply costs and by a $26 million decrease in transmission and distribution charges for the two month period ended June 30, 2010, as compared to 2009. Intercompany purchases from the Texas region, which eliminate in consolidation, were $300 million, an increase of $229 million over the two month period in 2009.
 
  o  
Texas — increased $25 million due to higher coal costs and ancillary services costs offset by a decrease in natural gas costs and purchased energy. Coal costs increased $23 million due to higher transportation charges.
 
  o  
Northeast — increased $24 million driven by a $13 million increase in natural gas and oil costs, an $8 million increase in purchased energy and a $4 million increase in coal costs. Natural gas and oil costs increased due to 20% higher generation and 37% higher average natural gas prices. Purchased energy increased due to costs to supply new load contracts which commenced on June 1, 2010. Coal costs increased due to 52% higher average prices offset by 1% lower coal generation.
   
Other costs of operations — increased $13 million during the three months ended June 30, 2010, compared to the same period in 2009. Maintenance expenses in the Texas and South Central regions increased by $24 million due to planned baseload outages which was offset by a decrease of $16 million in the Northeast region due to lower property tax expense and lower operations and maintenance expenses.

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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 $110 million during the three months ended June 30, 2010, compared to the same period in 2009. The breakdown of changes by region are as follows:
                                                                 
    Three months ended June 30, 2010
    Reliant                   South                
    Energy   Texas   Northeast   Central   West   Thermal   Elimination   Total
    (In millions)
Net gains/(losses) on settled positions
  $ (88 )   $ 69     $ 44     $ (8 )   $ 1     $ 2     $     $ 20  
 
Mark-to-market gains/(losses)
    163       (57 )     (55 )     10       2       (1 )           62  
 
Total derivative gains/(losses) included in revenues and cost of operations
  $ 75     $ 12     $ (11 )   $ 2     $ 3     $ 1     $     $ 82  
 
                                                                 
    Three months ended June 30, 2009
    Reliant                   South                
    Energy(a)   Texas   Northeast   Central   West   Thermal   Elimination   Total
    (In millions)
Net gains/(losses) on settled positions
  $ (114 )   $ 101     $ 95     $ (5 )   $ (1 )   $ 1     $     $ 77  
 
Mark-to-market gains/(losses)
    303       (144 )     (34 )     (15 )     7       (2 )           115  
 
Total derivative gains/(losses) included in revenues and cost of operations
  $ 189     $ (43 )   $ 61     $ (20 )   $ 6     $ (1 )   $     $ 192  
 
(a)   Reliant Energy results are for the period May 1, 2009, to June 30, 2009.
     The breakdown of gains and losses included in revenue and cost of operations by region are as follows:
                                                                 
    Three months ended June 30, 2010
    Reliant                   South                
    Energy   Texas   Northeast   Central   West   Thermal   Elimination (a)   Total
    (In millions)
Net gains/(losses) on settled positions, or financial income in revenues
  $     $ 70     $ 44     $ (8 )   $ 1     $ 2     $ (28 )   $ 81  
 
Mark-to-market results in revenues
                                                               
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
          (16 )     (34 )     1             (1 )     2       (48 )
Reversal of previously recognized unrealized losses on settled positions related to trading activity
          7             1                         8  
Net unrealized (losses)/gains on open positions related to economic hedges
          (66 )     (28 )     (4 )     1             45       (52 )
Net unrealized gains on open positions related to trading activity
          2       3       3       1                   9  
 
Subtotal mark-to-market results
          (73 )     (59 )     1       2       (1 )     47       (83 )
 
Total derivative (losses)/gains included in revenues
  $     $ (3 )   $ (15 )   $ (7 )   $ 3     $ 1     $ 19     $ (2 )
 
(a)   Represents the elimination of $19 million intercompany loss in the Texas region. The offsetting intercompany gain is included in cost of operations in the Reliant Energy region.

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    Three months ended June 30, 2009
    Reliant                   South                
    Energy(a)   Texas   Northeast   Central   West   Thermal   Elimination(b)   Total
    (In millions)
Net gains/(losses) on settled positions, or financial income in revenues
  $     $ 105     $ 96     $ (2 )   $ (1 )   $ 1     $     $ 199  
 
Mark-to-market results in revenues
                                                               
Reversal of previously recognized unrealized gains on settled positions related to economic hedges
          (16 )     (32 )                 (1 )           (49 )
Reversal of previously recognized unrealized gains on settled positions related to trading activity
          (14 )     (9 )     (12 )                       (35 )
Net unrealized (losses)/gains on open positions related to economic hedges
          (119 )     (9 )     (4 )     7       (1 )     (2 )     (128 )
Net unrealized (losses)/gains on open positions related to trading activity
          (10 )     5       6                         1  
 
Subtotal mark-to-market results
          (159 )     (45 )     (10 )     7       (2 )     (2 )     (211 )
 
Total derivative (losses)/gains included in revenues
  $     $ (54 )   $ 51     $ (12 )   $ 6     $ (1 )   $ (2 )   $ (12 )
 
(a)   Reliant Energy results are for the period May 1, 2009, to June 30, 2009.
 
(b)  
Represents the elimination of $2 million intercompany gain in the Texas region. The offsetting intercompany loss is included in cost of operations in the Reliant Energy region.
                                                 
    Three months ended June 30, 2010
    Reliant                   South        
    Energy   Texas   Northeast   Central   Elimination(a)   Total
    (In millions)
Net (losses)/gains on settled positions, or financial expense in cost of operations
  $ (88 )   $ (1 )   $     $     $ 28     $ (61 )
 
Mark-to-market results in cost of operations
                                               
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
    (17 )     8       4       4       (2 )     (3 )
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009
    60                               60  
Net unrealized gains/(losses) on open positions related to economic hedges
    120       8             5       (45 )     88  
 
Subtotal mark-to-market results
    163       16       4       9       (47 )     145  
 
Total derivative gains/(losses) included in cost of operations
  $ 75     $ 15     $ 4     $ 9     $ (19 )   $ 84  
 
(a)  
Represents the elimination of $19 million intercompany gains in the Reliant Energy region. The offsetting intercompany loss is included in revenue in the Texas region.
                                                 
    Three months ended June 30, 2009
    Reliant                   South        
    Energy(a)   Texas   Northeast   Central   Elimination(b)   Total
    (In millions)
Net losses on settled positions, or financial expense in cost of operations
  $ (114 )   $ (4 )   $ (1 )   $ (3 )   $     $ (122 )
 
Mark-to-market results in cost of operations
                                               
Reversal of previously recognized unrealized losses on settled positions related to economic hedges
          12       19                   31  
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009
    210                               210  
Net unrealized gains/(losses) on open positions related to economic hedges
    93       3       (8 )     (5 )     2       85  
 
Subtotal mark-to-market results
    303       15       11       (5 )     2       326  
 
Total derivative gains/(losses) included in cost of operations
  $ 189     $ 11     $ 10     $ (8 )   $ 2     $ 204  
 
(a)  
Reliant Energy results are for the period May 1, 2009, to June 30, 2009.
 
(b)  
Represents the elimination of $2 million intercompany loss in the Reliant Energy region. The offsetting intercompany gain is included in revenue in the Texas region.

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     For the three months ended June 30, 2010, the $52 million loss in revenue from economic hedge positions is primarily driven by a decrease in value of forward sales of natural gas and electricity due to an increase in forward power and gas prices. The $88 million gain in cost of energy from economic hedge positions is primarily driven by an increase in value of forward purchases of natural gas, electricity and fuel due to an increase in forward power and gas prices. Reliant Energy’s $60 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in cost of operations during the same period.
     For the period ended June 30, 2009, the $128 million mark-to-market loss in revenue related to a decrease in value in forward sales of electricity and fuel relating to economic hedges due to an increase in forward power and gas prices. The $85 million mark-to-market gain in expense related to economic hedges was due to an increase in forward purchases of electricity and natural gas relating to retail supply, due to an increase in forward power and gas prices.
     In accordance with ASC 815, the following table represents the results of the Company’s financial and physical trading of energy commodities for the three months ended June 30, 2010, and 2009. 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. The Company’s trading activities are subject to limits within the Company’s Risk Management Policy.
                 
    Three months
    ended June 30,
(In millions)   2010   2009
 
Trading gains/(losses)
               
Realized
  $ (13 )   $ 26  
Unrealized
    17       (34 )
 
Total trading gains/(losses)
  $ 4     $ (8 )
 
Depreciation and Amortization
     NRG’s depreciation and amortization expense decreased by $5 million for the three months ended June 30, 2010, compared to the same period in 2009. Depreciation and amortization expense for Reliant Energy decreased by $14 million mainly due to reduction in amortization of customer relationships. This decrease was offset by a $9 million increase in depreciation related to baghouse projects in western New York, Cedar Bayou 4 project which began operations in June 2009 and Langford which began commercial operations in December 2009.
Selling, General and Administrative Expenses
     Selling, general and administrative expenses increased by $8 million during the three months ended June 30, 2010, compared to the same period in 2009. The increase was due to:
    Retail selling, general and administrative expense — increased by $15 million due to inclusion of month of April in 2010.
This increase was offset by:
   
Consultant costs — decreased due to $5 million non-recurring costs related to Exelon’s exchange offer and proxy contest efforts incurred in 2009.
Acquisition-related Transaction and Integration Costs
     NRG incurred Reliant Energy acquisition-related transaction and integration costs of $23 million for the three months ended June 30, 2009. These integration efforts were completed by the end of 2009.

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Equity in Earnings of Unconsolidated Affiliates
     NRG’s equity earnings from unconsolidated affiliates increased by $6 million during the three months ended June 30, 2010, compared to the same period in 2009, primarily from an increase in equity earnings from Sherbino.
Gain on Sale of Equity Method Investments
     NRG’s gain on sale of equity method investments in 2009 represents a $128 million gain on the sale of NRG’s 50% ownership interest in MIBRAG.
Other Income/(Expense), Net
     NRG’s other income/(expense), net increased $30 million during the three months ended June 30, 2010, compared to the same period in 2009. The 2010 amount includes $3 million and $9 million of unrealized and realized foreign exchange gains, respectively. The 2009 amount includes a $15 million loss on a forward contract for foreign currency executed to hedge the MIBRAG sale proceeds.
Interest Expense
     NRG’s interest expense decreased by $12 million during the three months ended June 30, 2010, compared to the same period in 2009. This decrease was due to $7 million related to the settlement of the CSF Debt in 2009 and early 2010, a $12 million decrease in fees on the CSRA facility, a $4 million decrease due to a lower outstanding principal balance on the Term Loan Facility, and $2 million due to lower interest rates related to the unhedged portion of the Term Loan. These decreases were offset by a $10 million increase in interest expense related to the issuance of the 2019 Senior Notes in June 2009.
Income Tax Expense
     NRG’s income tax expense decreased by $33 million during the three months ended June 30, 2010, compared to the same period in 2009. The decrease in income tax expense was primarily due to a decrease in income. The effective tax rate was 35.8% and 25.8% for the three months ended June 30, 2010, and 2009, respectively.
     For the three months ended June 30, 2010, NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes as well as recording federal and state tax expense and interest for unrecognized tax benefits. For the three months ended June 30, 2009, NRG’s effective tax rate was different than the statutory rate of 35% primarily due to a net state and local income tax benefit as a result of the Reliant Energy acquisition, and the sale of the MIBRAG facility.

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Management’s discussion of the results of operations for the six months ended June 30, 2010, and 2009:
     The table below represents the results of NRG excluding the impact of Reliant Energy, and adjusted for intercompany transactions between Reliant Energy and the Texas region, during the six months ended June 30, 2010 and 2009:
                                                                 
    2010   2009
            Reliant           Total excluding           Reliant           Total excluding
(In millions)   Consolidated   Energy   Eliminations   Reliant Energy   Consolidated   Energy(a)   Eliminations   Reliant Energy
 
Operating Revenues
                                                               
Energy revenue
  $ 1,283     $     $ 484     $ 1,767     $ 1,612     $     $ 54     $ 1,666  
Capacity revenue
    417             7       424       513             11       524  
Retail revenue
    2,586       2,586                   1,250       1,250              
Risk management activities
    89             125       214       425             2       427  
Contract amortization
    (114 )     (128 )           14       (32 )     (75 )           43  
Thermal revenue
    48                   48       55                   55  
Other revenues
    39             26       65       72             2       74  
 
Total operating revenues
    4,348       2,458       642       2,532       3,895       1,175       69       2,789  
Operating Costs and Expenses
                                                               
Cost of sales
    2,318       1,843       516       991       1,628       803       71       896  
Risk management activities
    51       248       125       (72 )     (136 )     (189 )     (2 )     51  
Other operating costs
    599       94       1       506       516       41             475  
 
Total cost of operations
    2,968       2,185       642       1,425       2,008       655       69       1,422  
Depreciation and amortization
    410       59             351       382       43             339  
Selling, general and administrative
    269       122             147       214       49             165  
Acquisition-related transaction and integration costs
                            35                   35  
Development costs
    22                   22       22                   22  
 
Total operating costs and expenses
    3,669       2,366       642       1,945       2,661       747       69       1,983  
 
Gain on sale of assets
    23                   23                          
 
Operating income
  $ 702     $ 92     $     $ 610     $ 1,234     $ 428     $     $ 806  
 
(a)   Reliant Energy results are for the period May 1, 2009, to June 30, 2009.
Operating Revenues
     Operating revenues, excluding risk management activities, increased $789 million during the six months ended June 30, 2010, compared to the same period in 2009.
   
Retail revenue — for the six months ended June 30, 2010, were $2.6 billion consisting of $1.5 billion in Mass revenues and $991 million in C&I revenues. Retail revenues for the two months ended 2009 were $1.3 billion consisting of $761 million in Mass revenues and $437 million in C&I revenues.
 
   
Energy revenue — including intercompany revenue, increased $101 million during the six months ended June 30, 2010, compared to the same period in 2009:
  o  
Texas — increased by $98 million, with $56 million driven by higher energy prices, $10 million driven by margin on megawatt hours sold from market purchases and $31 million driven by an increase in generation. The average realized energy price increased by 5%, driven by a 1% increase in merchant prices and a 3% increase in contract prices. Intercompany sales to Reliant Energy, which eliminate in consolidation, were $484 million, an increase of $430 million over the two month period in 2009. Generation increased by 3%, driven by a 17% increase in gas plant generation and an increase in wind farm generation. Wind farm generation increased due to Langford, which began commercial operations in December 2009, and leased wind farm generation, which increased due to four additional months included in 2010. These increases were offset by a 13% decrease in nuclear plant generation due to planned outages.

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  o  
Northeast — decreased by $24 million, with $7 million driven by lower energy prices, $13 million driven by a reduction in generation, and $12 million of margin on a load contract which expired in May 2009, offset by an $8 million increase driven by new load-serving contracts, which commenced June 1, 2010. Merchant energy prices were lower by an average of 4%. Generation decreased by 5%, with a 19% decrease in oil and gas generation and a 2% decrease in coal generation. The decline in oil and gas generation is attributable to both planned and forced outages at Arthur Kill, Middletown and Oswego in 2010, offset by an increase due to higher reliability run hours at the Connecticut plants.
 
  o  
South Central — increased by $25 million due to a $31 million increase in contract revenue offset by a $6 million decrease in merchant energy revenues. Of the $31 million increase, $18 million is attributable to the region’s cooperative customers. Also contributing to the increase in contract revenue was $12 million due to a new contract with a regional municipality. Average realized price on contract energy sales was down $1.75 per MWh in 2010 compared to 2009. Megawatt hours sold to the merchant market decreased by 5%.
   
Capacity revenue — including intercompany revenue, decreased $100 million during the six months ended June 30, 2010, compared to the same period in 2009:
  o  
Texas — decreased by $82 million due to a lower proportion of baseload contracts which contain a capacity component. Intercompany sales to Reliant Energy, which eliminate in consolidation, decreased by $4 million.
 
  o  
Northeast — increased by $8 million, due to a $21 million increase in capacity revenue in the NYISO and PJM markets driven by higher prices offset by a $13 million decrease in NEPOOL capacity driven by the expiration of RMR contracts for Montville, Middletown and Norwalk in 2010.
 
  o  
South Central — decreased by $18 million due to the expiration of a capacity agreement with a regional utility.
 
  o  
West — decreased by $7 million due to reduced resource adequacy and call option contract sales at El Segundo in 2010 compared to 2009.
   
Contract amortization revenue — decreased by $82 million during the six months ended June 30, 2010, as compared to the same period in 2009. The decrease includes $52 million of amortization revenue for net in-market C&I contracts related to the Reliant Energy acquisition in May 2009 and a reduction of $28 million in amortization revenue in the Texas region due to the lower volume of contracted energy.
 
   
Other revenues — decreased by $33 million during the six months ended June 30, 2010, as compared to the same period in 2009. The decrease was driven by $14 million in lower emissions revenues in 2010 and a $31 million non-cash gain related to the settlement of pre-existing in-the-money contracts with Reliant Energy recognized in 2009. These decreases were offset by a $9 million increase in ancillary revenue. The Texas region’s intercompany ancillary sales to Reliant Energy, which eliminate in consolidation, were $25 million, an increase of $24 million over the two month period in 2009.
Cost of Operations
Cost of operations, excluding risk management activities, increased $773 million during the six months ended June 30, 2010, compared to the same period in 2009.
   
Cost of sales — including intercompany purchases, increased $690 million during the six months ended June 30, 2010, compared to the same period in 2009 due to:
  o  
Retail — Cost of energy for the six months ended June 30, 2010, was $1.8 billion consisting of $1.2 billion in supply costs and $634 million in transmission and distribution charges. Cost of energy for the two months ended June 30, 2009 was $803 million consisting of $550 million in supply costs and $267 million in transmission and distribution charges. Intercompany purchases from the Texas region, which eliminate in consolidation, were $516 million, an increase of $445 million over the two month period in 2009.

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  o  
Texas — increased $98 million due to higher coal and natural gas costs, ancillary services costs and purchased energy. Coal costs increased by $40 million due to a $30 million increase in transportation cost, and a $15 million due to higher prices offset by a $9 million decrease due to reduced generation. Natural gas costs increased $22 million, reflecting a 23% increase in average natural gas per MMBtu prices and a 17% increase in gas-fired generation. Ancillary service costs increased by $18 million due to an increase in purchased ancillary costs incurred to meet contract obligations. Purchased energy increased by $14 million due to a higher average price and a greater number of megawatt hours purchased to meet obligations when baseload plants are not available.
 
  o  
South Central — increased by $10 million due to an $11 million increase in purchased energy offset by $4 million decrease in coal costs due to a 1% reduction in coal generation.
   
Other costs of operations — increased $83 million during the six months ended June 30, 2010, compared to the same period in 2009. Other costs of operations for Reliant Energy increased by $53 million due to the additional four months included in 2010. Also, maintenance expenses in the Texas and South Central regions increased by $42 million due to planned baseload outages offset by a $17 million decrease in the Northeast region mainly due to lower spending at the Indian River and Arthur Kill plants, which completed a major outage project in the second quarter of 2009.
  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 $523 million during the six months ended June 30, 2010, compared to the same period in 2009. The breakdown of changes by region follows:
                                                                 
    Six months ended June 30, 2010
    Reliant                   South                
    Energy   Texas   Northeast   Central   West   Thermal   Elimination   Total
    (In millions)
Net (losses)/gains on settled positions
  $ (123 )   $ 77     $ 77     $ (21 )   $ 1     $ 3     $     $ 14  
Mark-to-market (losses)/gains
    (125 )     170       (30 )     8       3       (2 )           24  
 
Total derivative (losses)/gains included in revenues and cost of operations
  $ (248 )   $ 247     $ 47     $ (13 )   $ 4     $ 1     $     $ 38  
 
                                                                 
    Six months ended June 30, 2009
    Reliant                   South                
    Energy(a)   Texas   Northeast   Central   West   Thermal   Elimination   Total
    (In millions)
Net (losses)/gains on settled positions
  $ (114 )   $ 130     $ 151     $ 5     $ (3 )   $ 2     $     $ 171  
Mark-to-market gains/(losses)
    303       25       97       (40 )     6       (1 )           390  
 
Total derivative gains/(losses) included in revenues and cost of operations
  $ 189     $ 155     $ 248     $ (35 )   $ 3     $ 1     $     $ 561  
 
(a)   Reliant Energy results are for the period May 1, 2009, to June 30, 2009.

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     The breakdown of gains and losses included in revenue and cost of operations by region are as follows:
                                                                 
    Six months ended June 30, 2010
    Reliant                   South                
    Energy   Texas   Northeast   Central   West   Thermal   Elimination(a)   Total
    (In millions)
Net gains/(losses) on settled positions, or financial income in revenues
  $     $ 79     $ 77     $ (20 )   $ 1     $ 3     $ (37 )   $ 103  
 
Mark-to-market results in revenues
                                                               
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
          (53 )     (58 )     1             (2 )     (9 )     (121 )
Reversal of previously recognized unrealized losses on settled positions related to trading activity
          20       3       3                         26  
Net unrealized gains/(losses) on open positions related to economic hedges
          156       2       (22 )     1             (79 )     58  
Net unrealized gains on open positions related to trading activity
          7       8       6       2                   23  
 
Subtotal mark-to-market results
          130       (45 )     (12 )     3       (2 )     (88 )     (14 )
 
Total derivative gains/(losses) included in revenues
  $     $ 209     $ 32     $ (32 )   $ 4     $ 1     $ (125 )   $ 89  
 
(a)  
Represents the elimination of $125 million intercompany gain in the Texas region. The offsetting intercompany loss is included in cost of operations in the Reliant Energy region.
                                                                 
    Six months ended June 30, 2009
    Reliant                   South                
    Energy(a)   Texas   Northeast   Central   West   Thermal   Elimination(b)   Total
    (In millions)
Net gains/(losses) on settled positions, or financial income in revenues
  $     $ 143     $ 156     $ 11     $ (3 )   $ 2     $     $ 309  
 
Mark-to-market results in revenues
                                                               
Reversal of previously recognized unrealized gains on settled positions related to economic hedges
          (37 )     (63 )                 (2 )           (102 )
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
          154       159       (4 )     6       1       (2 )     314  
Net unrealized gains/(losses) on open positions related to trading activity
          (8 )     4       12                         8  
 
Subtotal mark-to-market results
          66       77       (30 )     6       (1 )     (2 )     116  
 
Total derivative gains/(losses) included in revenues
  $     $ 209     $ 233     $ (19 )   $ 3     $ 1     $ (2 )   $ 425  
 
(a)  
Reliant Energy results are for the period May 1, 2009, to June 30, 2009.
 
(b)  
Represents the elimination of $2 million intercompany gain in the Texas region. The offsetting intercompany loss is included in cost of operations in the Reliant Energy region.

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    Six months ended June 30, 2010
    Reliant                   South        
    Energy   Texas   Northeast   Central   Elimination(a)   Total
    (In millions)
Net gains/(losses) on settled positions, or financial expense in cost of operations
  $ (123 )   $ (2 )   $     $ (1 )   $ 37     $ (89 )
 
Mark-to-market results in cost of operations
                                               
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
    (20 )     23       9       9       9       30  
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009
    150                               150  
Net unrealized gains/(losses) on open positions related to economic hedges
    (255 )     17       6       11       79       (142 )
 
Subtotal mark-to-market results
    (125 )     40       15       20       88       38  
 
Total derivative (losses)/gains included in cost of operations
  $ (248 )   $ 38     $ 15     $ 19     $ 125     $ (51 )
 
(a)  
Represents the elimination of $125 million intercompany loss in the Reliant Energy region. The offsetting intercompany gain is included in revenue in the Texas region.
                                                 
    Six months ended June 30, 2009
    Reliant                   South        
    Energy(a)   Texas   Northeast   Central   Elimination(b)   Total
    (In millions)
Net losses on settled positions, or financial expense in cost of operations
  $ (114 )   $ (13 )   $ (5 )   $ (6 )   $     $ (138 )
 
Mark-to-market results in cost of operations
                                               
Reversal of previously recognized unrealized losses on settled positions related to economic hedges
          25       43                   68  
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009
    210                               210  
Net unrealized gains/(losses) on open positions related to economic hedges
    93       (66 )     (23 )     (10 )     2       (4 )
 
Subtotal mark-to-market results
    303       (41 )     20       (10 )     2       274  
 
Total derivative gains/(losses) included in cost of operations
  $ 189     $ (54 )   $ 15     $ (16 )   $ 2     $ 136  
 
(a)  
Reliant Energy results are for the period May 1, 2009, to June 30, 2009.
 
(b)  
Represents the elimination of $2 million intercompany loss in the Reliant Energy region. The offsetting intercompany gain is included in revenue in the Texas region.
     For the six months ended June 30, 2010, the $58 million gain in revenue from economic hedge positions is primarily driven by an increase in value of forward sales of natural gas and electricity due to a decrease in forward power and gas prices. The $142 million loss in cost of energy from economic hedge positions is primarily driven by a decrease in value of forward purchases of natural gas, electricity and fuel due to a decrease in forward power and gas prices. Reliant Energy’s $150 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in cost of operations during the same period.
     In accordance with ASC 815, the following table represents the results of the Company’s financial and physical trading of energy commodities for the six months ended June 30, 2010, and 2009. 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. The Company’s trading activities are subject to limits within the Company’s Risk Management Policy.
                 
    Six months
    ended June 30,
(In millions)   2010   2009
 
Trading gains/(losses)
               
Realized
  $ (24 )   $ 96  
Unrealized
    49       (96 )
 
Total trading gains/(losses)
  $ 25     $  
 

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Depreciation and Amortization
     NRG’s depreciation and amortization expense increased by $28 million during the six months ended June 30, 2010, compared to the same period in 2009. Reliant Energy’s depreciation and amortization expense for the six month period increased by $16 million due to the inclusion of four additional months in 2010. The balance of the increase was due to depreciation on the baghouse projects in western New York, Cedar Bayou 4, which began commercial operation in June 2009, and Langford, which began commercial operation in December 2009.
Selling, General and Administrative Expenses
     Selling, general and administrative expenses increased by $55 million during the six months ended June 30, 2010, compared to the same period in 2009. The increase was due to:
   
Retail selling, general and administrative expense — increased by $73 million due to the inclusion of four additional months in 2010.
These increases were offset by
   
Labor costs — decreased by $15 million offset by higher contractor expense of $5 million.
 
   
Consultant costs — decreased by $9 million due to non-recurring costs related to Exelon’s exchange offer and proxy contest efforts incurred in 2009.
Acquisition-related Transaction and Integration Costs
     NRG incurred Reliant Energy acquisition-related transaction and integration costs of $35 million for 2009.
Gain on Sale of Assets
     On January 11, 2010, NRG sold Padoma to Enel, recognizing a gain on sale of $23 million.
Equity in Earnings of Unconsolidated Affiliates
     NRG’s equity earnings from unconsolidated affiliates decreased by $2 million during the six months ended June 30, 2010, compared to the same period in 2009. In 2009, NRG recognized $15 million from MIBRAG, which was sold in June 2009. This decrease was partially offset by a $13 million increase from Sherbino in 2010.
Gain on Sale of Equity Method Investments
     NRG’s gain on sale of equity method investments in 2009 represents a $128 million gain on the sale of NRG’s 50% ownership interest in MIBRAG.
Other Income/(Expense), Net
     NRG’s other income/(expense), net increased $37 million during the six months ended June 30, 2010, compared to the same period in 2009. The 2010 amount includes $3 million and $9 million of unrealized and realized foreign exchange gains, respectively. The 2009 amount includes a $24 million loss on a forward contract for foreign currency executed to hedge the MIBRAG sale proceeds.

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Interest Expense
     NRG’s interest expense increased $3 million during the six months ended June 30, 2010, compared to the same period in 2009. This increase was due to $25 million related to the issuance of the 2019 Senior Notes in June 2009. This increase was offset by a $14 million decrease due to the settlement of the CSF Debt in 2009 and early 2010 and a $7 million decrease due to a lower outstanding principal balance on the Term Loan Facility and a $2 million decrease due to lower interest rates related to the unhedged portion of the Term Loan.
Income Tax Expense
     NRG’s income tax expense decreased by $266 million during the six months ended June 30, 2010, compared to the same period in 2009. The decrease in income tax expense was primarily due to a decrease in income. The effective tax rate was 40.4% and 41.5% for the six months ended June 30, 2010, and 2009, respectively.
     For the six months ended June 30, 2010, NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes as well as recording federal and state tax expense and interest for unrecognized tax benefits. For the six months ended June 30, 2009, NRG’s overall effective tax rate was different than the statutory rate of 35% primarily due to an increase in valuation allowance as a result of capital losses generated in the six month period 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 net state and local income tax benefit as a result of the Reliant Energy acquisition.

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Results of Operations — Regional Discussions
     The following is a detailed discussion of the results of operations of NRG’s retail business segment.
Reliant Energy
Quarterly Results
     For a discussion of the business profile of the Company’s Reliant Energy operations, see pages 94-96 of NRG Energy, Inc.’s 2009 Annual Report on Form 10-K.
Selected Income Statement Data
                                         
    Three months           Two months   Two months    
    ended   One month ended   ended   ended    
(In millions except otherwise noted)   June 30, 2010   April 30, 2010   June 30, 2010   June 30, 2009(c)   Change %
 
Operating Revenues
                                       
Mass revenues
  $ 808     $ 190     $ 618     $ 761       (19 )%
Commercial and Industrial revenues
    502       151       351       437       (20 )
Supply management revenues
    31       13       18       52       (65 )
Contract amortization
    (59 )     (22 )     (37 )     (75 )     51  
 
Total operating revenues
    1,282       332       950       1,175       (19 )
Operating Costs and Expenses
                                       
Cost of energy (including risk management activities)
    861       239       622       614       1  
Other operating expenses
    113       37       76       90       (16 )
Depreciation and amortization
    29       9       20       43       (53 )
 
Operating Income
  $ 279     $ 47     $ 232     $ 428       (46 )
Electricity sales volume — GWh