10-K
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-K
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the Fiscal Year ended December 31, 2006.
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the Transition period from          to          .
 
Commission file No. 001-15891
 
NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)
 
     
Delaware
  41-1724239
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
211 Carnegie Center
Princeton, New Jersey
(Address of principal executive offices)
 
08540
(Zip Code)
 
(609) 524-4500
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Exchange on Which Registered
 
Common Stock, par value $0.01
  New York Stock Exchange
5.75% Mandatory Convertible Preferred Stock   New York Stock Exchange
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     No þ
 
Indicate by check mark whether the Registrant (1) has filed all reports 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ     Accelerated filer o     Non-accelerated filer o
 
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
 
As of the last business day of the most recently completed second fiscal quarter, the aggregate market value of the common stock of the registrant held by non-affiliates was approximately $6,599,652,171 based on the closing sale price of $48.18 as reported on the New York Stock Exchange.
 
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  Yes þ     No o
 
Indicate the number of shares outstanding of each of the registrant’s classes of common stock as of the latest practicable date.
 
         
Class
 
Outstanding at February 23, 2007
 
Common Stock, par value $0.01 per share     122,335,466  
 
Documents Incorporated by Reference:
 
Portions of the Proxy Statement for the 2007 Annual Meeting of Stockholders to be held on April 25, 2007
 


 

 
TABLE OF CONTENTS
 
INDEX
 
             
  2
  7
    Business   7
    Risk Factors     41
    Unresolved Staff Comments   54
    Properties   54
    Legal Proceedings   57
    Submission of Matters to a Vote of Security Holders   61
  61
    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   61
    Selected Financial Data   64
    Management’s Discussion and Analysis of Financial Condition and Results of Operations   67
    Quantitative and Qualitative Disclosures about Market Risk   115
    Financial Statements and Supplementary Data   119
    Changes in and Disagreements with Accountants on Accounting and Financial Disclosures   119
    Controls and Procedures   119
    Other Information   120
  120
    Directors and Executive Officers of the Registrant   120
    Executive Compensation   120
    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   120
    Certain Relationships and Related Transactions   120
    Principal Accountant Fees and Services   120
  121
    Exhibits and Financial Statement Schedules   121
  218
 EX-10.38: NEO 2006 AIP PAYOUT AND 2007 BASE SALARY TABLE
 EX-10.39: NRG ENERGY, INC. EXECUTIVE AND KEY MANAGEMENT CHANGE-IN-CONTROL AND GENERAL SEVERANCE PLAN
 EX-12.1: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
 EX-12.2: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDEND REQUIREMENTS
 EX-21: SUBSIDIARIES OF NRG ENERGY INC
 EX-23.1: CONSENT OF KPMG LLP
 EX-31.1: CERTIFICATION
 EX-31.2: CERTIFICATION
 EX-31.3: CERTIFICATION
 EX-32: CERTIFICATION


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Table of Contents

 
Glossary of Terms
 
Glossary of Terms — (continued)
 
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
 
     
ABWR
  Advanced Boiling Water Reactor
Acquisition
  February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Company’s Texas region
Acquisition Agreement
  Acquisition Agreement dated September 30, 2005 underlying the February 2, 2006 acquisition of the Company’s Texas region
AMA
  Administrative Management Agreement between NRG Development Company, Inc. and West Coast Power, LLC
APB
  Accounting Principles Board
APB 18
  APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock”
Average gross heat rate
  The product of dividing (a) fuel consumed in BTU’s by (b) KWh generated
BACT
  Best Available Control Technology
BART
  Best Available Retrofit Technology
Baseload capacity
  Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
BTA
  Best Technology Available
BTU
  British Thermal Unit
CAA
  Clean Air Act
CAIR
  Clean Air Interstate Rule
CAISO
  California Independent System Operator
CAMR
  Clean Air Mercury Rule
Capacity factor
  The ratio of the actual net electricity generated to the energy that could have been generated at continuous full-power operation during the year
Capital Allocation Program
  Share repurchase program entered into August 2006
CDWR
  California Department of Water Resources
CERCLA
  Comprehensive Environmental Response, Compensation and Liability Act
CL&P
  Connecticut Light & Power
CO2
  Carbon dioxide
CPUC
  California Public Utilities Commission
Derate
  A derate exists whenever a generating unit is not capable of operating at its tested dependable maximum net capability
DNREC
  Delaware Department of Natural Resources and Environmental Control
EAF
  The total available hours a unit is available in a year minus the sum of all partial outage events in a year converted to equivalent hours, expressed as a percent of all hours in the year
EFOR
  Equivalent Forced Outage Rates — considers the equivalent impact that forced de-ratings have in addition to full forced outages
EITF
  Emerging Issues Task Force
EITF 02-3
  EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”
EPAct of 2005
  Energy Policy Act of 2005
EPC
  Engineering, Procurement and Construction


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ERCOT
  Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ERO
  Energy Reliability Organization
EWG
  Exempt Wholesale Generator
Expected annual baseload generation
  The net baseload capacity 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
FGD
  Flue Gas Desulphurization
FIN
  FASB Interpretation
FIN 45
  FIN No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
FIP
  Federal Implementation Plan
Fresh Start
  Reporting requirements as defined by SOP 90-7
GHG
  Greenhouse Gases
Hedge Reset
  Net settlement of long-term power contracts and gas swaps by negotiating prices to current market completed in November 2006
Hg
  Mercury
ICT
  Independent Coordinator of Transmission
IGCC
  Integrated Gasification Combined Cycle
IRS
  Internal Revenue Service
ISO
  Independent System Operator, also referred to as Regional Transmission Organizations, or RTO
ISO-NE
  ISO New England, Inc.
ITISA
  Itiquira Energetica S.A.
kW
  Kilowatts
KWh
  Kilowatt-hours
LADEQ
  Louisiana Department of Environmental Quality
LFRM
  Locational Factor Reserve Market
LIBOR
  London Inter-Bank Offered Rate
LNB/OFA
  Low NOx Burner with Over Fire Air
LSE
  Load-Serving Entity
MACT
  Maximum Achievable Control Technology
MADEP
  Massachusetts Department of Environmental Protection
MDL
  Multi-District Litigation
Merit Order
  A term used for the ranking of power stations in terms of increasing order of fuel costs
MIBRAG
  Mitteldeutsche Braunkohlengesellschaft mbH
Moody’s
  Moody’s Investors Services, Inc., a credit rating agency
MMBtu
  Million British Thermal Units
MRTU
  Market Redesign and Technology Upgrade
MW
  Megawatts


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MWh
  Saleable megawatt hours net of internal/parasitic load megawatt-hours
NAAQS
  National Ambient Air Quality Standards
Net baseload capacity
  Nominal summer net megawatt capacity of power generation adjusted for ownership and parasitic load, and excluding capacity from mothballed units as of December 31, 2006
Net Capacity Factor
  Net actual generation divided by net maximum capacity for the period hours
Net Generating Capacity
  Nominal summer capacity, net of auxiliary power
New York Rest of State
  New York State excluding New York City
NiMo
  Niagara Mohawk Power Corporation
NOx
  Nitrogen oxide
NOL
  Net Operating Loss
NOV
  Notice of Violation
NRC
  United States Nuclear Regulatory Commission
NSR
  New Source Review
NYPA
  New York Power Authority
NYISO
  New York Independent System Operator
NYSDEC
  New York Department of Environmental Conservation
OCI
  Other Comprehensive Income
OTC
  Ozone Transport Commission
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
PM (2.5)
  Fine particulate matter
PMI
  NRG Power Marketing, Inc., a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manage, all commodity trading and hedging for NRG
Powder River Basin, or PRB, Coal
  Coal produced in the northeastern Wyoming and southeastern Montana, which has low sulfur content
PPA
  Power Purchase Agreement
PSD
  Prevention of Significant Deterioration
PUCT
  Public Utility Commission of Texas
PUHCA
  Public Utility Holding Company Act of 2005
PURPA
  Public Utility Regulatory Policy Act of 2005
RCRA
  Resource Conservation and Recovery Act
RECLAIM
  Regional Clean Air Incentives Market
Repowering NRG
  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
RFP
  Request for proposal
RGGI
  Regional Greenhouse Gas Initiative


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RMR
  Reliability Must-Run
ROIC
  Return on invested capital
RTC
  RECLAIM Trading Credit
RTO
  Regional Transmission Organization, also referred to as an ISO
S&P
  Standard & Poor’s, a credit rating agency
SARA
  Superfund Amendments and Reauthorization Act of 1986
Sarbanes-Oxley
  Sarbanes — Oxley Act of 2002
SCAQMD
  South Coast Air Quality Management District
Schkopau
  Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which NRG has a 41.9% interest
SCR
  Selective Catalytic Reduction
SDG&E
  San Diego Gas & Electric
SEC
  United States Securities and Exchange Commission
Sellers
  Former holders of Texas Genco LLC shares
SERC
  Southeastern Electric Reliability Council/Entergy
SFAS
  Statement of Financial Accounting Standards issued by the FASB
SFAS 71
  SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”
SFAS 87
  SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS 106
  SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 109
  SFAS No. 109, “Accounting for Income Taxes”
SFAS 123
  SFAS No. 123, “Accounting for Stock-Based Compensation”
SFAS 123R
  SFAS No. 123 (revised 2004), “Share-Based Payment”
SFAS 133
  SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 137
  SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133”
SFAS 138
  SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of FASB Statement No. 133”
SFAS 142
  SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 143
  SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 144
  SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS 149
  SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
SFAS 158
  SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)”
SFAS 159
  SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115”
SNCR
  Selective non-catalytic reduction
SIP
  State Implementation Plan
SO2
  Sulfur dioxide


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SOP
  Statement of Position issued by the American Institute of Certified Public Accountants
SOP 90-7
  Statement of Position 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”
SPP
  Southwest Power Pool
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
TCEQ
  Texas Commission on Environmental Quality
Texas Genco
  Texas Genco LLC, now referred to as the Company’s Texas region
Uprate
  A sustainable increase in the electrical rating of a generating facility
US
  United States of America
USEPA
  United States Environmental Protection Agency
U.S. GAAP
  Accounting principles generally accepted in the United States
VAR
  Value at Risk
Virtual Units
  Products sold with scheduling characteristics for energy and ancillary services that are based on an underlying unit physical characteristic
VOC
  Volatile Organic Carbon
WCP
  WCP (Generation) Holdings, Inc.


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Table of Contents

 
PART I
 
Item 1 — Business
 
General
 
NRG Energy, Inc., NRG, or the Company, is a wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is primarily engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the United States and internationally. As of December 31, 2006, NRG had a total global portfolio of 223 active operating generation units at 51 power generation plants, with an aggregate generation capacity of approximately 24,175 MW. Within the United States, the Company has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,940 MW of generation capacity in 207 active generating units at 45 plants. These power generation facilities are primarily located in Texas (approximately 10,760 MW), and the Northeast (approximately 7,240 MW), South Central (approximately 2,850 MW), and the West (approximately 1,965 MW) regions of the United States, with approximately 125 MW from the Company’s thermal assets. NRG’s principal domestic power plants consist of a diversified mix of natural gas-, coal-, oil-fired and nuclear facilities, representing approximately 45%, 34%, 16% and 5% of the Company’s total domestic generation capacity, respectively. In addition, 15% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option, and consist primarily of baseload, intermediate and peaking power generation facilities, which are referred to as the merit order, and also include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company’s revenues and provides a stable source of cash flow. In addition, NRG’s diverse 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. In addition, NRG is pursuing opportunities to repower existing facilities and develop new generation capacity in markets in which NRG currently owns assets in an initiative referred to as Repowering NRG. In connection with NRG’s acquisition of Padoma Wind Power LLC, the Company has and will continue to actively evaluate and potentially develop or construct domestic terrestrial wind projects as part of the Repowering NRG program.
 
Business Strategy
 
NRG’s strategy is to optimize the value of the Company’s generation assets while using its asset base as a platform for growth and enhanced financial performance which can be sustained and expanded upon in the years to come. NRG plans to maintain and enhance the Company’s position as a leading wholesale power generation company in the United States in a cost-effective and risk-mitigating manner in order to serve the bulk power requirements of NRG’s existing customer base and other entities that offer load or otherwise consume wholesale electricity products and services in bulk. NRG’s strategy includes the following elements:
 
Pursue additional growth opportunities at existing sites — NRG is favorably positioned to pursue growth opportunities through expansion of its existing generating capacity and development of new generating capacity at its existing facilities. NRG intends to invest in its existing assets through plant improvements, repowerings, brownfield development and site expansions to meet anticipated requirements for additional capacity in NRG’s core markets. In furtherance of this goal, NRG has initiated a company-wide program, known as Repowering NRG, to develop, construct and operate new and enhanced power generation facilities at its existing sites, with an emphasis on new baseload capacity that is supported by long-term power sales agreements and financed with limited or non-recourse project financing. NRG expects that these efforts will provide one or more of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; an improved ability to dispatch economically across the merit order; increased technological and fuel diversity; and reduced environmental impacts, including facilities that either have near zero greenhouse gas emissions or can be equipped to capture and sequester greenhouse gas emissions.


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Table of Contents

 
Increase value from existing assets — NRG has a highly diversified portfolio of power generation assets in terms of region, fuel-type and dispatch levels. NRG will continue to focus on extracting value from its portfolio by improving plant performance, reducing costs and harnessing the Company’s advantages of scale in the procurement of fuels and other commodities, parts and services, and in doing so improve the Company’s return on invested capital, or ROIC — a strategy that NRG has branded FORNRG, or Focus on ROIC@NRG.
 
Maintain financial strength and flexibility — NRG remains focused on cash flow and maintaining appropriate levels of liquidity, debt and equity in order to ensure continued access to capital for investment, to enhance risk-adjusted returns and to provide flexibility in executing NRG’s business strategy. NRG will continue to focus on maintaining operational and financial controls designed to ensure that the Company’s financial position remains strong. At the same time, NRG expects to continue its practice of returning excess cash flows to its debt and equity investors on a regular basis.
 
Reduce the volatility of the Company’s cash flows through asset-based commodity hedging activities — NRG will continue to execute asset-based risk management, hedging, marketing and trading strategies within well defined risk and liquidity guidelines in order to manage the value of the Company’s physical and contractual assets. The Company’s marketing and hedging philosophy is centered on generating stable returns from its portfolio of baseload power generation assets while preserving an ability to capitalize on strong spot market conditions and to capture the extrinsic value of the Company’s intermediate and peaking facilities and portions of its baseload fleet. NRG believes that it can successfully execute this strategy by leveraging its expertise in marketing power and ancillary services, its knowledge of markets, its balanced financial structure and its diverse portfolio of power generation assets.
 
Pursue strategic acquisitions and divestures — NRG will continue to pursue selective acquisitions, joint ventures and divestitures to enhance its asset mix and competitive position in the Company’s core regions. NRG intends to concentrate on opportunities that present attractive risk-adjusted returns. NRG will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures.
 
Competition and Competitive Strengths
 
Competition — Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. NRG competes on the basis of the location of its plants and owning multiple plants in its regions, which increases the stability and reliability of its energy supply. Wholesale power generation is basically a local business that is currently highly fragmented relative to other commodity industries and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies NRG competes against depending on the market.
 
Scale and diversity of assets — NRG has one of the largest and most diversified power generation portfolios in the United States, with approximately 22,940 MW of generation capacity in 207 active generating units at 45 plants as of December 31, 2006. The Company’s power generation assets are diversified by fuel-type, dispatch level and region, which help mitigate the risks associated with fuel price volatility and market demand cycles. NRG’s U.S. baseload facilities, which consist of approximately 8,745 MW of generation capacity measured as of December 31, 2006, provide the Company with a significant source of stable cash flow, while its intermediate and peaking facilities, with approximately 14,195 MW of generation capacity as of December 31, 2006, provide NRG with opportunities to capture the significant upside potential that can arise from time to time during periods of high demand. In addition, approximately 15% of the Company’s domestic generation facilities have dual or multiple fuel capability, which allows most of these plants to dispatch with the lowest cost fuel option.


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The following chart demonstrates the diversification of NRG’s domestic power generation assets as of December 31, 2006:
 
(GRAPH)
 
Reliability of future cash flows — NRG has sold forward or otherwise hedged a significant portion of its expected baseload generation capacity through 2012. The Company has the capacity and intent to enter into additional hedges in later years when market conditions are favorable. In addition, as of December 31, 2006, the Company has purchased forward under fixed price contracts (with contractually-specified price escalators) to provide fuel for approximately 73% of its expected baseload coal generation output from 2007 to 2012. These forward positions provide a stable and reliable source of future cash flow for NRG’s investors, while preserving a portion of its generation portfolio for opportunistic sales to take advantage of market dynamics.
 
Favorable market dynamics for baseload power plants — In 2006, approximately 83% of the Company’s domestic generation was fueled by coal or nuclear fuel. In many of the competitive markets where NRG operates, the price of power is typically set by the marginal costs of natural gas-fired and oil-fired power plants that currently have substantially higher variable costs than solid fuel baseload power plants. As a result of NRG’s lower marginal cost for baseload coal and nuclear generation assets, the Company expects these ERCOT assets to generate power nearly 100% of the time they are available.
 
Locational advantages — Many of NRG’s generation assets are located within densely populated areas that are characterized by significant constraints on the transmission of power from generators outside the region. Consequently, these assets are able to benefit from the higher prices that prevail for energy in these markets during periods of transmission constraints. NRG has generation assets located within New York City, southwestern Connecticut, Houston and the Los Angeles and San Diego load basins; all areas with constraints on the transmission of electricity. This gives the Company the opportunity to capture additional revenues through offering capacity to retail electric providers and others, selling power at prevailing market prices during periods of peak demand and providing ancillary services in support of system reliability. These facilities are often ideally situated for repowering or the addition of new capacity, as well, because their location and existing infrastructure give them significant advantages over newly developed sites in their regions.


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Performance Metrics
 
The following table contains a summary of NRG’s operating revenues by segment for the year ended December 31, 2006. The table also reflects the realignment of the Company’s new segment structure as discussed in Item 15 — Note 17, Segment Reporting, to the Consolidated Financial Statements.
 
                                                                 
                Risk
                            Total
 
    Energy
    Capacity
    Management
    Contract
    Thermal
    Hedge
    Other
    Operating
 
Region
  Revenues     Revenues     Activities     Amortization     Revenues     Reset     Revenues(c)     Revenues  
    (In millions)  
 
Texas(a)
  $ 1,726     $ 849     $ (30 )   $ 609     $     $  (129 )   $ 63     $ 3,088  
Northeast
    966       321       144                         112       1,543  
South Central
    334       199       13       19                   5       570  
West(b)
    75       68       (3 )                       6       146  
International
    80       79                               14       173  
Thermal
    12                         124             16       152  
Corporate/Eliminations
                                        (49 )     (49 )
                                                                 
Total
  $ 3,193     $ 1,516     $ 124     $ 628     $ 124     $ (129 )   $ 167     $ 5,623  
                                                                 
 
 
(a)  For the period February 2, 2006 — December 31, 2006.
 
(b)  Includes fully consolidated results of WCP for the period April 1, 2006 — December 31, 2006.
 
(c)  Includes operations and maintenance fees, sale of natural gas, sale of emission allowances, and revenues from ancillary services.
 
In understanding NRG’s business, the Company believes that certain performance metrics are particularly important. These are industry statistics defined by the North American Electric Reliability Council and are more fully described below:
 
Annual Equivalent Availability Factor, or EAF:  The percentage of time in one year that a generating unit is able to produce electricity, adjusted to take into account times when the unit is unavailable and able to produce its full rated output.
 
Gross heat rate:  NRG calculates the gross heat rate for the Company’s fossil-fired power plants by dividing the average amount of fuel in BTUs that it takes to generate one kWh of electricity by the generator output.
 
Net Capacity Factor:  The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.


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Table of Contents

The tables below present the North American power generation performance metrics for the Company’s power plants discussed above for the years ended December 31, 2006 and 2005:
 
                                         
    Year Ended December 31, 2006  
                Annual
             
          Net
    Equivalent
    Average Net
       
    Net Owned
    Generation
    Availability
    Heat Rate
    Net Capacity
 
Region
  Capacity (MW)     (MWh)     Factor     Btu/KWh     Factor  
    (In thousands of MWh)  
 
Texas(a)
    10,760       44,910       91.0 %     10,300       41.0 %
Northeast(b)
    7,240       13,309       85.8       10,900       18.8  
South Central
    2,850       11,036       94.3       10,400       47.2  
West(c)
    1,965       1,901       89.1 %     11,400       15.1 %
 
                                         
    Year Ended December 31, 2005  
                Annual
             
          Net
    Equivalent
    Average Net
       
    Net Owned
    Generation
    Availability
    Heat Rate
    Net Capacity
 
Region
  Capacity (MW)     (MWh)     Factor     Btu/KWh     Factor  
    (In thousands of MWh)  
 
Northeast(b)
    7,099       16,246       87.2 %     11,146       22.9 %
South Central
    2,395       10,009       90.9       10,518       50.6  
West(d)
    1,044       1,794       86.5 %     11,109       18.0 %
 
 
(a)  For the period February 2, 2006 through December 31, 2006.
 
(b)  Factor data and heat rate does not include the Keystone and Conemaugh facilities.
 
(c)  Includes fully consolidated results of WCP for the period April 1, 2006 — December 31, 2006.
 
(d)  Includes 50% of the generation owned through NRG’s WCP partnership.
 
Generation Asset Overview
 
NRG has a significant power generation presence in major competitive power markets of the United States as set forth in the map below:
 
(MAP)


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As of December 31, 2006, the Company’s power generation assets consisted of approximately 10,470 MW of gas-fired; 7,815 MW coal-fired; 3,555 MW of oil-fired and 1,100 MW of nuclear generating capacity in the United States. In addition, NRG also owns approximately 1,230 MW of thermal capacity as well as 1,235 MW of power generation capacity overseas. The Company’s North American power generation portfolio by dispatch level is comprised of approximately 39% baseload, 37% intermediate and 24% of peaking units. NRG uses hedging strategies which may include power and natural gas forward sales contracts to manage the commodity price risk associated with the Company’s generation assets, and are primarily around the Company’s baseload generation assets. In addition, these hedging strategies also provide for stable cash flow and earnings predictability.
 
The following table summarizes NRG’s North American baseload capacity and the corresponding revenues resulting from baseload hedge agreements extending beyond December 31, 2006 through 2012:
 
                                                         
                                        Annual
 
                                        Average for
 
    2007     2008     2009     2010     2011     2012     2007-2012  
    (In millions unless otherwise stated)  
 
Net Baseload Capacity (MW)
    8,800       8,730       8,730       8,621       8,621       8,621       8,687  
Forecasted Baseload Capacity (MW)
    7,493       7,394       7,358       7,305       7,208       7,269       7,338  
Total Baseload Sales (MW)(a)
    7,263       6,105       5,370       4,334       4,679       1,767       4,920  
Percentage Baseload Capacity Sold Forward(b)
    97 %     83 %     73 %     59 %     65 %     24 %     67 %
Total Forward Hedged Revenues(c)(d)
  $ 3,582     $ 2,803     $ 2,524     $ 1,931     $ 1,934     $ 617     $ 2,232  
Weighted Average Hedged Price ($ per MWh)(c)
  $ 56     $ 52     $ 54     $ 51     $ 47     $ 40     $ 50  
Weighted Average Hedged Price ($ per MWh) excluding South Central region(d)
  $ 61     $ 57     $ 59     $ 56     $ 51     $ 49     $ 56  
 
 
(a) Includes amounts under fixed price power sales contracts and amounts financially hedged under natural gas contracts. The forward natural gas quantities are reflected in equivalent MWh and are derived by first dividing the quantity of MMBtu of natural gas hedged by the forward market implied heat rate as of December 31, 2006 to arrive at the equivalent MWh hedged which is then divided by 8,760 hours (total hours in a year) to arrive at MW hedged.
 
(b) Percentage hedged is based on total MW sold as power and gas converted using the method as described in (a) above divided by the forecasted baseload capacity.
 
(c) Represents all North American baseload sales including power contract prices in the Texas and South Central regions which are comprised of a fixed demand charge exclusive of a fixed energy charge, with the transaction price related to these contracts being the sum of both charges.
 
(d) The South Central region’s weighted average hedged prices ranges from $33/MWh — $35/MWh due to legacy cooperative load contracts entered into at prices significantly below current market levels.
 
(e) Includes contracted revenues subject to hedge accounting, market-to-market, and normal purchases and normal sales accounting treatment.
 
The following is a discussion of NRG’s generation assets by segment for the year ended December 31, 2006. This discussion reflects the realignment of the Company’s new segment structure as discussed in Item 15 — Note 17, Segment Reporting, to the Consolidated Financial Statements in this Form 10-K.
 
Texas Region — As of December 31, 2006, NRG’s generation assets in the Texas region consisted of approximately 5,280 MW of baseload generation assets and approximately 5,480 MW of intermediate and peaking natural gas-fired assets. NRG realizes a substantial portion of its revenue and cash flow from the sale of power from the Company’s three baseload power plants located in the ERCOT market that use solid fuel: W. A. Parish which uses coal, Limestone which uses lignite and coal, and an undivided 44% interest in two nuclear generating units at STP which uses nuclear fuel. Power plants are generally dispatched in order of lowest operating cost and as of December 31, 2006, approximately 72% of the net generation capacity in the ERCOT market was natural gas-fired. In the current natural gas price environment, NRG’s three baseload facilities have significantly lower operating costs than gas plants. NRG expects these three facilities to operate nearly 100% of the time, subject to planned and forced outages.


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Northeast Region — As of December 31, 2006, NRG generation assets in the Northeast region of the United States consisted of approximately 7,240 MW generation capacity from the Company’s power plants within the control areas of the New York Independent System Operator, or NYISO, the Independent System Operator — New England, or ISO-NE, and the PJM Interconnection LLC, or PJM. Certain of these assets are located in transmission constrained areas, including approximately 1,415 MW of in-city New York City generation capacity and approximately 535 MW of southwest Connecticut generation capacity. As of December 31, 2006, NRG’s generation assets in the Northeast region consisted of approximately 1,960 MW of baseload generation assets and approximately 5,280 MW of intermediate and peaking assets.
 
South Central Region — As of December 31, 2006, NRG generation assets in the South Central region of the United States consisted of approximately 2,850 MW of generation capacity, making NRG the third largest generator in the Southeastern Electric Reliability Council/Entergy, or SERC-Entergy, region. The Company’s generation assets in the South Central region consists of its primary asset, Big Cajun II, a coal-fired plant located near Baton Rouge, Louisiana which has approximately 1,490 MW of baseload generation assets and 1,360 MW of intermediate and peaking assets. An annual average of 1,164 MW of baseload generation capacity has been contracted through eleven cooperatives within the region through 2025.
 
West Region — On March 31, 2006, NRG acquired Dynegy, Inc.’s 50% ownership interest in WCP Holdings to become sole owner of power plants with generation capacity of approximately 1,825 MW in the West region of the United States. These assets, combined with approximately 140 MW of existing wholly owned capacity in the Western Electricity Coordinating Council, brings NRG’s total generation to approximately 1,965 MW in the West region as of December 31, 2006. On January 3, 2007, NRG completed the sale of the Red Bluff and Chowchilla II power plants with a combined generation capacity of approximately 95 MW to an entity controlled by Wayzata Investment Partners LLC. Excluding these two plants, total generation for the West region was 1,870 MW.
 
International Region — As of December 31, 2006, NRG had net ownership in approximately 1,235 MW of power generating capacity outside the United States in Australia, Brazil, and Germany. In addition to traditional power generation facilities, NRG also owned equity interests in certain coal mines in Germany.
 
Thermal — NRG owns thermal and chilled water businesses that generate approximately 1,230 MW thermal equivalents. In addition, NRG’s thermal segment owns certain power plants with approximately 125 MW of power generating capacity located in Delaware and in Pennsylvania.
 
Dispositions of Non-Strategic Assets
 
During 2006, NRG continued its efforts to divest the Company’s interests in non-core assets. As of December 31, 2006, NRG had sold a number of consolidated businesses and equity investments in an effort to reduce the Company’s debt, improve liquidity and rationalize NRG’s investments.
 
Dispositions completed during 2006 are summarized in the following table:
 
                                     
            Closing
        Gain/(Loss)
    Debt
 
Asset   Type   Segment(b)   Date   Proceeds     on Disposition     Reduction  
                (In millions)  
 
Rocky Road
  Equity investment   Corporate   03/31/06   $ 45     $     $  
Audrain(a)
  Discontinued operation   Corporate   03/29/06     115       15       240  
Cadillac
  Equity investment   Corporate   04/13/06     11       11        
James River
  Equity investment   Corporate   05/15/06     8       (6 )      
Latin American Funds
  Equity investment   International   06/30/06     23       3        
Flinders
  Discontinued operation   International   08/30/06     242       60       183  
Resource Recovery
  Discontinued operation   Corporate   11/08/06     22       5        
                                     
Total
              $ 466     $ 88     $ 423  
                                     
 
 
(a) Of the $115 million in cash proceeds, approximately $20 million was paid to NRG with the balance paid to the lenders of NRG Financial Company I LLC.
 
(b) Reflects realignment of the Company’s business segments during the fourth quarter 2006.


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In addition, on January 3, 2007, NRG completed the sale of Red Bluff and Chowchilla II power plants to an entity controlled by Wayzata Investment Partners LLC.
 
Repowering NRG Program
 
NRG has announced a comprehensive portfolio redevelopment program, referred to as Repowering NRG, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity at NRG’s existing domestic sites to meet the growing demand in the Company’s core markets. Through the Repowering NRG program, the Company anticipates retiring certain existing units and adding up to approximately 10,350 MW of new generation, with an emphasis on new baseload capacity that is supported by long-term power purchase agreements, or PPAs, and financed with limited or non-recourse project financing. NRG expects that these repowering investments will provide one or more of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; an improved ability to dispatch economically across the merit order; increased technological and fuel diversity; and reduced environmental impacts. The Company expects that the Repowering NRG program will also result in indirect benefits, including the continuation of operations and retention of key personnel at its existing facilities.
 
A critical aspect of the Repowering NRG program is the extent to which the Company seeks to reduce the carbon intensity of the Company’s generation fleet by developing generating facilities with zero CO2 and low CO2 emissions, as well as facilities that can be equipped for CO2 separation and sequestration. As a result, the Repowering NRG program is important not only to NRG but also to the power industry in general. The American power industry is the primary emitter of CO2 in the largest CO2 emitting market on earth. As the power industry takes steps to develop the next wave of power generation infrastructure, technology and capital allocation decisions will be made which could impact GHG from power generation by either making the situation significantly worse or significantly better in terms of CO2 intensity. Although there is no current technological solution to retro-fit existing fossil-fueled technology to capture GHG from power plant flues, there are commercially available large scale technologies for new plants that can generate power with much lower GHG emissions than traditional coal-fired generation. Given that new generation units have useful lives of up to 50 years, NRG will give full consideration to CO2 and other emissions that contribute to GHG when making its long-term investment decisions.
 
As part of the Repowering NRG program, NRG is pursuing a five-pronged GHG emissions strategy as follows:
 
1. Nuclear development — a known, reliable source of electricity with zero emissions.
 
2. IGCC development — coal-fueled baseload generation designed to reduce the intensity of CO2 emissions.
 
3. Wind development — renewable energy for the future with zero emissions.
 
4. Public outreach — NRG will work with government, industry and public interest groups to formulate and implement an economically and environmentally responsible GHG policy.
 
5. Bridge the technology gap — The Company has launched a number of initiatives to improve technology through R&D particularly post-combustion carbon capture, developing underground sequestration, and finding offsets that will mitigate CO2 production.
 
NRG estimates that the Repowering NRG program, if fully implemented as currently proposed, could have a total capital cost of approximately $16 billion. While NRG believes it is extremely unlikely that the program will be fully implemented as currently proposed, the Company nonetheless expects the overall capital expenditures in connection with the program will be substantial. NRG expects to mitigate the capital cost of the program through equity partnerships and public-private partnerships, as well as through development fees for certain projects. To mitigate the investment risks, NRG anticipates entering into long-term PPAs and engineering, procurement and construction, or EPC, contracts. The Company currently expects its share of cash contributions for the projects included in the Repowering NRG program to range between $500 million and $2.0 billion over the next decade. However, the proposed increase in generation capacity and capital costs resulting from Repowering NRG could change as proposed projects are included or removed from the program due to a number of factors, including successfully obtaining required permits and long term PPAs, availability of financing on favorable terms, and


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achieving targeted project returns. The projects that have been identified as part of the Repowering NRG program are subject to change as NRG refines the program to take into account the success rate for completion of projects, changes in the targeted minimum return thresholds, and evolving market dynamics.
 
The following table summarizes the current projects included in the Repowering NRG program by fuel-type:
 
         
Fuel-type
  MW  
 
Gas
      4,050  
Nuclear
    2,700  
Coal Gasification, or IGCC
    1,500  
Solid Fuel
    1,800  
Wind
    300  
         
Total
    10,350  
         
 
Commercial Operations Overview
 
NRG seeks to maximize profitability and manage cash flow volatility through the marketing, trading and sale of energy, capacity and ancillary services into spot, intermediate and long-term markets and through the active management and trading of emissions allowances, fuel supplies and transportation-related services. The Company’s principal objectives are the realization of the full market value of its asset base, including the capture of its extrinsic value, the management and mitigation of commodity market risk and the reduction of cash flow volatility over time.
 
NRG enters into power sales and hedging arrangements via a wide range of products and contracts, including power purchase agreements, fuel supply contracts, capacity auctions, natural gas swap agreements and other financial instruments. The power purchase agreements that NRG enters into require the Company to deliver MWh of power to its counterparties. Natural gas swap agreements and other financial instruments hedge the price NRG will receive for power to be delivered in the future.
 
Fuel Supply and Transportation
 
NRG’s fuel requirements consist primarily of nuclear fuel and various forms of fossil fuel including oil, natural gas and coal, including lignite. The prices of oil, natural gas and coal are subject to macro- and micro-economic forces that can change dramatically in both the short- and long-term. The Company obtains its oil, natural gas and coal from multiple suppliers and transportation sources. Although availability is generally not an issue, localized shortages, transportation availability and supplier financial stability issues can and do occur. Issues related to the sources and availability of raw materials is fairly uniform across the Company’s business segments.
 
Coal — The Company is largely hedged for its domestic coal consumption over the next few years. Coal hedging is dynamic based on forecasted generation and market volatility. As of December 31, 2006, NRG has purchased forward under contracts to provide fuel for approximately 73% on average of the Company’s requirement from 2007 through 2012; 111% in 2007 (includes inventory build in excess of the Company’s forecasted coal burn requirements), 89% in 2008, 81% in 2009, 56% in 2010, 51% in 2011 and 50% in years 2012 and beyond. NRG arranges for the purchase, transportation and delivery of coal for the Company’s baseload coal plants via a variety of coal purchase agreements, rail transportation agreements and rail car lease arrangements. The Company purchased approximately 35 million tons of coal in 2006, which would rank NRG as one of the largest coal purchasers in the United States.
 
As of December 31, 2006, NRG had approximately 7,600 privately leased or owned rail cars in the Company’s transportation fleet. In addition, the Company intends to enter into contracts for delivery of additional 1,100 rail cars within the next year of which approximately 1,000 will replace a portion of the Company’s existing rail car fleet. NRG has entered into rail transportation agreements with varying tenures that provide for substantially all of the Company’s rail transportation requirements through the end of the decade.
 
Natural Gas — NRG operates a fleet of natural gas plants in the Texas, Northeast, South Central and West regions which are comprised of primarily peaking assets that run in times of high power demand. Due to the


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uncertainty of their dispatch, the fuel needs are managed on a spot basis as it is not prudent to forward purchase fixed price gas on units that may not run. The Company contracts for gas storage services as well as gas transportation services to ensure delivery of gas when needed.
 
Nuclear Fuel — STP’s owners satisfy STP’s fuel supply requirements by (1) acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride, (2) contracting for enrichment of uranium hexafluoride and (3) contracting for fabrication of nuclear fuel assemblies. NRG is party to a number of long-term forward purchase contracts with many of the world’s largest suppliers covering STP requirements for uranium and conversion services for the next five years, and with substantial portions of STP’s requirements procured through the end of the next decade. NRG is party to long term contracts to procure STP’s requirements for enrichment services and fuel fabrication for the life of the operating license.
 
Seasonality and Price Volatility
 
Annual and quarterly operating results can be significantly affected by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. NRG derives a majority of its annual revenues in the months of May through September, when demand for electricity is the highest in its core domestic markets. Further, power price volatility is generally higher in the summer months, traditionally NRG’s most important season. The Company’s second most important season is the winter months of December through March when volatility and price spikes in underlying fuel prices have tended to drive seasonal electricity prices. Issues related to seasonality and price volatility are fairly uniform across the Company’s business segments.
 
Plant Operations Overview
 
NRG provides support services to the Company’s generation facilities to ensure that high-level performance goals are developed, best practices are shared and resources are appropriately balanced and allocated to get the best results for the Company. Performance goals are set for equivalent forced outage rates, or EFOR, availability, procurement costs, operating costs and safety.
 
Support services include safety, security, and systems. These services also include operations strategic planning and the development and dissemination of consistent policies and practices relating to plant operations.
 
To support the Repowering NRG program, the Company has organized its project execution process into one centralized group consisting of engineering, procurement and construction. This group has regional engineering functions combined with corporate project engineering, project management, procurement and construction functions to provide a consistent and standardized approach to the way repowering work is executed. This has enabled NRG to leverage both the procurement of major equipment as well as outside engineering resources through standardized work processes and work packaging. This process has led to identifying commonality in major equipment that can be procured from Original Equipment Manufacturers, or OEMs, as well as design processes. As a result, NRG expects to achieve cost savings by minimizing the number of outside engineering and construction resources, which provide detailed design and construction services required to complete projects, in addition to and by ensuring a consistent engineering and construction approach across all projects.
 
Performance Improvement, Cost and Process Control Initiatives
 
In 2005, NRG introduced a comprehensive, company-wide cost and revenue enhancement program with the goal of increasing its return on invested capital, or ROIC. This effort has been branded as FORNRG, or Focus on ROIC@NRG. Projects are focused on improving plant performance, reducing purchasing and other costs and streamlining processes. A large number of initiatives are currently under way at NRG’s major baseload facilities, including forced outage reductions, achieving full load, station service reductions, and heat rate improvements. Qualifying projects are also underway at the Princeton headquarters, which have reduced paperwork burdens as well as tax and insurance costs.
 
During the second quarter 2006, NRG expanded the program to include the Texas Genco assets and extended the term of the program to 2009, with anticipated annual savings in excess of $200 million to be achieved through


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continued benefits from operational performance, cost synergies and purchasing-related initiatives, plus $50 million in cash savings. For 2006, the program has demonstrated benefits of over $140 million from operational performance, cost synergies and purchasing-related initiatives, plus $61 million in cash savings, putting the Company on track to meet its 2009 target.
 
Environmental Capital Expenditures
 
Based on current rules, technology and plans, NRG has estimated that approximately $1.28 billion of environmental capital expenditures will be incurred during the period 2007 through 2012, primarily related to installation of particulate, SO2, NOx, and mercury controls to comply with the Clean Air Interstate Rule and Clean Air Mercury rules or alternative State regimes, to the extent more stringent than the USEPA rules, as well as installation of BTA under the Phase II 316(b) Rule. Changes to regulations or market conditions could result in changes to installed equipment timing or associated costs.
 
The following table summarizes the estimated environmental capital expenditures for the referenced period, by region and by year:
 
                                         
    Texas     Northeast     South Central     Other     Total  
    (In millions)  
 
2007
  $ 9     $ 118     $ 40     $ 10     $ 177  
2008
    16       183       92       10       301  
2009
    19       183       167       5       374  
2010
    26       144       86       4       260  
2011
    19       30       64       1       114  
2012
    13       3       34             50  
                                         
Total
  $ 102     $ 661     $ 483     $ 30     $ 1,276  
                                         
 
NRG is working to reduce a portion of the above environmental capital expenditures. First, NRG has the ability to monetize a portion of the Company’s excess allowances over the 2007-2012 timeframe and still hold sufficient allowances to operate the fleet with proposed controls through at least 2020. Second, NRG’s current contracts with the Company’s rural electrical customers in the South Central region allow for recovery of a significant portion of the costs, along with a capital return incurred by complying with new laws, including interest over the asset life of the required expenditures. Actual recoveries will depend, among other things, on the duration of the contracts and the treatment of these expenditures.
 
  Employees
 
As of December 31, 2006, NRG had 3,217 employees, approximately 1,622 of whom were covered by U.S. bargaining agreements. During 2006, the Company did not experience any significant labor stoppages or labor disputes at any of its facilities.
 
Regional Business Descriptions
 
NRG is organized into business units as described below, with each of the Company’s core regions operating as a separate business segment. As of December 31, 2006, NRG realigned the Company’s segment structure. For a further discussion on the realignment of the Company’s operating segments and for financial information on NRG’s operations by segment, see Item 15 — Note 17, Segment Reporting, to the Consolidated Financial Statements.
 
TEXAS
 
NRG’s largest business unit is located in Texas and is comprised of investments in generation facilities located in the physical control areas of the ERCOT market. These assets were acquired on February 2, 2006 as part of the acquisition of Texas Genco LLC.


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Operating Strategy
 
The Company’s business in Texas is comprised of two sets of assets: a regionally diverse set of three large solid-fuel baseload plants and a set of gas-fired plants located in and around Houston. NRG’s operating strategy to maximize value and opportunity across these assets is to (1) ensure the availability of the baseload plants to fulfill their commercial obligations under long-term forward sales contracts already in place, (2) manage the gas assets for profitability while ensuring the reliability and flexibility of power supply to the Houston market, (3) take advantage of the skill sets and market/regulatory knowledge to grow the business through incremental capacity uprates and repowering development of solid-fuel baseload and gas-fired units, and (4) play a leading role in the development of the ERCOT market by active membership and participation in market and regulatory issues.
 
NRG’s strategy is to sell forward a majority of its solid-fuel baseload capacity in the ERCOT market under long-term contracts or to enter into hedges by using natural gas as a proxy for power prices. Accordingly, the Company’s primary focus will be to keep these solid-fuel baseload units running efficiently. With respect to gas-fired assets, NRG will continue a dual path of contracting forward a significant portion of gas-fired capacity one to two years out while holding a portion for back-up in case there is an operational issue with one of the baseload units. For the gas-fired capacity sold forward, the Company will offer a range of products including where the customer has the right to dispatch capacity as the customer needs. For the gas-fired capacity that NRG will continue to sell commercially into the market, the Company will focus on making this capacity available to the market whenever it is economic to run.
 
The generation performance by fuel-type for the recent three-year period is as shown below:
 
                         
    Net Generation  
    2006     2005     2004  
    (In thousands of MWh)  
 
Coal
    31,371       31,299       31,222  
Gas
    7,983       6,806       7,701  
Nuclear(a)
    9,385       6,412       6,580  
                         
Total
      48,739         44,517         45,503  
                         
 
 
(a) MWh information reflects the undivided interest in total MWh generated by STP. On May 19, 2005, Texas Genco LLC increased its undivided interest in STP from 30.8% to 44.0%


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Generation Facilities
 
As of December 31, 2006, NRG’s generation facilities in Texas consisted of approximately 10,760 MW of generation capacity. The following table describes NRG’s electric power generation plants and generation capacity as of December 31, 2006:
 
                     
              Net
   
              Generation
   
              Capacity
   
Plant   Location   % Owned     (MW)(c)   Primary Fuel-type
 
Solid Fuel Baseload Units:
                   
W. A. Parish(a)
  Thompsons, TX     100.0     2,480   Coal
Limestone
  Jewett, TX     100.0     1,700   Lignite/Coal
South Texas Project(b)
  Bay City, TX     44.0     1,100   Nuclear
                     
Total Solid Fuel Baseload
              5,280    
Operating Natural Gas-Fired Units:
                   
Cedar Bayou
  Baytown, TX     100.0     1,500   Natural Gas
T. H. Wharton
  Houston, TX     100.0     1,025   Natural Gas
W. A. Parish (Natural gas)(a)
  Thompsons, TX     100.0     1,190   Natural Gas
S. R. Bertron
  Deer Park, TX     100.0     840   Natural Gas
Greens Bayou
  Houston, TX     100.0     760   Natural Gas
San Jacinto
  LaPorte, TX     100.0     165   Natural Gas
                     
Total Operating Natural Gas-Fired
              5,480    
                     
Total Operating Capacity
              10,760    
                     
 
 
(a) W. A. Parish has nine units, four of which are baseload coal-fired units and five of which are natural gas-fired units.
 
(b) Generation capacity figure consists of the Company’s 44.0% undivided interest in the two units of STP.
 
(c) Actual capacity can vary depending on factors including weather conditions, operational conditions and other factors. ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time. Excludes 2,970 MW of mothballed capacity available for redevelopment.
 
The following is a description of NRG’s most significant revenue generating plants in the Texas region:
 
W.A. Parish — NRG’s W.A. Parish plant is one of the largest fossil-fired plants in the United States based on total MWs of generation capacity. This plant’s power generation units include four coal-fired steam generation units with an aggregate generation capacity of 2,480 MW as of December 31, 2006. Two of these units are 650 MW steam units that were placed in commercial service in December 1977 and December 1978, respectively. The other two units are 570 MW and 610 MW steam units that were placed in commercial service in June 1980 and December 1982, respectively. All four units are serviced by two competing railroads that diversify NRG’s coal transportation options at competitive prices. Each of the four coal-fired units have low-NOx burners and SCR, installed to reduce NOx emissions and baghouses to reduce particulates. In addition, W.A. Parish Unit 8 has a scrubber installed to reduce SO2 emissions. Plant uprate projects completed in 2006 uprated the net generation capacity of W.A. Parish by 17 MW.
 
Limestone — NRG’s Limestone plant is a lignite and coal-fired plant located approximately 140 miles northwest of Houston. This plant includes two steam generation units with an aggregate generation capacity of 1,700 MW as of December 31, 2006. The first unit is an 835 MW steam unit that was placed in commercial service in December 1985. The second unit is an 865 MW steam unit that was placed in commercial service in December 1986. Limestone primarily burns lignite from an on-site mine, but also burns low sulfur coal and petroleum coke. This serves to lower average fuel costs by eliminating fuel transportation costs, which can represent up to two-thirds of delivered fuel costs for plants of this type. NRG owns the mining equipment and facilities and a portion of the lignite reserves located at the mine. Mining operations are conducted by Texas Westmoreland Coal Co., a single purpose, wholly-owned subsidiary of Westmoreland Coal Company and the owner of a substantial portion of the


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remaining lignite reserves. Both units have installed low-NOx burners to reduce NOx emissions and scrubbers to reduce SO2 emissions. In the second quarter of 2006, NRG replaced the high pressure and intermediate pressure turbines, rewound the generator and replaced the main generator step-up transformer of Limestone Unit 2. These upgrades increased the generation capacity by 86 MW.
 
South Texas Project Electric Generating Station, or STP — STP is one of the newest and largest nuclear-powered generation plants in the United States based on total megawatts of generation capacity. This plant is located approximately 90 miles south of downtown Houston, near Bay City, Texas and consists of two generation units each representing approximately 1,250 MW of generation capacity. STP’s two generation units commenced operations in August 1988 and June 1989, respectively. For the year ended December 31, 2006, STP had a zero percent forced outage rate and a 97% net capacity factor.
 
STP is currently owned as a tenancy in common between NRG and two other co-owners. NRG owns a 44%, approximately 1,100 MW, interest in STP, the City of San Antonio owns a 40% interest and the City of Austin owns the remaining 16% interest. Each co-owner retains its undivided ownership interest in the two nuclear-fueled generation units and the electrical output from those units. Except for certain plant shutdown and decommissioning costs and NRC licensing liabilities, NRG is severally liable, but not jointly liable, for the expenses and liabilities of STP. The four original co-owners of STP organized South Texas Project Nuclear Operating Company, or STPNOC, to operate and maintain STP. STPNOC is managed by a board of directors composed of one director appointed by each of the three co-owners, along with the chief executive officer of STPNOC. STPNOC is the NRC-licensed operator of STP. No single owner controls STPNOC and all decisions must be approved by two or more owners who collectively control more than 60% of the interests.
 
The two STP generation units operate under licenses granted by the NRC that expire in 2027 and 2028, respectively. These licenses may be extended for additional 20-year terms if the project satisfies NRC requirements. Adequate provisions exist for long-term on-site storage of spent nuclear fuel throughout the remaining life of the existing STP plant licenses.
 
Repowering NRG — Texas
 
As part of the Company’s Repowering NRG program, NRG has identified a number of proposed projects in Texas that could add important generation capacity to the State. These include, at present, one or more Houston gas-fired generation projects and wind projects, a large baseload coal project, and two new nuclear units. These projects are designed to meet the growing electrical needs of the State of Texas in a pragmatic and environmentally responsible way. Using a balanced portfolio of fuels and technologies, these projects would provide Texas with both new baseload generation, as well as intermediate and peaking generation units that will follow load and provide ancillary services.
 
The following table summarizes the proposed projects currently included in the Repowering NRG program in Texas:
 
         
Facility   Fuel-type   Technology
 
Cedar Bayou
  Gas   Simple/Combined Cycle
Limestone — unit 3
  Coal   Pulverized Coal
STP — Units 3&4
  Nuclear   ABWR
Wind Power
  Wind   Wind turbines
 
Cedar Bayou — In November 2006, NRG filed for a permit with the Texas Commission for Environmental Quality, or TCEQ, to repower single and combined cycle gas units consisting of up to 900 MW at NRG’s Cedar Bayou facility. The Company expects to receive permits and interconnection studies during the second half of 2007.
 
Limestone — NRG is proposing to repower an 800 MW pulverized baseload coal unit at the Company’s Limestone facility in central Texas, referred to as Limestone-3. Limestone-3 would be fueled primarily by PRB coal.
 
STP — NRG is proposing the addition of two nuclear reactors (Units 3 and 4) at the STP nuclear project. Commercial operations are proposed for late 2014 for Unit 3 and late 2015 for Unit 4. NRG has begun licensing


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efforts and the Company anticipates filing a Combined Operating License Application with the NRC during the second half of 2007. NRG is proposing to use General Electric’s Advanced Boiling Water Reactor, or ABWR, technology, which is rated at approximately 1,350 MW per reactor.
 
Wind — The Company has 100-300 MW of wind projects under active development in Texas.
 
Market Framework
 
The ERCOT market is one of the nation’s largest and fastest growing power markets. It represents approximately 85% of the demand for power in Texas and covers the whole state, with the exception of the far west (El Paso), a large part of the Texas Panhandle and two small areas in the eastern part of the state. From 1994 through 2006, peak hourly demand in the ERCOT market grew at a compound annual rate of 3.0%, compared to a compound annual rate of growth of 2.1% in the United States for the same period. For 2006, hourly demand ranged from a low of 20,276 MW to a high of 63,056 MW. ERCOT has limited interconnections compared to other markets in the United States — currently limited to 856 MW of generation capacity, and wholesale transactions within the ERCOT market are not subject to regulation by the Federal Energy Regulatory Commission, or FERC. Any wholesale producer of power that qualifies as a power generation company under the Texas electric restructuring law and that can access the ERCOT electric power grid is allowed to sell power in the ERCOT market at unregulated rates.
 
The ERCOT market has experienced significant construction of new generation plants in recent years, with over 20,000 MW of mostly natural gas-fired combined cycle generation capacity added to the market in the first half of this decade. As of December 31, 2006, aggregate net generation capacity of approximately 76,964 MW existed in the ERCOT market, of which 72.1% was natural gas-fired. Approximately 20,616 MW, or 26.7%, was lower marginal cost generation capacity such as coal, lignite and nuclear plants. NRG’s coal and nuclear fuel baseload plants represent approximately 5,280 MW, or 26%, of the total solid fuel baseload net generation capacity in the ERCOT market. ERCOT has established a target equilibrium reserve margin level of approximately 12.5%; the reserve margin at December 31, 2006, was 16.4%, forecast to drop to 11.4% for 2008 per ERCOT’s latest Capacity Demand and Reserve Report. With the exception of wind generation units, there has been very little generation that has come online since 2004, and the Company expects reserve margins to decrease through 2010 primarily due to load growth. Many new projects have been announced that if materialized would begin to increase the reserve margin after 2010.
 
In the ERCOT market, buyers and sellers enter into bilateral wholesale capacity, power and ancillary services contracts or may participate in the centralized ancillary services market, including balancing energy, which ERCOT administers. An October 1, 2005 “Report on Existing and Potential Electric System Constraints and Needs” found that natural gas-fired power plants set the market price of power more than 90% of the time in the ERCOT market. As a result of NRG’s lower marginal cost for baseload coal and nuclear generation assets, the Company expects these ERCOT assets to generate power nearly 100% of the time they are available.
 
The ERCOT market is currently divided into four regions or congestion zones, namely: North, Houston, South and West, which reflect transmission constraints that are commercially significant and which have limits as to the amount of power that can flow across zones. NRG’s W. A. Parish plant and all its natural gas-fired plants are located in the Houston zone. NRG’s Limestone plant is located in the North zone with STP located in the South zone.
 
The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council, or NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’s main interconnected power transmission grid. ERCOT is responsible for facilitating reliable operations of the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that power production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike power pools with independent operators in other regions of the country, the ERCOT market is not a centrally dispatched power pool and ERCOT does not procure power on behalf of its members other than to maintain the reliable operations of the transmission system. ERCOT also serves as an agent for procuring ancillary services for those who elect not to provide their own ancillary services.
 
Power sales or purchases from one location to another may be constrained by the power transfer capability between locations. Under current ERCOT protocol, the commercially significant constraints and the transfer


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capabilities along these paths are reassessed every year and congestion costs are directly assigned to those parties causing the congestion. This has the potential to increase power generators’ exposure to the congestion costs associated with transferring power between zones.
 
The PUCT has adopted a rule directing ERCOT to develop and implement a wholesale market design that, among other things, includes a day ahead energy market and replaces the existing zonal wholesale market design with a nodal market design that is based on locational marginal prices for power. See also, Regional Regulatory Developments — Texas Region. One of the stated purposes of the proposed market restructuring is to reduce local (intra-zonal) transmission congestion costs. The market redesign project is expected to take effect in late 2008. NRG expects that implementation of any new market design will require modifications to its existing procedures and systems. Although NRG does not expect the Company’s competitive position in the ERCOT market to be materially adversely affected by the proposed market restructuring, the Company does not know for certain how the planned market restructuring will affect its revenues, and some of NRG’s plants in ERCOT may experience adverse pricing effects due to their location on the transmission grid.
 
NORTHEAST
 
NRG’s second largest asset base is located in the Northeast region of the United States and is comprised of investments in generation facilities primarily located in the physical control areas of NYISO, the ISO-NE and PJM.
 
Operating Strategy
 
The Northeast region’s strategy is focused on optimizing the value of NRG’s broad and varied generation portfolio in the three interconnected and actively traded competitive markets: the NYISO, the ISO-NE and the PJM. In the Northeast markets, load-serving entities generally lack their own generation capacity, with much of the generation base aging and the current ownership of the generation highly disaggregated. Thus, commodity prices are more volatile on an as-delivered basis than in other NRG regions due to the distance and occasional physical constraints that impact the delivery of fuel into the region. In this environment, NRG seeks both to enhance its ability to be the low cost wholesale generator capable of delivering wholesale power to load centers within the region from multiple locations using multiple fuel sources, and to be properly compensated for delivering such wholesale power and related services. The generation performance by fuel-type for the recent three-year period is as shown below:
 
                         
    Net Generation  
    2006     2005     2004  
    (In thousands of MWh)  
 
Coal
    11,042       11,363       11,694  
Oil
    1,217       3,148       1,429  
Gas
    1,050       1,735       1,136  
                         
Total
    13,309       16,246       14,259  
                         
 
NRG is focused on capturing the locational value of its plants that are located in or near load centers and inside chronic transmission constraints, in order to improve the economic rationale for repowering of those sites. NRG does this primarily through the advocacy of capacity market reforms. The Company has seen some success in these efforts with the start of the Locational Forward Reserve Markets, or LFRM, in the New England Power Pool, or NEPOOL, which, were effective October 1, 2006, and, in addition, with the start of transition capacity payments which were effective December 1, 2006, together acting as a prelude to the full implementation of the Forward Capacity Market, or FCM, which begins June 1, 2010. Further, on December 22, 2006, FERC approved a settlement regarding PJM’s reliability pricing model, or RPM, effective June 1, 2007.
 
RMR Agreements — Several of the Northeast region’s Connecticut assets are located in transmission-constrained load pockets and have been designated as required to be available to ISO-NE to ensure reliability. These assets are subject to reliability must-run, or RMR, agreements, which are contracts under which NRG agrees to maintain its facilities to be available to run when needed, and are paid to provide these capability services based on the Company’s costs. During 2006, Middletown, Montville and Devon were covered by an RMR agreement.


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Effective January 1, 2007, the region’s Devon plant is no longer covered by an RMR agreement but operates now on a merchant basis. On January 12, 2007, FERC approved the ISO-NE request to eliminate Peaking Unit Safe Harbor, or PUSH, bidding effective June 19, 2007. This decision adversely impacts the value of generation from the Norwalk Harbor plant. NRG anticipates that it will file for an RMR agreement for this plant to be effective upon the elimination of PUSH bidding. To that end, NRG has received a determination letter from ISO-NE that this plant is needed for reliability service.
 
Generation Facilities
 
As of December 31, 2006, NRG’s generation facilities in the Northeast region consisted of approximately 7,240 MW of generation capacity, including assets located in transmission constrained areas, such as in-city New York City — 1,415 MW and southwest Connecticut — 535 MW.
 
The Northeast region power generation assets are summarized in the table below:
 
                     
              Net
   
              Generation
   
Plant   Location   % Owned     Capacity(a)   Primary Fuel-type
 
Oswego
  Oswego, NY     100.0     1,635   Oil
Arthur Kill
  Staten Island, NY     100.0     865   Natural Gas
Middletown
  Middletown, CT     100.0     770   Oil
Indian River
  Millsboro, DE     100.0     780   Coal
Astoria Gas Turbines
  Queens, NY     100.0     550   Natural Gas
Huntley
  Tonawanda, NY     100.0     550   Coal
Dunkirk
  Dunkirk, NY     100.0     585   Coal
Montville
  Uncasville, CT     100.0     500   Oil
Norwalk Harbor
  So. Norwalk, CT     100.0     340   Oil
Devon
  Milford, CT     100.0     140   Natural Gas
Vienna
  Vienna, MD     100.0     170   Oil
Somerset Power
  Somerset, MA     100.0     125   Coal
Connecticut Remote Turbines
  Four locations in CT     100.0     105   Oil
Conemaugh
  New Florence, PA     3.7     65   Coal
Keystone
  Shelocta, PA     3.7     60   Coal
                     
Total Northeast Region
              7,240    
                     
 
 
(a) Excludes 365 MW of inactive capacity.
 
The following is a description of NRG’s most significant revenue generating plants in the Northeast region:
 
Arthur Kill — NRG’s Arthur Kill plant is a natural gas-fired power plant consisting of three units and is located on the west side of Staten Island, New York. The plant produces an aggregate generation capacity of 865 MW from two intermediate load units (Units 20 and 30) and one peak load unit (Unit GT-1). Unit 20 produces an aggregate generation capacity of 350 MW and was installed in 1959. Unit 30 produces an aggregate generation capacity of 500 MW and was installed in 1969. Both Unit 20 and Unit 30 were converted from coal-fired to natural gas-fired facilities in the early 1990s. Unit GT-1 produces an aggregate generation capacity of 15 MW and is activated when ConEd issues a maximum generation alarm on hot days and during thunderstorms.
 
Astoria Gas Turbine — Located in Astoria, Queens, New York, the NRG Astoria Gas Turbine facility occupies approximately 15 acres within the greater Astoria Generating complex which includes several competing generating facilities. NRG’s Astoria Gas Turbine facility has an aggregate generation capacity of approximately 550 MW from 19 operational combustion turbine generators classified into three types of turbines. The first group consists of 12 gas-fired Pratt & Whitney GG-4 Twin Packs in Buildings 2, 3 and 4, which have a net generating capacity of 145 MW per building. The second group consists of Westinghouse Industrial Combustion


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Turbines #191A in Buildings 5, 7 and 8 that fire on liquid distillate with a net generating capacity of approximately 12 MW per building. The third group consists of Westinghouse Industrial Gas Turbines #251GG located in Buildings 10, 11, 12 and 13 and fired on liquid distillate with a net generation capacity of 20 MW per building. The Astoria units also supply Black Start Service to the NYISO. The site also contains tankage for distillate fuel with a capacity of 86,000 barrels.
 
Dunkirk — The Dunkirk plant is a coal-fired plant located on Lake Erie in Dunkirk, New York. This plant produces an aggregate generation capacity of 585 MW from four baseload units. Units 1 and 2 produce up to 95 MW each and were put in service in 1950, and Units 3 and 4 produce approximately 195 MW each and were put in service in 1959 and 1960, respectively. In the spring of 2006, the plant completed changes to switch from eastern bituminous coal to low sulfur PRB coal in order to comply with various federal and state emissions standards, as well as the New York Department of Environmental Conservation, or NYSDEC, settlement referred to in the following paragraph.
 
Huntley — The Huntley plant is a coal-fired plant consisting of six units and is located in Tonawanda, New York, approximately three miles north of Buffalo. The plant has a generation capacity of 550 MW from two intermediate load units (Units 65 and 66) and two baseload units (Units 67 and 68). Units 67 and 68 generate a net capacity of approximately 190 MW each, and were put in service in 1957 and 1958, respectively. Units 65 and 66 generate a net capacity of 85 MW each and were put in service between 1942 and 1954. Units 63 and 64 are inactive and were officially retired in May 2006. On November 30, 2006, NRG gave notice to the New York Department of Public Service of the Company’s intent to retire Units 65 and 66 effective June 3, 2007 pursuant to a settlement agreement reached with NYSDEC in January 2005. Per that agreement, NRG will reduce NOx and SO2 emissions from the Company’s Huntley and Dunkirk plants through 2013 in the aggregate by over 8,090 lbs and 8,690 lbs, respectively. A large portion of these reductions will be achieved by switching to low sulfur western coal and related projects for which NRG has already expended or committed significant capital.
 
Indian River — The Indian River Power plant is a coal-fired plant located in southern Delaware on a 1,170 acre site. The plant consists of four coal-fired steam electric units, Units 1 through 4 and one 15 MW combustion turbine, bringing total plant capacity to approximately 780 MW. Units 1 and 2 are each 80 MW of capacity and were placed in service in 1957 and 1959, respectively. Unit 3 is 165 MW of capacity and was placed in service in 1970, while Unit 4 is 440 MW of capacity and was placed in service in 1980. Units 3 and 4 are equipped with SNCR systems, for the reduction of NOx emissions. All four units are equipped with electrostatic precipitators to remove fly ash from the flue gases as well as low NOx burners with over fired air to control NOx emissions. Units 1, 2 and 3 combust eastern bituminous coal, while Unit 4 is fueled with low sulfur compliance coal.
 
Repowering NRG — Northeast Region
 
The Repowering NRG program in the Northeast is focused on developing the region’s existing facilities, including using IGCC technology and coal in New York and Delaware, in addition to using combined cycle gas turbines and gas peakers (some with dual fuel capability on oil) in the region.
 
The following table summarizes the proposed projects currently included in the Repowering NRG program in the Northeast region:
 
         
Facility   Fuel-type   Technology
 
Huntley
  Coal   IGCC
Indian River
  Coal   IGCC
Montville
  Gas/Oil   Combined Cycle Gas Turbine
Middletown
  Gas/Oil   Gas Peakers
Devon
  Gas/Oil   Gas Peakers
 
Huntley — In December 2006, NRG won a conditional award in a competitive bid process with the New York Power Authority, or NYPA, to build a 600 MW IGCC plant at the Company’s Huntley facility. The bid included selling capacity and energy to NYPA under a long term PPA. As part of the conditional award, NYPA entered into a strategic alliance with NRG to pursue support from federal, state and local programs in order to close the perceived pricing gap between NRG’s proposal and NYPA’s requirements, while preserving the material benefits of NRG’s


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proposal relating to innovative clean coal power generation, including CO2 capture and geologic sequestration plans.
 
Indian River — NRG also submitted a bid in December 2006 for the development of a similar IGCC plant at the Company’s Indian River facility in response to a Request for Proposals, or RFP, issued by Delmarva Power and Light. NRG’s bid proposed a 400 MW long term PPA for energy and capacity from the IGCC facility. The bid is currently under review and a formal award decision is scheduled to occur in the second quarter of 2007. If the bid is accepted, NRG expects to negotiate the terms of the PPA and obtain regulatory approval by the middle of 2007.
 
Connecticut — In December 2006, NRG submitted bids to repower a number of its existing facilities in Connecticut, in response to the State of Connecticut’s RFP process. The bids included separate proposals offering a total of approximately 1,000 MW of new capacity. The largest proposal includes a 630 MW combined cycle unit at the Company’s Montville site. The project covered by this proposal, if accepted, could be converted to an IGCC plant at a later date in response to any state energy and environmental policy objectives requiring baseload capacity that utilizes a plentiful domestic fuel source, such as coal. In addition, this conversion has the potential to bring material environmental benefits to the State of Connecticut, including the ability to capture and potentially sequester CO2. NRG has also submitted bids for a new gas-fired peaking capacity at the Company’s Middletown and Devon sites.
 
Market Framework
 
Although each of the three Northeast ISOs and their respective energy markets are functionally, administratively and operationally independent, they all follow, to a certain extent, similar market designs. Each ISO dispatches power plants to meet system energy and reliability needs, and settles physical power deliveries at Locational Marginal Prices, or LMPs, which reflect the value of energy at a specific location at the specific time it is delivered. This value is determined by an ISO-administered auction process, which evaluates and selects the least costly supplier offers or bids to create a reliable and least-cost dispatch. The ISO-sponsored LMP energy markets consist of two separate and characteristically distinct settlement time frames. The first is a security-constrained, financially firm, day-ahead unit commitment market. The second is a security-constrained, financially settled, real-time dispatch and balancing market. Prices paid in these LMP energy markets, however, are affected by, among other things, market mitigation measures, which can result in lower prices associated with certain generating units that are mitigated because they are deemed to have locational market power, and by $1,000/MWh energy market price caps that are in place in all three northeast ISOs.
 
In addition to energy delivery, the ISOs manage secondary markets for installed capacity, ancillary services and financial transmission rights. All of the three Northeast ISOs have realized, however, that they are not capable of supporting needed investment in new generation without well designed capacity and ancillary service markets. NYISO’s capacity market was the first to receive approval of its proposed demand curve and locational capacity reforms (which are intended to better reflect locational values of capacity resources). ISO-NE and PJM are in the process of implementing their respective versions of reformed capacity markets, namely, a forward capacity market, or FCM, in ISO-NE, and a reliability pricing model, or RPM, proposal in PJM. ISO-NE has instituted a transitional payment for capacity starting December 1, 2006, which starts at a price of $3.05/kW-month and gradually rises to $4.10/kW-month through June 1, 2010, when the FCM market takes effect. In addition, ISO-NE instituted its LFRM market effective October 1, 2006 which provides a capacity payment for qualifying quick start units. NRG bid and was awarded 292 MW of LFRM capacity in the first auction which cleared at the capped rate of $14/kW-month. As indicated above, FERC approved a settlement of the PJM RPM market which will be effective June 1, 2007. For a further discussion, see Item 15 — Note 22 Regulatory Matters, to the Consolidated Financial Statements.
 
SOUTH CENTRAL
 
As of December 31, 2006, NRG owned approximately 2,850 MW of generating capacity in the South Central region of the United States. The region lacks a regional transmission organization or ISO and, therefore, remains a bilateral market, making it less efficient than a region with an ISO-administered energy market using large scale economic dispatch, such as the Northeast region. NRG operates the LaGen Control Area which encompasses the generating facilities and the Company’s cooperative load. As a result, the LaGen control area is capable of


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providing control area services, in addition to wholesale power, that allows NRG to provide full requirement services to load-serving entities, thus making the LaGen Control Area a competitive alternative to the integrated utilities operating in the region.
 
Operating Strategy
 
NRG’s South Central region seeks to capitalize on two factors: (1) its position as a significant coal-fired generator in a market that is highly dependent on natural gas for power generation, and (2) its long-term contractual and historical service relationship with eleven rural cooperatives around Louisiana. NRG’s South Central region works with its cooperative customers to improve contract administration, to expand their and the Company’s customer bases on terms advantageous to all parties and, in some cases, to modify the terms of the Company’s contracts with respect to its current or new customers.
 
The generation performance by fuel-type for the recent three-year period is as shown below:
 
                         
    Net Generation  
    2006     2005     2004  
    (In thousands of MWh)  
 
Coal
    10,968       9,924       10,353  
Gas
    68       85       8  
                         
Total
    11,036       10,009       10,361  
                         
 
Generation Facilities
 
NRG’s generating assets in the South Central region consist primarily of its net ownership of power generation facilities in New Roads, Louisiana, which is referred to as Big Cajun II, and also includes the Sterlington, Rockford, Bayou Cove and Big Cajun peaking facilities.
 
NRG’s power generation assets in the South Central region as of December 31, 2006 are summarized in the table below:
 
                     
              Net
   
              Generation
   
              Capacity
   
Plant   Location   % Owned     (MW)   Primary Fuel-type
 
Big Cajun II(a)
  New Roads, LA     86.0     1,490   Coal
Bayou Cove
  Jennings, LA     100.0     300   Natural Gas
Big Cajun I — (Peakers) Units 3 & 4
  Jarreau, LA     100.0     210   Natural Gas
Big Cajun I — Units 1 & 2
  Jarreau, LA     100.0     220   Natural Gas/Oil
Rockford I
  Rockford, IL     100.0     300   Natural Gas
Rockford II
  Rockford, IL     100.0     145   Natural Gas
Sterlington
  Sterlington, LA     100.0     185   Natural Gas
                     
Total South Central
              2,850    
                     
 
 
(a) NRG owns 100% of Units 1 & 2; 58% of Unit 3
 
Big Cajun II — NRG’s Big Cajun II plant is a coal-fired, sub-critical baseload plant located along the banks of the Mississippi River, near Baton Rouge, Louisiana. This plant includes three coal-fired generation units (Units 1, 2 and 3) with an aggregate generation capacity of 1,730 MW as of December 31, 2006, and generation capacity per unit of 580 MW, 575 MW and 575 MW, respectively. The plant uses coal supplied from the Powder River Basin and was commissioned between 1981 and 1983. NRG owns 100% of Units 1 and 2 and a 58% undivided interest in Unit 3 for an aggregate owned capacity of 1,490 MW of the plant. All three units have been upgraded with low NOx burners and overfire air. The Unit 1 generator has recently been rewound and was optimized with a modern turbine/exciter control system. Units 2 and 3 are planned for generator rewinds, turbine/exciter control replacements and


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additional neural net systems in future years. These efficiency improvements are expected to cost approximately $30 million.
 
Repowering NRG — South Central Region
 
The region’s Repowering NRG strategy is focused on expanding generation capacity at the Company’s Big Cajun facilities, using coal and petcoke as fuel for the plants under best available control technology.
 
The following table summarizes the proposed projects currently included in the Repowering NRG program in the South Central region:
 
         
Facility   Fuel-type   Technology
 
Big Cajun-II — Unit 4
  Coal   Pulverized Coal (BACT)
Big Cajun-I
  Pet coke/Coal   Fluidized Bed Boiler
 
Big Cajun II — Unit 4 — The Company continues the development of a new 775 MW super critical coal-fired generating unit at its Big Cajun II facility. On April 28, 2006, NRG filed an application with the Louisiana Department of Environmental Quality, or LADEQ, to modify the existing permit to allow the Big Cajun II Unit 4 to utilize bituminous, in addition to sub-bituminous, coal. NRG has also entered into project development agreements with potential equity partners for certain ownership interests in Unit 4. However, NRG cannot predict the outcome of its application for the issuance of the modified permit at this time.
 
Big Cajun I — On May 26, 2006, NRG filed with LADEQ a request for an air permit for the addition of a 230 MW facility at the Company’s Big Cajun I facility. This proposed facility will have the ability to utilize petroleum coke, coal, or biomass as its fuel source.
 
Market Framework
 
NRG’s assets in the South Central region are located within the franchise territories of vertically integrated utilities, primarily Entergy Corp., or Entergy. Entergy performs the scheduling, reserve and reliability functions that are administered by the ISOs in certain other regions of the United States and Canada. Although the reliability functions performed are essentially the same, the primary differences between these markets lie in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counterparties. Transacting counterparties are required to reserve and purchase transmission services from the relevant transmission owners at their FERC-approved tariff rates. Included with these transmission services are the reserve and ancillary costs.
 
As of December 31, 2006, NRG had long-term all-requirements contracts with eleven Louisiana distribution cooperatives with initial terms ranging from five to twenty-five years. The region had seven contracts that expire in 2025, with the remaining four contracts expiring between 2009 and 2014. In addition, NRG also has certain long-term contracts with the Municipal Energy Authority of Mississippi, South Mississippi Electric Power Association, and Southwestern Electric Power Company, which collectively comprise an additional 13% of region’s contract load requirement.
 
During peak demand periods, NRG’s Big Cajun II assets are insufficient to serve the requirements of the customers under these contracts, and at such times NRG typically purchases power from other power producers in the region, frequently at higher prices than can be recovered under the Company’s contracts. As the loads of the region’s customers grow, the Company can expect this imbalance to worsen, unless NRG is successful in renegotiating the terms of these long-term contracts. NRG has been successful in negotiating contract modifications with several of the region’s long-term cooperative customers, which has prevented the addition of large industrial or municipal loads at the contract rates. Also, to minimize this risk during the peak summer and winter seasons, the Company has been successful in entering into tolling agreements, which effectively reduce the need for spot market purchases.


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WEST
 
NRG’s portfolio in the West region currently consists of the El Segundo Generating Station, the Encina Generating Station and 13 combustion turbines with total generation capacity of approximately 1,965 MW. On March 31, 2006, NRG purchased Dynegy Inc’s 50% ownership interest in WCP and became the sole owner of the WCP assets. In addition, NRG owns a 50% interest in the Saguaro power plant located in Nevada. On January 3, 2007, NRG sold the Red Bluff and the Chowchilla II power plants to Wayzata Investment Partners LLC.
 
Operating Strategy
 
NRG’s West region strategy is focused on maximizing the cash flow and value associated with its generating plants while protecting and potentially realizing the commercial value of the underlying real estate. There are three principal components to this strategy: (1) responding to expected market demand, initially in load serving entity RFOs and eventually into a capacity market, and (2) using existing emission credits to permit new more efficient generating units at existing sites or siting plants at less valuable property and optimizing the value of the region’s coastal property for other purposes.
 
The Company’s Encina Station has sold all energy and capacity, 965 MW, in the aggregate, to SDG&E through 2009, on a tolling basis, and recovers its operating costs plus a capacity payment. The El Segundo Station has sold all energy and capacity, 670 MW, in the aggregate, to a load-serving entity through April 30, 2008, on a tolling basis, and recovers its operating costs plus a capacity payment. The San Diego Combustion Turbines, 190 MW, in the aggregate, are subject to an RMR agreement with the CAISO through calendar year 2007, on a tolling basis, and recover their costs plus a return of investment.
 
The Saguaro power plant is located in Henderson, Nevada, and is contracted to Nevada Power and two steam hosts. The Saguaro plant is contracted to Nevada Power through 2022, one steam host, referred to as Pioneer, whose contract expires in 2007, with a negotiated renewal, and a steam off taker, Ocean Spray, whose contract runs through 2015. Saguaro Power Company, LP, the project company, procures fuel in the open market. NRG manages its share of any fuel price risk through NRG’s commodity price risk strategy.
 
Generation Facilities
 
NRG’s power generation assets in the West region as of December 31, 2006 are summarized in the table below:
 
                     
              Net
   
              Generation
   
              Capacity
   
Plant   Location   % Owned     (MW)   Primary Fuel-type
 
Encina
  Carlsbad, CA     100.0     965   Natural Gas
El Segundo
  El Segundo, CA     100.0     670   Natural Gas
Cabrillo II
  San Diego, CA     100.0     190   Natural Gas
Red Bluff(a)
  Northern CA     100.0     45   Natural Gas
Chowchilla(a)
  Northern CA     100.0     50   Natural Gas
Saguaro
  Henderson, NV     50.0     45   Natural Gas
                     
Total West Region
              1,965    
                     
 
 
(a) Sold on January 3, 2007
 
The following are descriptions of the Company’s most significant revenue generating plants in the West region:
 
Encina — The Encina Station is located in Carlsbad, California and has a combined generating capacity of 965 MW from five fossil-fuel steam-electric generating units and one combustion turbine. The five fossil-fuel steam-electric units provide intermediate load services and primarily use natural gas but also maintain dual fuel capability. Dual fuel capability allows the units to use oil for emergency reliability backup only under a gas supply force majeure conditions. Also located at the Encina Station is a combustion turbine that provides peaking services


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of 15 MW. Units 1, 2 and 3 each have a generation capacity of approximately 107 MW and were installed in 1954, 1956 and 1958, respectively. Units 4 and 5 have a generation capacity of approximately 300 MW and 330 MW respectively, and were installed in 1973 and 1978. The combustion turbine was installed in 1966. Units 1, 2 and 3 are projected to be retired after 2010. Low NOx burner modifications and SCR equipment has been installed on Units 1, 2, 3, 4 and 5.
 
El Segundo — The El Segundo plant is located in El Segundo, California and produces an aggregate generation capacity of 670 MW from two gas-fired intermediate load units (Units 3 and 4). These units, which have a generation capacity of 335 MW each, were installed in 1964 and 1965, respectively. SCR equipment has been installed on Units 3 and 4.
 
Repowering NRG — West Region
 
The region’s Repowering NRG strategy is focused on the construction of new capacity to meet increasing local requirements using natural gas at the Company’s existing facilities, as well as the development of potential wind projects through the Company’s wholly-owned subsidiary, Padoma Wind Power, LLC.
 
The following table summarizes the proposed projects currently included in the Repowering NRG program in the West region.
 
         
Facility   Fuel-type   Technology
 
Long Beach
  Gas   Simple Cycle Gas Turbine
Long Beach Repower
  Gas   Combined Cycle Gas Turbine
Encina Peakers
  Gas   Simple Cycle Gas Turbine
El Segundo 1&2
  Gas   Combined Cycle Gas Turbine
Wind Power — California
  Wind   Wind turbines
El Segundo 3&4
  Gas   Combined Cycle Gas Turbine
 
Long Beach — In November 2006, NRG was awarded a 260 MW PPA by Southern California Edison to repower Units 1-4 at the Company’s Long Beach Generating Station in Long Beach, California. The PPA term commences August 1, 2007 and continues for ten years.
 
El Segundo 1& 2 Repower Project  — NRG has permits from the California Energy Commission and Air District to construct a new gas-fired combined cycle plant at the Company’s El Segundo facility to replace the retired units at the site. NRG anticipates seeking amendments to these permits to substitute equipment that will not require the use of once-through sea water cooling. The reconfigured project is included in a load-serving entity’s RFO process which is scheduled to announce PPA contract awards for new capacity in early 2008.
 
In addition, the Company has submitted bids to one of the load-serving entities for two more projects in the West region. The Company expects to know the outcome of these bids sometime during the second half of 2007.
 
Market Framework
 
NRG’s assets in the West region consist primarily of older, higher heat rate, gas-fired plants in southern California. These plants, while older and less efficient than newer combined cycle plants, are under tolling agreements for 2007. CAISO has designated all of the units comprising El Segundo, Encina and Cabrillo II to be capacity that meets the local capacity procurement requirements of the local load-serving entities. At times, all of the plants have been designated as RMR, which entitles designated plants to certain fixed-cost payments from the CAISO for the right to dispatch those units during periods of locational constraints. Currently, the El Segundo unit does not have an RMR agreement with CAISO, but has been designated as a local capacity resource in the Western Los Angeles area and has a tolling agreement for its full capacity with a local major utility for the period May 1, 2006 through April 30, 2008. All units at Encina and Cabrillo II have been designated as local capacity resources for the San Diego load pocket and were designated as RMR units for 2007. Per the RMR agreement, CAISO has an option to renew those units for RMR service into 2008. Encina has a tolling agreement for its full capacity with SDG&E for the period January 1, 2007 through December 31, 2009.


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INTERNATIONAL
 
As of December 31, 2006, NRG, through certain foreign subsidiaries, had investments in power generation projects located in Australia, Germany and Brazil with approximately 1,235 MW of total generating capacity. In addition, NRG owns interests in coal mines located in Germany. The Company’s strategy is to maximize its return on investment and therefore concentrates on contract management; monitoring of its facility operators to ensure safe, profitable and sustainable operations; management of cash flow and finances; and growth of its businesses through investments in projects related to current businesses.
 
NRG’s international power generation assets as of December 31, 2006 are summarized in the table below:
 
                     
              Net
   
              Generation
   
Plant   Location   % Owned     Capacity   Primary Fuel-type
 
Gladstone
  Australia     37.5     605   Coal
Schkopau
  Germany     41.9     400   Lignite
MIBRAG
  Germany     50.0     75   Lignite
ITISA
  Brazil     99.2     155   Hydro
                     
Total International
              1,235    
                     
 
Australia — On June 8, 2006, NRG announced the sale of the Company’s 37.5% equity interest in the Gladstone power station, or Gladstone, and its associated 100% owned NRG Gladstone Operating Services to Transfield Services, an Australia-based provider of operations, maintenance, ownership and asset management services for a purchase price of approximately $189 million (AU$239 million) subject to customary purchase price adjustments, plus assumption of NRG’s share of Gladstone’s unconsolidated debt and cash of approximately $61 million (AU$77 million) and approximately $28 million (AU$35 million), respectively. After-tax cash proceeds are expected to be in excess of $185 million (AU$234 million). The sale is pending until NRG satisfies certain conditions, particularly the securing of certain consents and waivers from the other owners of the project, or agrees to complete the sale on alternative terms. NRG is seeking to close the transaction in 2007.
 
Germany — NRG’s interests in Germany include a 50% equity interest in MIBRAG, which mines approximately 20 million metric tons of lignite per year and owns 150 MW of electric generation capacity, and a 41.9% equity interest in Schkopau, a 900 MW generating plant fueled with lignite from MIBRAG. NRG does not have direct operational control of either of these facilities.
 
Approximately 89% of MIBRAG’s revenues are generated from lignite sales. MIBRAG’s generation capacity comprises three plants, 40% of whose output is used to power MIBRAG’s mining operations and the balance sold under contract to EnviaM, the local distribution utility. NRG, through its wholly-owned subsidiary Saale Energie Gesellschaft, or SEG, owns 400 MW of the Schkopau plant’s electric capacity which is sold under a long term contract to Vattenfall Europe Generation.
 
Brazil — NRG owns a 155 MW hydro-electric power plant located in the state of Mato Grosso, Brazil. NRG currently has a 99.2% interest in the plant.
 
THERMAL
 
Through its wholly-owned subsidiary, NRG Thermal LLC, or NRG Thermal, the Company owns thermal and chilled water businesses that have a steam and chilled water capacity of approximately 1,230 megawatt thermal equivalents, or MWt. As of December 31, 2006, NRG Thermal provided steam heating to approximately 550 customers and chilled water to 95 customers in five different cities in the United States. The Company’s thermal businesses in Pittsburgh, Harrisburg and San Francisco are regulated by their respective state Public Utility Commission. The other thermal businesses are subject to the terms of the contract with the off-takers. In addition, NRG Thermal owns and operates three thermal projects that serve industrial and government customers with high-pressure steam and hot water. NRG Thermal also owns a 90 MW combustion turbine peaking generation facility and a 12 MW coal-fired cogeneration facility in Dover, Delaware as well as a 16 MW gas-fired project in


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Harrisburg, Pennsylvania. Approximately 40% of NRG Thermal’s revenues are derived from its district heating and chilled water business in Minneapolis, Minnesota.
 
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 CFTC, FERC, NRC, PUCT and other public utility commissions in certain states where NRG’s generating assets are located. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which it participates.
 
The operations of, and wholesale electric sales from, NRG’s Texas region are not subject to regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. As discussed below, these operations are subject to regulation by PUCT, as well as to regulation by the NRC with respect to the Company’s ownership interest in STP.
 
Commodities Futures Trading Commission, or CFTC
 
CFTC, among other things, has regulatory oversight authority over the trading of electricity and gas commodities, including financial products and derivatives, under the Commodity Exchange Act, or CEA. Specifically, under existing statutory authority, CFTC has the authority to commence enforcement actions and seek injunctive relief against any person, whenever that person appears to be engaged in the communication of false or misleading or knowingly inaccurate reports concerning market information or conditions that affected or tended to affect the price of natural gas, a commodity in interstate commerce, or actions intended to or attempting to manipulate commodity markets. CFTC also has the authority to seek civil monetary penalties, as well as the ability to make referrals to the Department of Justice for criminal prosecution, in connection with any conduct that violates the CEA. Proposals are pending in Congress to expand CFTC oversight of the over-the-counter markets and bilateral financial transactions.
 
Federal Energy Regulatory Commission
 
FERC, among other things, regulates the transmission and the wholesale sale of electricity in interstate commerce under the authority of the Federal Power Act, or FPA. In addition, under existing regulations, FERC determines whether an entity owning a generation facility is an Exempt Wholesale Generator, or EWG, as defined in the Public Utility Holding Company Act of 2005, or PUHCA of 2005. FERC also determines whether a generation facility meets the ownership and technical criteria of a Qualifying Facility, or QF, under Public Utility Regulatory Policies Act of 1978, or PURPA. Each of NRG’s U.S. generating facilities has either been determined by FERC to qualify as a QF, or the subsidiary owning the facility has been determined to be a EWG.
 
Federal Power Act — The FPA gives FERC exclusive rate-making jurisdiction over the wholesale sale of electricity and transmission of electricity in interstate commerce. Under the FPA, FERC, with certain exceptions, regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as public utilities. The FPA also gives FERC jurisdiction to review certain transactions and numerous other activities of public utilities. NRG’s QFs are currently exempt from the FERC’s rate regulation under Sections 205 and 206 of the FPA to the extent that sales are made pursuant to a state regulatory authority’s implementation of PURPA.
 
Public utilities under the FPA are required to obtain FERC’s acceptance, pursuant to Section 205 of the FPA, of their rate schedules for the wholesale sale of electricity. All of NRG’s non-QF generating and power marketing companies in the United States make sales of electricity pursuant to market-based rates authorized by FERC. FERC’s orders that grant NRG’s generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power, create barriers to entry, or engage in abusive affiliate transactions. In addition, NRG’s market-based sales are subject to certain market behavior rules and, if any of its generating or power marketing companies were deemed to have violated any one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority, as well as criminal and civil penalties. As a condition to the orders granting NRG market-based rate authority, every three years NRG is required to file a market update to demonstrate that it continues to meet FERC’s standards with respect to generating market


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power and other criteria used to evaluate whether entities qualify for market-based rates. NRG is also required to report to FERC any material changes in status that would reflect a departure from the characteristics that FERC relied upon when granting NRG’s various generating and power marketing companies’ market-based rates. If NRG’s generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules.
 
Section 203 of the FPA requires FERC’s prior approval for the transfer of control of assets subject to FERC’s jurisdiction. Section 204 of the FPA gives FERC jurisdiction over a public utility’s issuance of securities or assumption of liabilities. However, FERC typically grants blanket approval for future securities issuances and the assumption of liabilities to entities with market-based rate authority. In the event that one of NRG’s generating and power marketing companies were to lose its market-based rate authority, such company’s future securities issuances or assumption of liabilities could require prior approval from FERC.
 
In compliance with Section 215 of the Energy Policy Act of 2005, or EPAct of 2005, FERC has approved the North American Electric Reliability Corporation, or NERC, as the national Energy Reliability Organization, or ERO. As the ERO, NERC will be responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. NRG is responsible for complying with the standards in the regions in which it operates. The ERO will have the ability to assess financial penalties for non-compliance beginning in June 2007.
 
Public Utility Holding Company Act of 2005 — PUHCA of 2005 provides FERC with certain authority over and access to books and records of public utility holding companies not otherwise exempt by virtue of their ownership of EWGs, QFs, and Foreign Utility Companies, or FUCOs. NRG is a public utility holding company, but because all of the Company’s generating facilities have QF status or are owned through EWGs or FUCOs, it is exempt from the accounting, record retention, and reporting requirements of PUHCA.
 
Public Utility Regulatory Policies Act — PURPA was passed in 1978 in large part to promote increased energy efficiency and development of independent power producers. PURPA created QFs to further both goals, and FERC is primarily charged with administering PURPA as it applies to QFs. As discussed above, under current law, some categories of QFs may be exempt from regulation under the FPA as public utilities. PURPA incentives also initially included a requirement that utilities must buy and sell power to QFs. Among other things, EPAct of 2005 provides for the elimination of the obligation imposed on certain utilities to purchase power from QFs at an avoided cost rate under certain conditions. However, the purchase obligation is only eliminated if FERC first finds that a QF has non-discriminatory access to wholesale energy markets having certain characteristics, including nondiscriminatory transmission and interconnection services provided by a regional transmission entity in certain circumstances. Existing contracts entered into under PURPA are not expected to be impacted; however, certain of NRG’s QFs currently interconnect into markets that may meet the qualifications for elimination of the PURPA purchase requirement. If the obligation to purchase from some or all of NRG’s QFs is terminated, NRG will need to find alternative purchasers for the output of these QFs once their current contracts expire. Such alternative purchases will be at prevailing market rates, which may not be as favorable as the terms of NRG’s PURPA sales arrangements under existing contracts and thus may diminish the value of the Company’s QFs. In addition, under FERC regulations for implementing EPAct of 2005, QFs not making sales pursuant to state-approved avoided cost rates will become subject to FERC’s ratemaking authority under the FPA and be required to obtain market rate authority in order to be allowed to sell power at market-based rates.
 
Nuclear Regulatory Commission, or NRC
 
The NRC is authorized under the Atomic Energy Act of 1954, as amended, or the AEA, among other things, to grant licenses for, and regulate the operation of, commercial nuclear power reactors. As a holder of an ownership interest in STP, NRG is an NRC licensee and is subject to NRC regulation. The NRC license gives the Company the right to only possess an interest in STP but not to operate it. Operating authority under the NRC operating license for STP is held by STPNOC. NRC regulation involves licensing, inspection, enforcement, testing, evaluation, and modification of all aspects of plant design and operation including the right to order a plant shutdown, technical and financial qualifications, and decommissioning funding assurance in light of NRC safety and environmental


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requirements. In addition, NRC’s written approval is required prior to a licensee transferring an interest in its license, either directly or indirectly. As a possession-only licensee, i.e., non-operating co-owner, the NRC’s regulation of NRG is primarily focused on the Company’s ability to meet its financial and decommissioning funding assurance obligations. In connection with the NRC license, the Company and its subsidiaries have a support agreement to provide up to $120 million to support operations at STP.
 
Decommissioning Trusts — Upon expiration of the operating terms of the operation licenses for the two generating units at STP, currently scheduled for 2027 and 2028, the co-owners of STP are required under federal law to decontaminate and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning obligations unless it is a rate-regulated utility, or a state or municipal entity that sets its own rates, or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that the trust, plus allowable earnings, will equal the estimated decommissioning obligations by the time the decommissioning is expected to begin.
 
As a result of the acquisition of Texas Genco LLC, NRG through its 44% ownership interest has become the beneficiary of decommissioning trusts that have been established to provide funding for decontamination and decommissioning of STP. CenterPoint Energy Houston Electric, LLC, or CenterPoint, and American Electric Power, or AEP, collect, through rates or other authorized charges to their electric utility customers, amounts designated for funding NRG’s portion of the decommissioning of the facility.
 
In the event that the funds from the trusts are ultimately determined to be inadequate to decommission the STP facilities, the original owners of the Company’s STP interests, CenterPoint and AEP, each will be required to collect, through their PUCT-authorized non-bypassable rates or other charges to customers, additional amounts required to fund NRG’s obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective rate payers of CenterPoint or AEP, or their successors.
 
Public Utility Commission of Texas, or PUCT
 
NRG’s Texas generation subsidiaries are registered as power generation companies with PUCT. PUCT also has jurisdiction over power generation companies with regard to the administration of nuclear decommissioning trusts, PUCT state-mandated capacity auctions, and the implementation of measures to mitigate undue market power that a power generation company may have and to remedy market power abuses in the ERCOT market and, indirectly, through oversight of ERCOT. PMI is registered as a power marketer with the PUCT and thus is also subject to the jurisdiction of the PUCT with respect to its sales in ERCOT.
 
Regional Regulatory Developments
 
In New England, New York, the Mid-Atlantic region, the Midwest and California, FERC has approved regional transmission organizations, also commonly referred to as independent system operators, or ISOs. Most of these ISOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by FERC and associated ISO market rules. These tariffs/market rules dictate how the capacity and energy markets operate, how market participants may make bilateral sales with one another, and how entities with market-based rates are compensated within those markets. The ISOs in these regions also control access to and the operation of the transmission grid within their regions. In Texas, pursuant to a 1999 restructuring statute, the PUCT has granted similar responsibilities to ERCOT.
 
NRG is affected by rule/tariff changes that occur in the ISO regions. The ISOs that oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address market power or volatility in these markets. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of NRG’s generation facilities that sell capacity and energy into the wholesale power markets. In addition, new approaches to the sale of electric power have been proposed, and it is not yet clear how they will operate in times of market stress or whether they will provide adequate compensation to generators over the long term.


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Texas Region
 
ERCOT has adopted “Texas Nodal Protocols” that will revise the wholesale market design to incorporate locational marginal pricing (in place of the current ERCOT zonal market). Major elements of the Texas Nodal Protocols include the continued capability for bilateral contracting of energy and ancillary schedules, a financially binding day-ahead market, resource-specific energy and ancillary service bid curves, the direct assignment of all congestion rents, nodal energy prices for resources, aggregation of nodal to zonal energy prices for loads, congestion revenue rights (including pre-assignment for public power entities), and pricing safeguards. The PUCT approved the Texas Nodal Protocols on April 5, 2006, and full implementation of the new market design is expected in December 2008. In other rulemakings, the PUCT has expanded its enforcement policy, increased market oversight, and established market and generator-specific data disclosure requirements designed to increase market transparency. Certain entity specific data disclosure provisions have been stayed by order of a Texas appellate court.
 
Northeast Region
 
New England — NRG’s Middletown and Montville facilities continue to be operated pursuant to RMR agreements that were accepted by the Commission on February 1, 2006 (effective January 1, 2006). Unless terminated earlier, the Middletown and Montville RMR agreements are expected to terminate upon the commencement of the Forward Capacity Market, as discussed below. The Devon RMR Agreement terminated on December 31, 2006.
 
On March 7, 2006, a broad group of New England market participants filed a settlement that provides for interim capacity transition payments for all generators in New England for the period starting December 1, 2006 through May 31, 2010, and the establishment of FCM, commencing June 1, 2010. The FCM established by the settlement will operate an annual descending clock forward capacity auction, normally three years in advance, and will serve as the principal mechanism by which ISO-NE will obtain its installed capacity requirement. For the Company’s Connecticut units subject to RMR agreements, any transition payment will be credited against the monthly availability payment for those units, resulting in no additional revenues for those units. NRG’s other New England generation units are eligible for the transition payments. On June 16, 2006, FERC issued an order accepting the settlement, which was reaffirmed on rehearing by order dated October 31, 2006. On December 28, 2006, the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts filed an appeal of the FERC orders accepting the settlement with U.S. Court of Appeals for the D.C. Circuit. Interim capacity transition payments provided for under the FCM settlement commenced December 1, 2006, as scheduled.
 
On May 12, 2006, FERC issued an order accepting ISO-NE’s Ancillary Service Market Phase II package that includes a LFRM. This order was reaffirmed on rehearing on October 25, 2006. NRG’s quick-start units are well-suited to provide this service. For the eight-month winter period beginning October 1, 2006, the LFRM market for Connecticut cleared at the cap of $14/kW-month. NRG sold 292 MW in the LFRM auction and expects its participation in this market to positively contribute to revenues from the region.
 
On January 12, 2007, FERC accepted proposed amendments to ISO-NE’s market rules that eliminate the PUSH bidding mechanism effective June 19, 2007. The elimination of PUSH bidding will impact the Company’s Norwalk Harbor facility, and the Company anticipates seeking an RMR agreement for Norwalk Harbor Units 1 and 2.
 
New York — On December 22, 2006, the NYISO filed proposed tariff revisions that impose additional market power mitigation on the current owners of its divested generation units in New York City, including NRG’s Arthur Kill and Astoria facilities. The proposed mitigation effectively lowers the bid cap currently set forth in the NYISO tariff from $105/kW-year to $82/kW-year. This proposal could adversely impact capacity revenues from these units and NRG is contesting this filing before FERC.
 
On January 5, 2007, the Executive Committee of the New York State Reliability Council voted to change the Installed Reserve Margin, or IRM, from 18% to 16.5%. This change, which must be approved by FERC, will become effective for the May 2007 through April 2008 capacity year and will reduce the amount of capacity that must be purchased by load-serving entities.


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PJM — On December 22, 2006, FERC issued an order approving the settlement agreement filed September 29, 2006, in the Reliability Pricing Model, or RPM, proceeding. The settlement agreement proposes to implement RPM, the key components of which include the determination of capacity prices through use of a downward-sloping demand curve, locational pricing, and a forward capacity market. PJM anticipates conducting its first auction for the 2007-08 delivery years in April 2007 and implementing the RPM capacity market on June 1, 2007. The RPM settlement effectively accepts PJM’s August 31, 2006 filing with a number of revisions, as set forth in the settlement and December 22, 2006 order. NRG considers these market reforms to be a positive development for its assets in the region.
 
South Central Region
 
Entergy has begun to implement its Independent Coordinator of Transmission, or ICT, proposal that will provide (i) independent oversight over the operations of the Entergy transmission system, including the processing of interconnection and transmission requests; (ii) a new process and standard for assigning cost responsibility for transmission upgrades; and (iii) a new weekly procurement process that will allow both Entergy and NRG, as a purchaser of power, to more efficiently utilize the transmission system. The Southwest Power Pool has been selected as the ICT and began performing its responsibilities in November 2006.
 
Entergy’s ICT proposal will impact both the region’s existing operations by improving transmission access and competitive opportunities and the region’s development opportunities by administering the interconnection process. Certain issues regarding (i) the development of the base transmission plan; (ii) control over Entergy’s transmission models; and (iii) Entergy’s proposal to implement participant funding, are still being contested.
 
West Region
 
On December 1, 2006, NRG filed with FERC an extension of the existing RMR agreements for NRG’s Cabrillo Power I, LLC’s Encina facility, and Cabrillo Power II, LLC’s San Diego Jets facility for 2007, and to continue the existing rate effective January 1, 2007. On January 24, 2007, FERC accepted the Cabrillo I filing. On January 30, 2007, FERC accepted the Cabrillo II filing, subject to refund, in response to protests filed by the CPUC and CAISO, and established settlement procedures. NRG has negotiated a three-year bilateral arrangement with SDG&E for Encina that insulates Encina from any revenue impact associated with the RMR agreement.
 
On September 21, 2006, FERC conditionally accepted the CAISO’s Market Redesign and Technology Upgrade, or MRTU, proposal which is currently scheduled to go in effect in January 31, 2008. Significant components of the MRTU include (i) locational marginal pricing of energy; (ii) a more effective congestion management system; (iii) a day-ahead market; and (iv) an increase to the existing bid caps. NRG considers these market reforms to be a positive development for its assets in the region. Several parties have requested rehearing, which remains pending.
 
On July 20, 2006, the CPUC issued its order towards establishing a standard Resource Adequacy Capacity Product that followed its decision to impose local capacity requirements, which took effect January 1, 2007. On the same date, the CPUC issued its order on long-term resource procurement that requires SCE to procure at least 1,500 MW.
 
In November 2006, NRG was awarded a 260 MW PPA by Southern California Edison to repower Units 1-4 at the Company’s Long Beach Generating Station in Long Beach, California. On February 22, 2007, an intervener sought rehearing of the CPUC approval of the agreement and is contesting the PPA at FERC.
 
See also Item 15 — Note 22, Regulatory Matters, to the Consolidated Financial Statements for a further discussion.
 
Environmental Matters
 
NRG is subject to a wide range of environmental regulations across a broad number of jurisdictions in the development, ownership, construction and operation of domestic and international projects. These laws and regulations generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental laws have become increasingly stringent in recent years, especially


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around the regulation of air emissions from power generators. Such laws generally require regular capital expenditures for power plant upgrades, modifications and the installation of certain pollution control equipment. In general, future laws and regulations are expected to require the addition of emissions control or other environmental quality equipment or the imposition of certain restrictions on the operations of the Company’s facilities. NRG expects that future liability under, or compliance with, environmental requirements could have a material effect on the Company’s operations or competitive position.
 
Federal Environmental Initiatives
 
Air — On May 18, 2005, the US Environmental Protection Authority, or USEPA, published the Clean Air Mercury Rule, or CAMR, to permanently cap and reduce mercury emissions from coal-fired power plants. CAMR imposes limits on mercury emissions from new and existing coal-fired plants and creates a market-based cap-and-trade program that will reduce nationwide utility emissions of mercury in two phases, 2010 and 2018. Texas and Louisiana will adopt the CAMR federal implementation plan, or FIP, when it is finalized by USEPA. Certain states in which NRG operates coal plants in NRG’s Northeast region such as Delaware, Massachusetts and New York have proposed or adopted state implementation plans in lieu of the CAMR FIP. Provisions for mercury monitoring and mitigation technologies are included in the budget and environmental capital expenditures for NRG’s coal plants.
 
On May 12, 2005, the USEPA published the Clean Air Interstate Rule, or CAIR. This rule applies to 28 eastern states and the District of Columbia and caps SO2 and NOx emissions from power plants in two phases; 2010 and 2015 for SO2 and 2009 and 2015 for NOx. CAIR will apply to some of the Company’s power plants in New York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois, Pennsylvania, Maryland and Texas. On August 24, 2005, the USEPA published a proposed FIP to ensure that generators affected by CAIR reduce emissions on schedule. In parallel: (i) on December 20, 2005, the USEPA signed proposed revisions to address attainment for fine particulates, or NAAQS for PM2.5, which will require affected states to implement further rules to address SO2 and NOx emissions; and (ii) on November 9, 2005, the USEPA proposed the second phase of the 8-hour ozone NAAQS rule relating to NOx emissions. A number of environmental groups, states and industry organizations challenged aspects of the CAIR. The challenges were consolidated into South Coast Air Quality Management District v. EPA. In a ruling on December 22, 2006, the D.C. Circuit overturned portions of USEPA’s Phase I implementation rule for the new 8-hour ozone standard. Specifically, the court ruled that USEPA could revoke the 1-hour standard as long as there was no backsliding from more stringent control measures. This ruling could result in the imposition of fees under Section 185 of the Clean Air Act, or the CAA, on volatile organic carbon, or VOC, and NOx emissions in severe non-attainment areas. The fees could be as high as $7,700/ton for emissions above 80% of baseline emissions levels. Depending on the determination of baseline emission levels, this could materially impact NRG’s operations in California, New York City and Texas.
 
The Clean Air Visibility Rule was published by the USEPA on July 6, 2005. The rule requires regional haze controls by targeting SO2 and NOx emissions from sources including power plants of a certain vintage through the installation of Best Available Retrofit Technology, or BART, in certain cases. States must develop implementation plans by December 2007. Most of the Company’s facilities will likely be able to satisfy their obligations under the BART rule through compliance with the more stringent CAIR. Accordingly, no material additional expenditures are anticipated beyond those required by CAIR.
 
Increased public concern and mounting political pressure may result in federal requirements to reduce or mitigate the effects of GHG. NRG’s generating portfolio includes coal-, oil- and gas-fired plants, which emit CO2, a GHG, and will likely be subject to proposed regulation which could affect NRG’s costs of operation. NRG is taking steps now to mitigate any potential adverse impacts, including investments in non-fossil generation and investments in generation technologies that will more easily allow the company to manage and control CO2 emissions.
 
In the 1990s, the USEPA commenced an industry-wide investigation of coal-fired electric generators to determine compliance with environmental requirements under the CAA associated with repairs, maintenance, modifications and operational changes made to facilities over the years. As a result, the USEPA and several states filed suits against a number of coal-fired power plants in mid-western and southern states alleging violations of the CAA New Source Review, or NSR, Prevention of Significant Deterioration, or PSD, requirements. EPA has issued


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an NOV against NRG’s Big Cajun II plant alleging that NRG’s predecessors had undertaken projects that triggered requirements under the PSD program, including the installation of emission controls. NRG has evaluated the claims and believes they have no merit. Nonetheless, NRG has had discussions with EPA about resolving the claims. See the South Central regional below for a further discussion.
 
Water — In July 2004, USEPA published rules governing cooling water intake structures at existing power facilities commonly referred to as the Phase II 316(b) rules. The rules specify standards for cooling water intake structures at existing power plants using the largest amounts of cooling water. These rules will require implementation of the Best Technology Available, or BTA, for minimizing adverse environmental impacts unless a facility shows that such standards would result in very high costs or little environmental benefit. On January 25, 2007, the 2nd Circuit Court of Appeals made its decision in the Riverkeeper vs. US EPA appeal over the Phase II 316(b) regulation. Riverkeeper prevailed on nearly all issues and the decision essentially remands all of the important aspects of the rule back to EPA for reconsideration and restricted EPA’s ability to allow generators to substitute mitigation for aquatic species losses through habitat restoration or other measures. The Phase II 316(b) regulation affects a number of NRG’s plants, specifically those with once-through cooling systems. While NRG has conducted a number of the requisite studies, until all the needed studies throughout the Company’s fleet have been completed, consultations on the results have occurred with USEPA or its delegated state or regional agencies, and EPA concludes its reconsideration of the 316(b) rules, it is not possible to estimate with certainty the capital costs that will be required for compliance with the Phase II 316(b) rules.
 
Nuclear Waste — Under the U.S. Nuclear Waste Policy Act of 1982, the federal government must remove and ultimately dispose of spent nuclear fuel and high-level radioactive waste from nuclear plants such as STP. Consistent with the Act, owners of nuclear plants, including NRG and the other owners of STP, entered into contracts setting out the obligations of the owners and the U.S. Department of Energy, or DOE, including the fees being paid by the owners for DOE’s services. Since 1998, the DOE has been in default on its obligations to begin removing spent nuclear fuel and high-level radioactive waste from reactors. On January 28, 2004, Texas Genco LP and the other owners of STP filed a breach of contract suit against the DOE in order to protect against the running of a statute of limitations.
 
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the State. The State of Texas has agreed to a compact with the state of Vermont for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by President Clinton in 1998. In 2003, the State of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal. NRG intends to continue to ship low-level waste material from STP offsite for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will then be stored on-site. STP’s on-site storage capacity is expected to be adequate for STP’s needs until other off-site facilities become available.
 
Regional U.S. Environmental Initiatives
 
Northeast Region
 
NRG’s facilities in the eastern US are subject to a cap-and-trade program governing NOx emissions during the ozone season, typically from May 1 through September 30. These rules essentially require that one NOx allowance be held for each ton of NOx emitted. Each of NRG’s facilities that are subject to these rules has been allocated NOx emission allowances. NRG currently estimates that the portfolio total is currently sufficient to generally cover operations at these facilities through 2009, reflecting the fact that NOx allowances are allocated on a three-year, look-back basis. However, if at any point emission allowances are insufficient for the anticipated operation of each of these facilities, NRG must purchase NOx allowances. Any obligation to purchase a substantial number of additional NOx allowances could have a material adverse effect on NRG’s operations.
 
The Ozone Transport Commission, or OTC, was established by Congress and governs ozone and the NOx budget program in certain eastern states, including Massachusetts, Connecticut, New York and Delaware. The OTC proposes to implement a regional plan containing emission reduction targets for power plants that exceed those under CAIR. The OTC targets and timelines have slipped although additional SO2 and NOx reductions are still in


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discussion. Current attention is focused on NOx emissions from units run primarily on High Energy Demand Days, or HEDD, of which NRG owns facilities in Connecticut, Delaware and New York. NRG continues to be actively engaged in the OTC stakeholder process including providing technical expertise to improve policy decision making. While it is not possible to predict the outcome of this regional effort, to the extent that the OTC is successful in implementing emission requirements that are more stringent than existing regimes, NRG could be materially impacted.
 
On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding, or MOU, to create a Regional Greenhouse Gas initiative to establish a cap-and-trade greenhouse gas program for electric generators, referred to as RGGI. Maryland and Massachusetts have since announced their intent to join. In August 2006, the states participating in RGGI released a model rule which addresses program elements including timelines, monitoring, the use of offsets, and allowance trading. The program begins in 2009. Individual states in which NRG operates including Connecticut, Delaware, Massachusetts and New York must promulgate state rules, which can be based on the model rule, and in addition, address allowance allocations/auctions, treatment of unallocated allowances and leakage. New York issued a pre-proposal version in December 2006 which, among other things, proposes to increase MOU suggested set aside of allowances from 25% to 100% and that these allowances be auctioned. New York is accepting comments on the pre-proposal and expects to have a final rule later in 2007. Connecticut, Delaware and Massachusetts plan to develop rules in 2007. NRG has proposed clean coal IGCC projects that are carbon capture ready to meet future generation demands in both New York and Delaware and also, potentially, Connecticut. NRG continues to actively participate in state and regional RGGI proceedings.
 
New England — Massachusetts air regulations prescribe schedules under which six existing coal-fired power plants in-state are required to meet stringent emission limits for NOx, SO2, mercury, and CO2. NRG’s Somerset plant is subject to these regulations. NRG has installed natural gas reburn technology to meet the NOx and SO2 limits. On June 4, 2004, the Massachusetts Department of Environmental Protection, or MADEP, issued its regulation on the control of mercury emissions. The effect of this regulation is that starting October 1, 2006, Somerset will be capped at 13.1 lbs/year of mercury as of January 1, 2008 and must achieve a reduction in its mercury inlet-to-outlet concentration of 85%. NRG plans to meet the requirements through the management of our fuels and the use of early and off-site reduction credits. Additionally, NRG has entered into an agreement with MADEP to retire or repower the Somerset station by the end of 2009. A permit for repowering the facility was submitted to the MADEP in December 2006.
 
The Massachusetts carbon regulation 310 CMR 7.29 Emissions Standards for Power Plants requires coal-fired generation located within the state to comply with CO2 emissions restrictions. A carbon emissions cap applies from January 1, 2006, while a rate requirement will apply in 2008. It is expected that Somerset will meet the cap from 2006 through 2007 and purchase offsets after that period. Massachusetts announced in January 2006 that they will join the other Northeast states in RGGI.
 
New York — Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC entered into a Consent Order with the New York State Department of Environmental Conservation, or NYSDEC, effective March 31, 2004, regarding certain alleged opacity exceedances. The Order stipulates penalties for future violations of opacity requirements and a compliance schedule. In 2006, NRG accrued amounts payable to NYSDEC of $0.2 million to cover the stipulated penalty payments.
 
Delaware — In November 2006, the Delaware Department of Natural Resources and Environmental Control, or DNREC, promulgated Regulation No. 1146, or Reg 1146, Electric Generating Unit Multi-Pollutant Regulation and Section 111(d) of the State Plan for the Control of Mercury Emissions from Coal-Fired Electric Steam Generating Units. These regulations govern the control of SO2, NOx and mercury emissions from electric generating units. NRG’s current plan to install controls at the Company’s Indian River facility, while on an accelerated basis, is unable to meet certain deadlines for SO2 and NOx controls in Phase 1, taking into account the time required, as a practical matter, to design, install and commission the necessary equipment. NRG and the owners of all other subject facilities in the state filed a challenge to Reg 1146 with the Environmental Appeals Board on December 6, 2006. In addition, NRG also filed a protective appeal with the Delaware Superior Court on December 29, 2006. NRG is unable to predict the outcome of the proceedings at this time, but failure to obtain relief may result in a material impact to the Company’s Indian River facility.


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On January 5, 2005, DNREC initiated a rule making to incorporate USEPA’s NSR reforms within Delaware’s Regulation 25. Delaware was required to revise the state’s current rules and demonstrate such revisions are equivalent to, or more stringent than, the USEPA’s revised rules by January 2006, which Delaware did not meet. The state is considering a facility emissions limit that would cap all NSR applicable pollutants. The results of the rule making, expected in 2007, will impact Indian River and Dover facilities.
 
West Region
 
NRG’s El Segundo Generating Station is regulated by the South Coast Air Quality Management District, or SCAQMD. Before the station’s retirement as of January 1, 2005, the Long Beach Generating Station was also regulated by SCAQMD. SCAQMD approved amendments to its Regional Clean Air Incentives Market, or RECLAIM, NOx regulations on January 7, 2005. RECLAIM is a regional emission-trading program targeting NOx reductions to achieve state and federal ambient air quality standards for ozone. Among other changes, the amendments reduce the NOx RECLAIM Trading Credit, or RTC, holdings of El Segundo Power, LLC and Long Beach Generation LLC facilities by certain amounts. Notwithstanding these amendments, retained RTCs are expected to be sufficient to operate El Segundo Units 3 and 4 as high as 100% capacity factor for the life of those units.
 
On September 27, 2006, Governor Arnold Schwarzenegger signed Assembly Bill 32 — California Global Warming Solutions Act of 2006 and Senate Bill 1368 — Electricity: Emissions of Greenhouse Gases. Assembly Bill 32, or AB 32, requires the California Air Resources Board, or CARB, to develop a greenhouse gas reduction program to reduce emissions to 1990 levels by 2020, a reduction of approximately 25%. The reductions will be phased in beginning 2012 pursuant to regulations to be adopted by 2011. The financial impact to NRG will depend on final regulations. In addition, the governor also signed Senate Bill 1368, or SB 1368, which prohibits utilities from entering into contracts of five years or more for any baseload generation exceeding a 60% capacity factor unless the contracting facility complies with a greenhouse gas performance standard no higher than the rate of GHG emissions for a combined cycle natural gas baseload power plant. NRG’s plants and development projects in California are unaffected by SB 1368 because they either meet the combined cycle standard or they do not exceed the 60% capacity factor and/or five year contract term thresholds.
 
Nuclear Insurance
 
STPNOC purchases insurance coverage on behalf of NRG and the other owners of STP. STP maintains property, decontamination liability and nuclear hazard liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. Currently, STP has a $2.75 billion limit in property and decontamination liability insurance coverage, which is above the legally required minimum of $1.06 billion. The $2.75 billion includes $1 billion excess blanket coverage that is shared with two other nuclear power plants, namely Diablo Canyon and DC Cook. The deductible for property damage is $2.5 million. STP also carries a primary accidental outage policy, which allows for six weeks of indemnity at $3.5 million per week after a 17 week deductible is met. The $3.5 million weekly indemnity would be allocated between the three owners of STP according to their ownership percentages. NRG has purchased additional accidental outage coverage for its 44% ownership stake in STP. This policy provides coverage after the six week indemnity period has been paid under the primary policy, and will provide NRG $1.98 million weekly indemnity per unit for 52 weeks and $1.58 million per week for the next 71 weeks. If both units at STP are affected by an outage arising out of the same accident, weekly indemnity per unit is limited to 80% of the single unit recovery. There is no coverage for partial outages, and the outage must be the result of a property damage caused by a sudden and fortuitous event.
 
The Price-Anderson Act, as amended through 2025 by the Energy Policy Act of 2005, requires owners of nuclear power plants in the U.S. to purchase the maximum amount of insurance available (currently $300 million) in the insurance market for liability claims that arise in the event of a nuclear accident. In addition, the Act provides a secondary layer of protection of up to $10.5 billion. Under this provision, each licensed reactor company is obliged to contribute up to approximately $101 million per unit per accident in retrospective premiums for any single incident at any nuclear power plant. Annual installments per reactor cannot exceed $15 million. STP is a two reactor facility but NRG’s liability would be capped at 44% due to the Company’s ownership interest in STP. The Price-Anderson Act only covers nuclear liability associated with an accident in the course of operation of the nuclear


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reactor, transportation of nuclear fuel to the reactor site, storage of nuclear fuel and waste at the reactor site and the transportation of the spent nuclear fuel and nuclear waste from the nuclear reactor. Any substantial retrospective premiums imposed under the Price-Anderson Act or losses not covered by insurance could have a materially adverse effect on NRG’s financial condition, the results of operations and statement of cash flows.
 
Domestic Site Remediation Matters
 
Under certain federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products at the facility. NRG may also be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, or SARA, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills or other occurrences during its operations.
 
In January 2006, NRG Indian River Operations, Inc. received a letter of informal notification from DNREC stating that it may be a potentially responsible party with respect to a historic captive landfill. NRG is working with the DNREC, through the Voluntary Clean-up Program to investigate the site. The Company is unable to predict the exact impact at this time.
 
Further details regarding our Domestic Site Remediation obligations can be found at Item 15 — Note 22, Regulatory Matters, to the Consolidated Financial Statements.
 
International Environmental Matters
 
Most of the foreign countries in which NRG owns or may acquire or develop independent power projects have environmental and safety laws or regulations relating to the ownership or operation of electric power generation facilities. These laws and regulations, like those in the U.S., are constantly evolving and have a significant impact on international wholesale power producers. In particular, NRG’s international power generation facilities will likely be affected by emissions limitations and operational requirements imposed by the Kyoto Protocol, which is an international treaty related to greenhouse gas emissions enacted on February 16, 2005, and country-based restrictions pertaining to global climate change concerns.
 
NRG retains appropriate advisors in foreign countries and seeks to design its international asset management strategy to comply with each country’s environmental and safety laws and regulations. There can be no assurance that changes in such laws or regulations will not adversely effect the Company’s international operations.
 
MIBRAG/Schkopau, Germany — CO2 emissions trading began in Germany in 2005, pursuant to European Union obligations under the Kyoto Protocol. Trading rules and emissions allocations for the second emissions trading period (2008 through 2012) have not yet been established by the regulators, therefore the impact of the new rules on NRG’s German business cannot be predicted at this time. Changes to the German Emission Control Directive have specified lower NOx emission limits for plants firing conventional fuels and co-firing waste products. The new regulations required the Mumsdorf and Deuben Power stations to install additional controls to reduce NOx emissions in 2006. These plant modifications have been successfully completed. The regulations of the revised European Union’s Groundwater Directive and Mine Wastewater Management Directive are now in effect and MIBRAG sees no negative effects on its mining operations or economics.
 
Available Information
 
NRG’s annual reports on Form 10-K, quarterly reports on Form10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge through the Company’s website, www.nrgenergy.com, as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission.


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Item 1A — Risk Factors Related to NRG Energy, Inc.
 
Many of NRG’s power generation facilities operate, wholly or partially, without long-term power sale agreements.
 
Many of NRG’s facilities operate as “merchant” facilities without long-term power sales agreements for some or all of their generating capacity and output, and therefore are exposed to market fluctuations. Without the benefit of long-term power sales agreements for these assets, NRG cannot be sure that we will be able to sell any or all of the power generated by these facilities at commercially attractive rates or that these facilities will be able to operate profitably. This could lead to future impairments of the Company’s property, plant and equipment or to the closing of certain of its facilities, resulting in economic losses and liabilities, which could have a material adverse effect on the Company’s results of operations, financial condition or cash flows.
 
NRG’s financial performance may be impacted by changing natural gas prices, significant and unpredictable price fluctuations in the wholesale power markets and other market factors that are beyond the Company’s control.
 
A significant percentage of the company’s domestic revenues are derived from baseload power plants that are fueled by coal. In many of the competitive markets where NRG operates, the price of power typically is set by marginal cost natural gas-fired power plants that currently have substantially higher variable costs than NRG’s coal-fired baseload power plants. The current pricing and cost environment allows the Company’s baseload coal generation assets to earn attractive operating margins compared to plants fueled by natural gas. A decrease in natural gas prices could result in a corresponding decrease in the market price of power but would generally not affect the cost of the coal that the plants use. This could significantly reduce the operating margins of the Company’s baseload generation assets and materially and adversely impact its financial performance.
 
In addition, because changes in power prices in the markets where NRG operates are generally correlated with changes in natural gas prices, NRG’s hedging portfolio includes natural gas derivative instruments to hedge power prices for its baseload generation. If this correlation between power prices and natural gas prices is not maintained and a change in gas prices is not proportionately offset by a change in power prices, the Company’s natural gas hedges may not fully cover this differential. This could have a materially adverse impact on the Company’s cash flow and financial position.
 
Market prices for power, generation capacity and ancillary services tend to fluctuate substantially. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility from supply and demand imbalances, especially in the day-ahead and spot markets. Long- and short-term power prices may also fluctuate substantially due to other factors outside of the Company’s control, including:
 
  •  increases and decreases in generation capacity in the Company’s markets, including the addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity;
 
  •  changes in power transmission or fuel transportation capacity constraints or inefficiencies;
 
  •  electric supply disruptions, including plant outages and transmission disruptions;
 
  •  heat rate risk;
 
  •  weather conditions;
 
  •  changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;
 
  •  development of new fuels and new technologies for the production of power;
 
  •  regulations and actions of the ISOs; and
 
  •  federal and state power market and environmental regulation and legislation.


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These factors have caused the Company’s operating results to fluctuate in the past and will continue to cause them to do so in the future.
 
NRG’s costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of its fuel supplies.
 
NRG relies on coal, oil and natural gas to fuel a majority of its power generation facilities. Delivery of these fuels to the facilities is dependent upon the continuing financial viability of contractual counterparties as well as upon the infrastructure (including rail lines, rail cars, barge facilities, roadways, and natural gas pipelines) available to serve each generation facility. As a result, the Company is subject to the risks of disruptions or curtailments in the production of power at its generation facilities if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
 
NRG has sold forward a substantial portion of its baseload power in order to lock in long-term prices that it deemed to be favorable at the time it entered into the forward sale contracts. In order to hedge its obligations under these forward power sales contracts, the Company has entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow the Company to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in the Company’s fuel supplies may therefore require it to find alternative fuel sources at higher costs, to find other sources of power to deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Any such event could have a material adverse effect on the Company’s financial performance.
 
NRG also buys significant quantities of fuel on a short-term or spot market basis. Prices for all of the Company’s fuels fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price NRG can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. This may have a material adverse effect on the Company’s financial performance. Changes in market prices for natural gas, coal and oil may result from the following:
 
  •  weather conditions;
 
  •  seasonality;
 
  •  demand for energy commodities and general economic conditions;
 
  •  disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
 
  •  additional generating capacity;
 
  •  availability and levels of storage and inventory for fuel stocks;
 
  •  natural gas, crude oil, refined products and coal production levels;
 
  •  changes in market liquidity;
 
  •  federal, state and foreign governmental regulation and legislation; and
 
  •  the creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with the Company.
 
NRG’s plant operating characteristics and equipment, particularly at its coal-fired plants, often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, coal of specific quality may not be available at any price, or the Company may not be able to transport such coal to its facilities on a timely basis. In this case, the Company may not be able to run the coal facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or operating problems. If the Company had sold forward the power from such a coal facility, it could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on the Company’s results of operations.


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There may be periods when NRG will not be able to meet its commitments under forward sale obligations at a reasonable cost or at all.
 
A substantial portion of the output from NRG’s baseload facilities has been sold forward under fixed price power sales contracts through 2012, and the Company also sells forward the output from its intermediate and peaking facilities when its deems it commercially advantageous to do so. Because the obligations under most of these agreements are not contingent on a unit being available to generate power, NRG is generally required to deliver power to the buyer, even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that the Company does not have sufficient lower cost capacity to meet its commitments under its forward sale obligations, the Company would be required to supply replacement power either by running its other, higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price. If NRG fails to deliver the contracted power, it would be required to pay the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial.
 
In NRG’s South Central region, NRG has long-term contracts with rural cooperatives that require it to serve all of the cooperatives’ requirements at prices that generally reflect the costs of coal-fired generation. At times, the output from NRG’s coal-fired Big Cajun II facility has been and will continue to be inadequate to serve these obligations, and when that happens the Company has typically purchased power from other power producers, often at a loss. NRG’s financial returns from its South Central region are likely to deteriorate over time as the rural cooperatives grow their customer base, unless the Company is able to amend or renegotiate its contracts with the cooperatives or add generating capacity.
 
NRG’s trading operations and the use of hedging agreements could result in financial losses that negatively impact its results of operations.
 
The Company typically enters into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, in order to manage the commodity price risks inherent in its power generation operations. These activities, although intended to mitigate price volatility, expose the Company to other risks. When the Company sells power forward, it gives up the opportunity to sell power at higher prices in the future, which not only may result in lost opportunity costs but also may require the Company to post significant amounts of cash collateral or other credit support to its counterparties. Further, if the values of the financial contracts change in a manner that the Company does not anticipate, or if a counterparty fails to perform under a contract, it could harm the Company’s business, operating results or financial position.
 
NRG does not typically hedge the entire exposure of its operations against commodity price volatility. To the extent it does not hedge against commodity price volatility, the Company’s results of operations and financial position may be improved or diminished based upon movement in commodity prices.
 
NRG may engage in trading activities, including the trading of power, fuel and emissions allowances that are not directly related to the operation of the Company’s generation facilities or the management of related risks. These trading activities take place in volatile markets and some of these trades could be characterized as speculative. The Company would expect to settle these trades financially rather than through the production of power or the delivery of fuel. This trading activity may expose the Company to the risk of significant financial losses which could have a material adverse effect on its business and financial condition.
 
NRG may not have sufficient liquidity to hedge market risks effectively.
 
The Company is exposed to market risks through its power marketing business, which involves the sale of energy, capacity and related products and the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into energy and delivering the energy to a buyer.
 
NRG undertakes these marketing activities through agreements with various counterparties. Many of the Company’s agreements with counterparties include provisions that require the Company to provide guarantees,


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offset of netting arrangements, letters of credit, a second lien on assets and/or cash collateral to protect the counterparties against the risk of the Company’s default or insolvency. The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in the Company being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of the Company’s strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than the Company anticipates or will be able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as a cash margin, the Company may not be able to manage price volatility effectively or to implement its strategy. An increase in the amount of letters of credit or cash collateral required to be provided to the Company’s counterparties may negatively affect the Company’s liquidity and financial condition.
 
Further, if any of NRG’s facilities experience unplanned outages, the Company may be required to procure replacement power at spot market prices in order to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, the Company may be exposed to significant losses, may miss significant opportunities, and may have increased exposure to the volatility of spot markets.
 
The accounting for NRG’s hedging activities may increase the volatility in the Company’s quarterly and annual financial results.
 
NRG engages in commodity-related marketing and price-risk management activities in order to financially hedge its exposure to market risk with respect to electricity sales from its generation assets, fuel utilized by those assets, and emission allowances.
 
NRG generally attempts to balance its fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for in accordance with SFAS 133, as amended, which requires the Company to record all derivatives on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for cash flow hedge accounting treatment. Whether a derivative qualifies for cash flow hedge accounting treatment depends upon it meeting specific criteria used to determine if the cash flow hedge is and will remain appropriate for the term of the derivative. Economic hedges will not necessarily qualify for cash flow hedge accounting treatment. As a result, the Company may be unable to accurately predict the impact that its risk management decisions may have on its quarterly and annual operating results.
 
Competition in wholesale power markets may have a material adverse effect on NRG’s results of operations, cash flows and the market value of its assets.
 
NRG has numerous competitors in all aspects of its business, and additional competitors may enter the industry. Because many of the Company’s facilities are old, newer plants owned by the Company’s competitors are often more efficient than NRG’s aging plants, which may put some of these plants at a competitive disadvantage to the extent the Company’s competitors are able to consume the same or less fuel as the Company’s plants consume. Over time, the Company’s plants may be squeezed out of their markets, or may be unable to compete with these more efficient plants.
 
In NRG’s power marketing and commercial operations, it competes on the basis of its relative skills, financial position and access to capital with other providers of electric energy in the procurement of fuel and transportation services, and the sale of capacity, energy and related products. In order to compete successfully, the Company seeks to aggregate fuel supplies at competitive prices from different sources and locations and to efficiently utilize transportation services from third-party pipelines, railways and other fuel transporters and transmission services from electric utilities.
 
Other companies with which NRG competes with may have greater liquidity, greater access to credit and other financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than NRG does.


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NRG’s competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote greater resources to the construction, expansion or refurbishment of their power generation facilities than NRG can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties. Accordingly, it is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share. There can be no assurance that NRG will be able to compete successfully against current and future competitors, and any failure to do so would have a material adverse effect on the Company’s business, financial condition, results of operations and cash flow.
 
Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on NRG’s revenues and results of operations. NRG may not have adequate insurance to cover these risks and hazards.
 
The ongoing operation of NRG’s facilities involves risks that include the breakdown or failure of equipment or processes, performance below expected levels of output or efficiency and the inability to transport the Company’s product to its customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Company’s business. Unplanned outages typically increase the Company’s operation and maintenance expenses and may reduce the Company’s revenues as a result of selling fewer MWh or require NRG to incur significant costs as a result of running one of its higher cost units or obtaining replacement power from third parties in the open market to satisfy the Company’s forward power sales obligations. NRG’s inability to operate the Company’s plants efficiently, manage capital expenditures and costs, and generate earnings and cash flow from the Company’s asset-based businesses could have a material adverse effect on the Company’s results of operations, financial condition or cash flows. While NRG maintains insurance, obtains warranties from vendors and obligates contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover the Company’s lost revenues, increased expenses or liquidated damages payments should the Company experience equipment breakdown or non-performance by contractors or vendors.
 
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as fire, explosion, structural collapse and machinery failure are inherent risks in the Company’s operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in NRG being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. NRG maintains an amount of insurance protection that it considers adequate, but the Company cannot provide any assurance that its insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A successful claim for which the Company is not fully insured could hurt its financial results and materially harm NRG’s financial condition. Further, due to rising insurance costs and changes in the insurance markets, NRG cannot provide any assurance that its insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on the Company’s financial condition, results of operations or cash flows.
 
Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on NRG’s results of operations, cash flow and financial condition.
 
Many of NRG’s facilities are old and require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability.
 
NRG cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility


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repairs and unexpected events (such as natural disasters or terrorist attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on the Company’s liquidity and financial condition.
 
If NRG makes any major modifications to its power generation facilities, the Company may be required to install the best available control technology or to achieve the lowest achievable emissions rates, as such terms are defined under the new source review provisions of the federal Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures.
 
The Company’s Repowering NRG program is subject to financing, construction, and operational risks that could adversely impact NRG’s financial performance
 
While NRG currently intends to develop and finance the more capital intensive, solid fuel-fired projects included in the Repowering NRG program on a non-recourse or limited recourse basis through separate project financed entities, and intends to seek additional investments in most of these projects from third parties, NRG anticipates that it will need to make significant equity investments in these projects. NRG may also decide to develop and finance some of the projects, such as smaller gas-fired and renewable projects, using corporate financial resources rather than non-recourse debt, which could subject NRG to significant capital expenditure requirements and to risks inherent in the development and construction of new generation facilities. In addition to providing some or all of the equity required to develop and build the proposed projects, NRG’s ability to finance these projects on a non-recourse basis is contingent upon a number of factors, including the terms of the engineering, procurement and construction contracts, construction costs, power purchase agreements and fuel procurement contracts, capital markets conditions, the availability of tax credits and other government incentives for certain new technologies. To the extent NRG is not able to obtain non-recourse financing for any projects or should the credit rating agencies attribute a material amount of the project finance debt to NRG’s credit, the financing of the Repowering NRG projects could have a negative impact on the credit ratings of NRG. In addition, there are risks inherent in the development and construction of new generation facilities. Further, certain of the Repowerng NRG projects incorporate advanced equipment and technologies with only a modest amount of operating history in the proposed configurations. There also exists the possibility of cost overruns, schedule delays and performance risks during the construction phase, as well as the possibility of operational and contractual issues during the commercial operational life of these new generation facilities that could adversely impact NRG’s financial performance.
 
As part of the Repowering NRG program, NRG may also choose to undertake the repowering, refurbishment or upgrade of current facilities based on the Company’s assessment that such activity will provide adequate financial returns. Such projects often require several years of development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. The construction, expansion, modification and refurbishment of power generation facilities involve many additional risks, including:
 
  •  delays in obtaining necessary permits and licenses;
 
  •  environmental remediation of soil or groundwater at contaminated sites;
 
  •  interruptions to dispatch at the Company’s facilities;
 
  •  supply interruptions;
 
  •  work stoppages;
 
  •  labor disputes;
 
  •  weather interferences;
 
  •  unforeseen engineering, environmental and geological problems;
 
  •  unanticipated cost overruns; and
 
  •  performance risks.


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Any of these risks could cause NRG’s financial returns on new investments to be lower than expected, or could cause the Company to operate below expected capacity or availability levels, which could result in lost revenues, increased expenses, higher maintenance costs and penalties.
 
Supplier and/or customer concentration at certain of NRG’s facilities may expose the Company to significant financial credit or performance risks.
 
NRG often relies on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of certain of its facilities. If these suppliers cannot perform, the Company utilizes the marketplace to provide these services. There can be no assurance that the marketplace can provide these services as, when and where required.
 
At times, NRG relies on a single customer or a few customers to purchase all or a significant portion of a facility’s output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility. The Company has also hedged a portion of its exposure to power price fluctuations through forward fixed price power sales and natural gas price swap agreements. Counterparties to these agreements may breach or may be unable to perform their obligations. NRG may not be able to enter into replacement agreements on terms as favorable as its existing agreements, or at all. If the Company was unable to enter into replacement PPA’s, the Company would sell its plants’ power at market prices. If the Company is unable to enter into replacement fuel or fuel transportation purchase agreements, NRG would seek to purchase the Company’s fuel requirements at market prices, exposing the Company to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price.
 
The failure of any supplier or customer to fulfill its contractual obligations to NRG could have a material adverse effect on the Company’s financial results. Consequently, the financial performance of the Company’s facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.
 
NRG relies on power transmission facilities that the Company does not own or control and that are subject to transmission constraints within a number of the Company’s core regions. If these facilities fail to provide NRG with adequate transmission capacity, the Company may be restricted in its ability to deliver wholesale electric power to its customers and the Company may either incur additional costs or forego revenues. Conversely, improvements to certain transmission systems could also reduce revenues.
 
NRG depends on transmission facilities owned and operated by others to deliver the wholesale power it sells from the Company’s power generation plants to its customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, NRG’s ability to sell and deliver wholesale power may be adversely impacted. If a region’s power transmission infrastructure is inadequate, the Company’s recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure. The Company cannot also predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.
 
In addition, in certain of the markets in which NRG operates, energy transmission congestion may occur and the Company may be deemed responsible for congestion costs if it schedules delivery of power between congestion zones during times when congestion occurs between the zones. If NRG were liable for such congestion costs, the Company’s financial results could be adversely affected.
 
In the California ISO, New York ISO and New England ISO markets, the Company has a significant amount of generation located in load pockets, making that generation valuable, particularly with respect to maintaining the reliability of the transmission grid. Expansion of transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of our existing facilities in these areas.
 
Because NRG owns less than a majority of some of its project investments, the Company cannot exercise complete control over their operations.
 
NRG has limited control over the operation of some project investments and joint ventures because the Company’s investments are in projects where it beneficially owns less than a majority of the ownership interests.


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NRG seeks to exert a degree of influence with respect to the management and operation of projects in which it owns less than a majority of the ownership interests by negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, the Company may not always succeed in such negotiations. NRG may be dependent on its co-venturers to operate such projects. The Company’s co-venturers may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these projects optimally. The approval of co-venturers also may be required for NRG to receive distributions of funds from projects or to transfer the Company’s interest in projects.
 
Future acquisition activities may have adverse effects.
 
NRG may seek to acquire additional companies or assets in the Company’s industry. The acquisition of power generation companies and assets is subject to substantial risks, including the failure to identify material problems during due diligence, the risk of over-paying for assets and the inability to arrange financing for an acquisition as may be required or desired. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, the Company’s acquisitions may not be successfully integrated. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them.
 
NRG’s business is subject to substantial governmental regulation and may be adversely affected by legislative or regulatory changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
 
NRG’s business is subject to extensive foreign, and U.S. federal, state and local laws and regulation. Compliance with the requirements under these various regulatory regimes may cause the Company to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
 
Public utilities under the Federal Power Act, or FPA, are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. All of NRG’s non-qualifying facility generating companies and power marketing affiliates in the United States make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. FERC has granted each of NRG’s generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant NRG’s generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, NRG’s market-based sales are subject to certain market behavior rules, and if any of NRG’s generating and power marketing companies were deemed to have violated one of those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG’s generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates NRG charges for power from its facilities.
 
NRG is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules that occur in the existing ISOs. The ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps, and other mechanisms to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of NRG’s generation facilities that sell energy and capacity into the wholesale power markets.
 
The regulatory environment applicable to the electric power industry has undergone substantial changes over the past several years as a result of restructuring initiatives at both the state and federal levels. These changes are ongoing and the Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on NRG’s business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price


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mechanism, as well as proposals to re-regulate the markets or require divestiture by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, our business prospects and financial results could be negatively impacted.
 
NRG’s ownership interest in a nuclear power facility subjects the Company to regulations, costs and liabilities uniquely associated with these types of facilities.
 
Under the Atomic Energy Act of 1954, as amended, or AEA, operation of STP, of which NRG indirectly own a 44.0% interest, is subject to regulation by the Nuclear Regulatory Commission, or NRC. Such regulation includes licensing, inspection, enforcement, testing, evaluation and modification of all aspects of nuclear reactor power plant design and operation, environmental and safety performance, technical and financial qualifications, decommissioning funding assurance and transfer and foreign ownership restrictions. NRG’s 44% share of the output of STP represents approximately 1,100 MW of generation capacity.
 
There are unique risks to owning and operating a nuclear power facility. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, particularly with respect to spent nuclear fuel, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning a nuclear facility. The NRC could require the shutdown of the plant for safety reasons or refuse to permit restart of the unit after unplanned or planned outages. New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. STP may be obligated to continue storing spent nuclear fuel if the Department of Energy continues to fail to meet its contractual obligations to STP made pursuant to the U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of STP’s spent nuclear fuel. See also “Environmental Matters — U.S. Federal Environmental Initiatives — Nuclear Waste” in Item 1. Costs associated with these risks could be substantial and have a material adverse effect on NRG’s results of operations, financial condition or cash flow. In addition, to the extent that all or a part of STP is required by the NRC to permanently or temporarily shut down or modify its operations, or is otherwise subject to a forced outage, NRG may incur additional costs to the extent it is obligated to provide power from more expensive alternative sources — either NRG’s own plants, third party generators or the ERCOT — to cover the Company’s then existing forward sale obligations. Such shutdown or modification could also lead to substantial costs related to the storage and disposal of radioactive materials and spent nuclear fuel.
 
NRG and the other owners of STP maintain nuclear property and nuclear liability insurance coverage as required by law. The Price-Anderson Act, as amended by the Energy Policy Act of 2005, requires owners of nuclear power plants in the United States to be collectively responsible for retrospective secondary insurance premiums for liability to the public arising from nuclear incidents resulting in claims in excess of the required primary insurance coverage amount of $300 million per reactor. The Price-Anderson Act only covers nuclear liability associated with any accident in the course of operation of the nuclear reactor, transportation of nuclear fuel to the reactor site, in the storage of nuclear fuel and waste at the reactor site and the transportation of the spent nuclear fuel and nuclear waste from the nuclear reactor. All other non-nuclear liabilities are not covered. Any substantial retrospective premiums imposed under the Price-Anderson Act or losses not covered by insurance could have a material adverse effect on NRG’s financial condition, results of operations or cash flows.
 
NRG is subject to environmental laws and regulations that impose extensive and increasingly stringent requirements on the Company’s ongoing operations, as well as potentially substantial liabilities arising out of environmental contamination. These environmental requirements and liabilities could adversely impact NRG’s results of operations, financial condition and cash flows.
 
NRG’s business is subject to the environmental laws and regulations of foreign, federal, state and local authorities. The Company must comply with numerous environmental laws and regulations and obtain numerous governmental permits and approvals to operate our plants. If NRG fails to comply with any environmental requirements that apply to its operations, the Company could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions seeking to curtail the Company’s operations. In addition, when new requirements take effect or when existing environmental requirements are revised, reinterpreted


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or subject to changing enforcement policies, NRG’s business, results of operations, financial condition and cash flows could be adversely affected.
 
Environmental laws and regulations have generally become more stringent over time, and the Company expects this trend to continue. In particular, several states in which NRG operates have proposed or are in the process of proposing requirements to control emissions of NOx, SO2, and mercury from electric generating units that are more stringent than federal regulations. In Delaware, NRG and others have appealed portions of such a regulation for the control of multiple pollutants to both the Environmental Appeals Board and Delaware Superior Court, based not on the required level of emissions reductions, but on the timing for achievement of those reductions by 2009. We are unable to predict the outcome of these appeals.
 
There is a growing consensus in the U.S. and globally that greenhouse gases, or GHG, emissions are linked to global climate change. States in the Northeast under RGGI and California under AB32 are expected to propose rules to stabilize and reduce GHG in the near future. Increased public concern and mounting political pressure may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG. NRG’s U.S. generating portfolio includes coal-, oil- and gas-fired plants that are projected to emit approximately 70 million tons of CO2, a GHG, for 2007. The Company’s facilities in New York and California will be subject to regulation under RGGI and AB32, respectively. It is likely that the Company’s U.S. plants would also be subject to regulation under any new GHG legislation introduced at the state, regional or national level. While NRG plans to address the risks of such GHG regulations through CO2 offsets, by supporting CO2 mitigation research, and by pursuing CO2 sequestration capable facilities, technologies such as nuclear and wind that do not emit GHG, and highly efficient fossil fuel projects, the costs of complying with potential GHG regulations may be substantial and may have a significant impact on NRG’s operations, cash flow and financial position. The actual impact of any state, regional or federal GHG regulations on NRG will depend on a number of factors including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the degree to which the forward market prices on the cost of GHG regulation, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas prices.
 
A recent court ruling on the appeal of the USEPA Phase II 316(b) regulation has created uncertainty for power plants that use once-through cooling water. Specifically, the ruling remanded certain provisions back to the USEPA for reconsideration and prohibits certain mitigation technologies, including restoration. In light of this ruling, NRG anticipates that it will not be able to rely on restoration and cost-benefit adjustment at some of its facilities in the West region. In addition, the ruling has created some uncertainty with respect to approximately 17% of the Company’s other generating units that do not have cooling towers. NRG continues to complete and analyze fish studies and design solutions which will meet the Phase II 316(b) regulation when finalized for all of its facilities that use once-through cooling. NRG is closely following progress on the final rule, although it is not possible to quantify the impact of the revisions at this time.
 
Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. The Company is generally responsible for all liabilities associated with the environmental condition of the Company’s power generation plants, including any soil or groundwater contamination that may be present, regardless of when the liabilities arose and whether the liabilities are known or unknown, or arose from the activities of predecessors or third parties.
 
NRG’s business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by its unionized employees.
 
As of December 31, 2006, approximately 55% of NRG’s employees at its U.S. generation plants would have been covered by collective bargaining agreements. In the event that the Company’s union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, NRG would be responsible for procuring replacement labor or the Company could experience reduced power generation or outages. NRG’s ability to procure such labor is uncertain. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flow.


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Changes in technology may impair the value of NRG’s power plants.
 
Research and development activities are ongoing to provide alternative and more efficient technologies to produce power, including fuel cells, clean coal and coal gasification, micro-turbines, photovoltaic (solar) cells and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these or other technologies could reduce the costs of power production to a level below what the Company has currently forecasted, which could adversely affect its cash flow, results of operations or competitive position.
 
Acts of terrorism could have a material adverse effect on NRG’s financial condition, results of operations and cash flows.
 
NRG’s generation facilities and the facilities of third parties on which they rely may be targets of terrorist activities, as well as events occurring in response to or in connection with them, that could cause environmental repercussions and/or result in full or partial disruption of the facilities ability to generate, transmit, transport or distribute electricity or natural gas. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Any such environmental repercussions or disruption could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on the Company’s financial condition, results of operations and cash flow.
 
NRG’s international investments are subject to additional risks that its U.S. investments do not have.
 
NRG has investments in power projects in Australia, Germany and Brazil. International investments are subject to risks and uncertainties relating to the political, social and economic structures of the countries in which it invests. Risks specifically related to our investments in international projects may include:
 
  •  fluctuations in currency valuation;
 
  •  currency inconvertibility;
 
  •  expropriation and confiscatory taxation;
 
  •  restrictions on the repatriation of capital; and
 
  •  approval requirements and governmental policies limiting returns to foreign investors.
 
NRG’s level of indebtedness could adversely affect its ability to raise additional capital to fund its operations, expose it to the risk of increased interest rates and limit its ability to react to changes in the economy or its industry.
 
NRG’s substantial debt could have important consequences, including:
 
  •  increasing NRG’s vulnerability to general economic and industry conditions;
 
  •  requiring a substantial portion of NRG’s cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing NRG’s ability to pay dividends to holders of its preferred or common stock or to use its cash flow to fund its operations, capital expenditures and future business opportunities;
 
  •  limiting NRG’s ability to enter into long-term power sales or fuel purchases which require credit support;
 
  •  exposing NRG to the risk of increased interest rates because certain of its borrowings, including borrowings under its new senior secured credit facility are at variable rates of interest;
 
  •  limiting NRG’s ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and
 
  •  limiting NRG’s ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to its competitors who have less debt.
 
The indentures for NRG’s notes and senior secured credit facility contain financial and other restrictive covenants that may limit the Company’s ability to engage in activities that may be in its long-term best interests.


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NRG’s failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of the Company’s indebtedness.
 
In addition, NRG’s ability to arrange financing, either at the corporate level or at a non-recourse project-level subsidiary, and the costs of such capital, are dependent on numerous factors, including:
 
  •  general economic and capital market conditions;
 
  •  credit availability from banks and other financial institutions;
 
  •  investor confidence in NRG, its partners and the regional wholesale power markets;
 
  •  NRG’s financial performance and the financial performance of its subsidiaries;
 
  •  NRG’s level of indebtedness and compliance with covenants in debt agreements;
 
  •  maintenance of acceptable credit ratings;
 
  •  cash flow; and
 
  •  provisions of tax and securities laws that may impact raising capital.
 
NRG may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on its business and operations.
 
Because the historical financial information may not be representative of the results of operation as a combined company or capital structure after the Acquisition, and NRG’s and Texas Genco LLC’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate the combined company, NRG and Texas Genco LLC.
 
Texas Genco LLC did not exist prior to July 19, 2004, and Texas Genco LLC and its subsidiaries had no operations and no material activities until December 15, 2004 when Texas Genco LLC acquired its gas- and coal-fired assets. Consequently, Texas Genco LLC’s historical financial information is not comparable to the Texas region’s current financial information.
 
NRG and Texas Genco LLC had been operating as separate companies prior to February 2, 2006. NRG and Texas Genco LLC had no prior history as a combined company, nor have they been previously managed on a combined basis. The historical financial statements may not reflect what the combined company’s results of operations, financial position and cash flows would have been had both companies operated on a combined basis and may not be indicative of what the combined company’s results of operations, financial position and cash flows will be in the future.
 
Goodwill and/or other intangible assets not subject to amortization that NRG has recorded in connection with its acquisitions are subject to mandatory annual impairment evaluations and as a result, the Company could be required to write off some or all of this goodwill and other intangible assets, which may adversely affect the Company’s financial condition and results of operations.
 
In accordance with Financial Accounting Standard No. 142, Goodwill and Other Intangible Assets, goodwill is not amortized but is reviewed annually or more frequently for impairment and other intangibles are also reviewed at least annually or more frequently, if certain conditions exist, and may be amortized. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings which could materially adversely affect NRG’s reported results of operations and financial position in future periods.


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Cautionary Statement Regarding Forward Looking Information
 
This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The words “believes”, “projects”, “anticipates”, “plans”, “expects”, “intends”, “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG Energy, Inc.’s actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risks Related to NRG in Item 1A of NRG’s 2006 Annual Report on Form 10-K and the following:
 
  •  General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;
 
  •  Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;
 
  •  The effectiveness of NRG’s risk management policies and procedures, and the ability of NRG’s counterparties to satisfy their financial commitments;
 
  •  Counterparties’ collateral demands and other factors affecting NRG’s liquidity position and financial condition;
 
  •  NRG’s ability to operate its businesses efficiently, manage capital expenditures and costs tightly (including general and administrative expenses), and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
 
  •  NRG’s potential inability 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;
 
  •  Price mitigation strategies and other market structures employed by independent system operators, or ISO, or regional transmission organizations, or RTOs, that result in a failure to adequately compensate NRG’s generation units for all of its costs;
 
  •  NRG’s ability to borrow additional funds and access capital markets, as well as NRG’s substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;
 
  •  Operating and financial restrictions placed on NRG 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; and
 
  •  NRG’s ability to implement its Repowering NRG strategy of developing and building new power generation facilities, including new nuclear units and IGCC units.
 
Forward-looking statements speak only as of the date they were made, and NRG Energy, Inc. 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 Annual Report on Form 10-K should not be construed as exhaustive.


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Item 1B — Unresolved Staff Comments
 
None.
 
Item 2 — Properties
 
Listed below are descriptions of NRG’s interests in facilities, operations and/or projects owned as of December 31, 2006. The MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company’s ownership position excluding capacity from inactive/mothballed units as of December 31, 2006. The following table summarizes NRG’s Power Production and Cogeneration Facilities by region:
 
                 
            Net
   
    Purchaser/Power
      Generation
   
Name and Location of Facility
  Market   % Owned   Capacity   Primary Fuel-type
 
Texas Region:
               
W. A. Parish, Thompsons, Texas
  ERCOT   100.0   2,480   Coal
Limestone, Jewett, Texas
  ERCOT   100.0   1,700   Lignite/Coal
South Texas Project, Bay City, Texas(a)
  ERCOT   44.0   1,100   Nuclear
Cedar Bayou, Baytown, Texas
  ERCOT   100.0   1,500   Natural Gas
T. H. Wharton, Houston, Texas
  ERCOT   100.0   1,025   Natural Gas
W. A. Parish, Thompsons, Texas
  ERCOT   100.0   1,190   Natural Gas
S. R. Bertron, Deer Park, Texas
  ERCOT   100.0   840   Natural Gas
Greens Bayou, Houston, Texas
  ERCOT   100.0   760   Natural Gas
San Jacinto, LaPorte, Texas
  ERCOT   100.0   165   Natural Gas
Northeast Region:
               
Oswego, New York
  NYISO   100.0   1,635   Oil
Arthur Kill, Staten Island, New York
  NYISO   100.0   865   Natural Gas
Middletown, Connecticut
  ISO-NE   100.0   770   Oil
Indian River, Millsboro, Delaware
  PJM   100.0   780   Coal
Astoria Gas Turbines, Queens, New York
  NYISO   100.0   550   Natural Gas
Dunkirk, New York
  NYISO   100.0   585   Coal
Huntley, Tonawanda, New York
  NYISO   100.0   550   Coal
Montville, Uncasville, Connecticut
  ISO-NE   100.0   500   Oil
Norwalk Harbor, So. Norwalk, Connecticut
  ISO-NE   100.0   340   Oil
Devon, Milford, Connecticut
  ISO-NE   100.0   140   Natural Gas
Vienna, Maryland
  PJM   100.0   170   Oil
Somerset, Massachusetts
  ISO-NE   100.0   125   Coal
Connecticut Jet Power, Connecticut (four sites)
  ISO-NE   100.0   105   Oil
Conemaugh, New Florence, Pennsylvania
  PJM   3.7   65   Coal
Keystone, Shelocta, Pennsylvania
  PJM   3.7   60   Coal


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            Net
   
    Purchaser/Power
      Generation
   
Name and Location of Facility
  Market   % Owned   Capacity   Primary Fuel-type
 
South Central Region:
               
Big Cajun II, New Roads, Louisiana(b)
  SERC-Entergy   86.0   1,490   Coal
Bayou Cove, Jennings, Louisiana
  SERC-Entergy   100.0   300   Natural Gas
Big Cajun I, Jarreau, Louisiana
  SERC-Entergy   100.0   210   Natural Gas
Big Cajun I, Jarreau, Louisiana
  SERC-Entergy   100.0   220   Natural Gas/Oil
Rockford I, Illinois
  PJM   100.0   300   Natural Gas
Rockford II, Illinois
  PJM   100.0   145   Natural Gas
Sterlington, Louisiana
  SERC-Entergy   100.0   185   Natural Gas
West Region:
               
Encina, Carlsbad, California
  Cal ISO   100.0   965   Natural Gas
El Segundo Power, California
  Cal ISO   100.0   670   Natural Gas
San Diego Combustion Turbines, California (three sites)
  Cal ISO   100.0   190   Natural Gas
Chowchilla, California(c)
  Cal ISO   100.0   50   Natural Gas
Red Bluff, California(c)
  Cal ISO   100.0   45   Natural Gas
Saguaro Power Co., Henderson, Nevada
  WECC   50.0   45   Natural Gas
International Region
               
Gladstone Power
  Enertrade/Boyne            
Station, Queensland, Australia
  Smelters   37.5   605   Coal
Schkopau Power Station, Germany
  Vattenfall Europe   41.9   400   Lignite
MIBRAG, Germany(d)
  ENVIA/MIBRAG Mines   50.0   75   Lignite
ITISA, Brazil
  COPEL   99.2   155   Hydro
Corporate
               
Power Smith Cogeneration, Oklahoma City, Oklahoma
  SPP   6.25   7   Natural Gas
 
 
(a) For the nature of NRG’s interest and various limitations on the Company’s interest, please read Item 1 — Business — Texas — Generation Facilities section.
 
(b) Units 1 and 2 owned 100.0%, Unit 3 owned 58.0%
 
(c) Sold January 2, 2007
 
(d) Primarily a coal mining facility

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The following table summarizes NRG’s thermal facilities as of December 31, 2006:
 
             
        %
   
        Ownership
   
Name and Location of Facility
  Thermal Energy Purchaser   Interest   Generating Capacity(a)
 
NRG Energy Center
Minneapolis, MN
  Approx. 100 steam customers and
47 chilled water customers
  100.0   Steam: 1,203 MMBtu/hr.
(353 MWt) Chilled Water:
42,630 tons (150 MWt)
NRG Energy Center
San Francisco, CA
  Approx. 175 steam customers   100.0   Steam: 482 MMBtu/Hr.
(141 MWt)
NRG Energy Center
Harrisburg, PA
  Approx. 250 steam customers and
3 chilled water customers
  100.0   Steam: 440 MMBtu/hr.
(129 MWt) Chilled water:
2,400 tons (8 MWt)
NRG Energy Center
Pittsburgh, PA
  Approx. 25 steam and 25 chilled
water customers
  100.0   Steam: 266 MMBtu/hr.
(78 MWt) Chilled water:
12,920 tons (45 MWt)
NRG Energy Center
San Diego, CA
  Approx. 20 chilled water customers   100.0   Chilled water: 7,425 tons
(26 MWt)
NRG Energy Center
St. Paul, MN
  Rock-Tenn Company   100.0   Steam: 430 MMBtu/hr.
(126 MWt)
Camas Power Boiler,
Camas, WA
  Georgia-Pacific Corp.   100.0   Steam: 200 MMBtu/hr.
(59 MWt)
NRG Energy Center
Dover, DE
  Kraft Foods Inc.   100.0   Steam: 190 MMBtu/hr.
(56 MWt)
NRG Energy Center
Oak Park Heights, MN
  Anderson Corp., MN
Correctional Facility
  100.0   Steam: 200 MMBtu/Hr.
(59 MWt)
Paxton Creek Cogeneration, Harrisburg, PA
  PJM   100.0   12 MW — Natural Gas
Dover, DE
  PJM   100.0   106 MW — Natural Gas/Coal
 
Other Properties
 
In addition, NRG owns various real property and facilities relating to its generation assets, other vacant real property unrelated to our generation assets, interest in a construction project, and properties not used for operational purposes. NRG believes it has satisfactory title to its plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in the Company’s opinion, would not have a material adverse effect on the use or value of its portfolio.
 
NRG leases its corporate offices at 211 Carnegie Center, Princeton, New Jersey 08540 and various other office spaces.
 


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Item 3 —  Legal Proceedings
 
In re: Wholesale Electricity Antitrust Litigation, Judicial Council Coordinated Proceeding No. 4204, or JCCP 4204, Superior court of California, San Diego County (formerly MDL 1405, U.S. District Court, Southern District of California). The cases included in this proceeding are as follows:
 
Pamela R Gordon, on Behalf of Herself and All Others Similarly Situated v Reliant Energy, Inc. et al., Case No. 758487, Superior Court of the State of California, County of San Diego (filed on November 27, 2000). Ruth Hendricks, On Behalf of Herself and All Others Similarly Situated and On Behalf of the General Public v. Dynegy Power Marketing, Inc. et al., Case No. 758565, Superior Court of the State of California, County of San Diego (filed November 29, 2000). The People of the State of California, by and through San Francisco City Attorney Louise H. Renne v. Dynegy Power Marketing, Inc. et al., Case No. 318189, Superior Court of California, San Francisco County (filed January 18, 2001). Pier 23 Restaurant, A California Partnership, On Behalf of Itself and All Others Similarly Situated v PG&E Energy Trading et al., Case No. 318343, Superior Court of California, San Francisco County (filed January 24, 2001). Sweetwater Authority, et al. v. Dynegy, Inc. et al., Case No. 760743, Superior Court of California, County of San Diego (filed January 16, 2001). Cruz M Bustamante, individually, and Barbara Matthews, individually, and on behalf of the general public and as a representative taxpayer suit, v. Dynegy Inc. et al., inclusive. Case No. BC249705, Superior Court of California, Los Angeles County (filed May 2, 2001).
 
NRG was dismissed from the JCCP 4204 proceeding on July 22, 2005. On May 17, 2006, the U.S. Bankruptcy Court for the Southern District of New York granted NRG’s motion to disallow all pre-petition claims filed against NRG related to the California energy crisis in 2000 and 2001. Plaintiffs did not appeal this decision. Several of WCP’s operating subsidiaries remain defendants in cases that are part of the JCCP 4204 proceeding. The cases in the proceeding allege unfair competition, market manipulation and price fixing and all seek treble damages, restitution and injunctive relief. The defendants, including the WCP subsidiaries, filed a motion to dismiss based on the filed rate doctrine and federal preemption which was granted on October 3, 2005, and a judgment of dismissal with prejudice was entered on October 5, 2005. Plaintiffs filed a notice of appeal on December 2, 2005, with the California Court of Appeals — Fourth District and on February 26, 2007, the court affirmed the lower court’s judgment of dismissal relying on the filed rate doctrine and federal preemption. Where WCP or its subsidiaries are named, Dynegy is defending them pursuant to an indemnification agreement.
 
Bustamante v. McGraw-Hill Companies, Inc., et al., No. BC 235598, California Superior Court, Los Angeles County (filed November 20, 2002, and amended in 2003) — This putative class action alleges that the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades. Named defendants in the suit include several of WCP’s operating subsidiaries. The complaint seeks restitution and disgorgement, civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. Defendants’ motion for summary judgment is pending. Dynegy is defending the WCP subsidiaries pursuant to an indemnification agreement.
 
Texas-Ohio Energy, Inc., on behalf of Itself and all others similarly situated v. Dynegy, Inc. Holding Co., West Coast Power, LLC, et al., Case No. CIV.S-03-2346 DFL GGH, U.S. District Court, Eastern District of California (filed November 10, 2003) — This putative class action alleges violations of the federal Sherman and Clayton Acts and state antitrust law. In addition to naming WCP and Dynegy, Inc. Holding Co., the complaint names numerous industry participants, as well as “unnamed co-conspirators.” The complaint alleges that defendants conspired to manipulate the spot price and basis differential of natural gas with respect to the California market. The complaint seeks unspecified amounts of damages, including a trebling of plaintiff’s and the putative class’s actual damages. On April 18, 2005, the court granted defendants’ motion to dismiss based on the filed rate doctrine and federal preemption. On May 17, 2005, Plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Ninth Circuit. Dynegy is defending WCP pursuant to an indemnification agreement.
 
City of Tacoma, Department of Public Utilities, Light Division, v. American Electric Power Service Corporation, et al., U.S. District Court, Western District of Washington, Case No. C04-5325 RBL (filed June 16, 2004) — The complaint names over 50 defendants, including WCP’s four operating subsidiaries and various Dynegy entities. The complaint also names both us and WCP as “Non-Defendant Co-Conspirators.” Plaintiff alleges a conspiracy to violate the federal Sherman Act by withholding power generation from, and/or inflating the apparent demand for power in markets in California and elsewhere. Plaintiff claims damages in excess of $175 million. After the case was transferred to the U.S. District Court for the Southern District of California on

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February 11, 2005, the court granted defendants’ motion to dismiss the case based on the filed rate doctrine and federal preemption. On March 21, 2005, Plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Ninth Circuit. Dynegy is defending WCP and its subsidiaries pursuant to an indemnification agreement.
 
Fairhaven Power Company v. Encana Corporation, et al., Case No. CIV-F-04-6256 (OWW/ LJO), U.S. District Court, Eastern District of California (filed September 22, 2004), Abelman v. Encana, U.S. District Court, Eastern District of California, Case No. 04-CV-6684 (filed December 13, 2004); Utility Savings v. Reliant, et al., U.S. District Court, Eastern District of California, (filed November 29, 2004) — These putative class actions named WCP and Dynegy Holding Co., Inc. among the numerous defendants. The Complaints alleged violations of the federal Sherman Act, and California’s antitrust and unfair competition law as well as unjust enrichment. The Complaints sought a determination of class action status, a trebling of unspecified damages, statutory, punitive or exemplary damages, restitution, disgorgement, injunctive relief, a constructive trust, and costs and attorneys’ fees. On December 19, 2005, the court granted defendants notice to dismiss based upon the filed rate doctrine and federal preemption. Dynegy is defending WCP pursuant to an indemnification agreement. On February 2, 2006, Dynegy settled the case on behalf of itself and WCP and Plaintiffs are expected to file a motion to approve the settlement with the Court by the end of the first quarter 2007. If approved, WCP will pay no defense costs or settlement funds, as Dynegy owed and provided a complete defense and indemnification.
 
Natural Gas Anti-Trust Cases I,II,III & IV, California Judicial Council Coordination Proceeding Nos. 4221, 4224, 4226 and 4228, San Diego County Superior Court, California. The cases consolidated in this proceeding are as follows:
 
ABAG Publicly Owned Energy Resources v. Sempra Energy, et al., Alameda County Superior Court, Case No. RG04186098, (filed November 10, 2004); Cruz Bustamante v. Williams Energy Services, et al., Los Angeles Superior Court, Case No. BC285598, (filed June 28, 2004); City & County of San Francisco, et al. v. Sempra Energy, et al., San Diego County Superior Court, Case No. GIC832539, (filed June 8, 2004); City of San Diego v. Sempra Energy, et al., San Diego County Superior Court, Case No. GIC839407, (filed December 1, 2004); County of Alameda v. Sempra Energy, Alameda County Superior Court, Case No. RG041282878, (filed October 29, 2004); County of San Diego v. Sempra Energy, et al., San Diego County Superior Court, Case No. GIC833371, (filed July 28, 2004); County of San Mateo v. Sempra Energy, et al., San Mateo County Superior Court, Case No. CIV443882, (filed December 23, 2004); County of Santa Clara v. Sempra Energy, et al., San Diego County Superior Court, Case No. GIC832538, (filed July 8, 2004); Nurserymen’s Exchange, Inc. v. Sempra Energy, et al., San Mateo County Superior Court, Case No. CIV442605, (filed October 21, 2004); Older v. Sempra Energy, et al., San Diego Superior Court, Case No. GIC835457, (filed December 8, 2004); Owens-Brockway Glass Container, Inc. v. Sempra Energy, et al., Alameda County Superior Court, Case No. RG0412046, (filed December 30, 2004); Sacramento Municipal Utility District v. Reliant Energy Services, Inc., Sacramento County Superior Court, Case No. 04AS04689, (filed November 19, 2004); School Project for Utility Rate Reduction v. Sempra Energy, et al., Alameda County Superior Court, Case No. RG04180958, (filed October 19, 2004); Tamco, et al. v. Dynegy, Inc., et al., San Diego County Superior Court, Case No. GIC840587, (filed December 29, 2004); Utility Savings & Refund Services, LLP v. Reliant Energy Services, Inc., et al., U.S. District Court, Eastern District of California, Case No. 04-6626, (filed November 30, 2004); Pabco Building Products v. Dynegy et al., San Diego Superior Court, Case No. GIC 856187, (filed November 22, 2005); The Board of Trustees of California State University v. Dynegy et al., San Diego Superior Court, Case No. GIC 856188, (filed November 22, 2005).
 
The defendants in all of the above referenced cases include WCP and various Dynegy entities. NRG is not a defendant. The Complaints allege that defendants attempted to manipulate natural gas prices in California, and allege violations of California’s antitrust law, conspiracy, and unjust enrichment. The relief sought in all of these cases includes treble damages, restitution and injunctive relief. The Complaints assert that WCP is a joint venture between Dynegy and NRG, but that Dynegy Marketing and Trade handled all of the administrative services and commodity related concerns of WCP. Defendants’ motion to dismiss was denied by the Court on June 22, 2005, and the cases are in discovery. Dynegy entered into a settlement agreement with Plaintiffs on behalf of itself and WCP in the Older case and the court approved the settlement on December 11, 2006. WCP paid no defense costs or


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settlement funds, as Dynegy owed and provided a complete defense and indemnification. In the other cases in this proceedings, Dynegy is defending WCP pursuant to an indemnification agreement.
 
California Electricity and Related Litigation Indemnification — In the above cases relating to natural gas, Dynegy’s counsel is defending WCP and/or its subsidiaries and will be the responsible party for any loss. In the above cases relating to electricity, Dynegy’s counsel is representing it and WCP and/or its subsidiaries with Dynegy and WCP each responsible for half of the costs and each party responsible for half of any loss. Any new cases filed within these categories of cases would be handled in the same manner.
 
Public Utilities Commission of the State of California et al. v. Federal Energy Regulatory Commission, Nos. 03-74246 and 03-74207, FERC Nos. EL 02-60-000, EL 02-60, and EL 02-62 (filed December 19, 2006) — The U.S. Court of Appeals for the Ninth Circuit reversed FERC and remanded the case to FERC for further proceedings consistent with the decision. 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. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. With respect to WCP, the complaint demanded that FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, FERC rejected this demand, denied rehearing, and the case was appealed to the Ninth Circuit where oral argument was held December 8, 2004. The Ninth Circuit held that in FERC’s review of the contracts at issue, FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, as such contracts were not reviewed by FERC with full knowledge of the then-existing market conditions. None of the dependents sought rehearing by the Ninth Circuit within the requested time period. Because an extension of time will be filed shortly, WCP and the other defendants will have until April 18, 2007, to seek review by the U.S. Supreme Court or they can instead wait for the case to be remanded back to FERC. If review before the U.S. Supreme Court is sought, the Court will decide in 2007 whether it will accept the appeal. At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG’s financial condition, results of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy’s share of the WCP assets, WCP and NRG assumed responsibility for any risk of loss arising from this case unless any such loss is 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 by WCP and Dynegy.
 
Connecticut Light & Power Company v. NRG Power Marketing, Inc., Docket No. 3:01-CV-2373 (AWT), U.S. District Court, District of Connecticut (filed on November 28, 2001) — Connecticut Light & Power Company, or CL&P, sought recovery of amounts it claimed it was owed for congestion charges under the terms of an October 29, 1999, contract between the parties. CL&P withheld approximately $30 million from amounts owed to NRG Power Marketing, Inc., or PMI, and PMI counterclaimed. CL&P filed its motion for summary judgment to which PMI filed a response on March 21, 2003. By reason of the stay issued by the bankruptcy court, the court has not ruled on the pending motion. On November 6, 2003, the parties filed a joint stipulation for relief from the stay in order to allow the proceeding to go forward, which was promptly granted. PMI cannot estimate at this time the overall exposure for congestion charges for the full term of the contract.
 
Connecticut Light & Power Company v. NRG Energy, Inc., Federal Energy Regulatory Commission Docket No. EL03-10-000-Station Service Dispute (filed October 9, 2002); Binding Arbitration — On July 1, 1999, Connecticut Light & Power Company, or CL&P, and the Company agreed that we would purchase certain CL&P generating facilities. The transaction closed on December 14, 1999, whereupon NRG took ownership of the facilities. CL&P began billing NRG for station service power and delivery services provided to the facilities and NRG refused to pay, asserting that the facilities self-supplied their station service needs. On October 9, 2002, Northeast Utilities Services Company, on behalf of itself and CL&P, filed a complaint at FERC seeking an order requiring NRG Energy to pay for station service and delivery services. On December 20, 2002, FERC issued an Order finding that at times when NRG is not able to self-supply its station power needs, there is a sale of station power from a third-party and retail charges apply. CL&P renewed its demand for payment which was again refused by NRG. In August 2003, the parties agreed to submit the dispute to binding arbitration. In July and August 2006,


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the parties submitted their respective statements to the three member arbitration panel. A discovery and briefing schedule was issued and a hearing is set for September 2007.
 
Niagara Mohawk Power Corporation v. Dunkirk Power LLC, NRG Dunkirk Operations, Inc., Huntley Power LLC, NRG Huntley Operations, Inc., Oswego Power LLC and NRG Oswego Operations, Inc., Supreme Court, Erie County, Index No. 1-2000-8681 — Station Service Dispute (filed October 2, 2000) — NiMo sought to recover damages less payments received through the date of judgment, as well as additional amounts for electric service provided to the Dunkirk Plant. NiMo claimed that we failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999, and continuing to September 18, 2000, and thereafter. On October 8, 2002, a Stipulation and Order was entered, staying this action pending resolution by FERC of the disputes in this matter.
 
Niagara Mohawk Power Corporation v. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and NRG Oswego Operations, Inc., (Filed November 26, 2002) in Federal Energy Regulatory Commission Docket No. EL 03-27-000 — This is the companion action to the above referenced action filed by NiMo at FERC asserting the same claims and legal theories. On November 19, 2004, FERC denied NiMo’s petition and ruled that the Huntley, Dunkirk and Oswego plants could net their service station obligations over a 30 calendar day period from the day NRG Energy acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. On April 22, 2005, FERC denied NiMo’s motion for rehearing and on October 23, 2006, the U.S. Court of Appeals for the D.C. Circuit denied rehearing. On January 22, 2007, NiMo filed a petition for certiorari seeking review before the U.S. Supreme Court.
 
CFTC Trading Litigation — On July 1, 2004, the Commodities Futures Trading Commission, or CFTC, filed a civil complaint against us in Minnesota federal district court, alleging false reporting of natural gas trades from August 2001 to May 2002, and seeking an injunction against future violations of the Commodity Exchange Act. On March 16, 2005, the federal district court in Minnesota dismissed the case. On appeal, the U.S. Court of Appeals in August 2006 reversed the district court’s dismissal. The parties have agreed to a settlement in which NRG agreed to give the CFTC a $2 million allowed class 5 claim in NRG’s bankruptcy proceeding. The settlement agreement was approved by the Court on February 13, 2007.
 
Additional Litigation — In addition to the foregoing, NRG is party to other litigation or legal proceedings. The Company believes that it has valid defenses to the legal proceedings and investigations described above and intends to defend them vigorously. However, litigation is inherently subject to many uncertainties. There can be no assurance that additional litigation will not be filed against the Company or its subsidiaries in the future asserting similar or different legal theories and seeking similar or different types of damages and relief. Unless specified above, the Company is unable to predict the outcome these legal proceedings and investigations may have or reasonably estimate the scope or amount of any associated costs and potential liabilities. An unfavorable outcome in one or more of these proceedings could have a material impact on the Company’s consolidated financial position, results of operations or cash flows. The Company also has indemnity rights for some of these proceedings to reimburse the Company for certain legal expenses and to offset certain amounts deemed to be owed in the event of an unfavorable litigation outcome.
 
Disputed Claims Reserve — As part of NRG’s plan of reorganization, NRG funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, as such claims are resolved; the claimants are paid from the reserve on the same basis as if they had been paid out in the bankruptcy. To the extent the aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the funded claims reserve, NRG will be obligated to provide additional cash and common stock to satisfy the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the reserves is held by an escrow agent to complete the distribution and settlement process. Since NRG has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from the balance sheet. Similarly, NRG removed the obligations relevant to the claims from the balance sheet when the common stock was issued and cash contributed.
 
On April 3, 2006, the Company made a supplemental distribution to creditors under the Company’s Chapter 11 plan totaling $25 million in cash and 2,541,000 shares of common stock. As of January 24, 2007, the reserve held


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approximately $9.9 million in cash and approximately 691,700 shares of common stock. NRG believes the cash and stock together represent sufficient funds to satisfy all remaining disputed claims.
 
Item 4 —  Submission of Matters to a Vote of Security Holders
 
None.
 
PART II
 
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Market Information and Holders
 
NRG’s authorized capital stock consists of 500,000,000 shares of NRG common stock and 10,000,000 shares of preferred stock. A total of 8,000,000 shares of the Company’s common stock are available for issuance under NRG’s Long-Term Incentive Plan. NRG has also filed with the Secretary of State of Delaware a Certificate of Designation for each of the following shares of the Company’s preferred stock: (i) 4% Convertible Perpetual Preferred Stock, (ii) 3.625% Convertible Perpetual Preferred Stock, and (iii) 5.75% Mandatory Convertible Preferred Stock.
 
NRG’s common stock is listed on the New York Stock Exchange and has been assigned the symbol: NRG. NRG has submitted to the New York Stock Exchange its annual certificate from its Chief Executive Officer certifying that he is not aware of any violation by the Company of New York Stock Exchange corporate governance listing standards. The high and low sales prices, as well as the closing price for the Company’s common stock on a per share basis for 2006 and 2005 are set forth below:
 
                                                                 
    Fourth
    Third
    Second
    First
    Fourth
    Third
    Second
    First
 
    Quarter
    Quarter
    Quarter
    Quarter
    Quarter
    Quarter
    Quarter
    Quarter
 
Common Stock Price   2006     2006     2006     2006     2005     2005     2005     2005  
 
High
  $ 59.48     $ 51.15     $ 52.61     $ 49.46     $ 49.44     $ 44.45     $ 37.61     $ 39.10  
Low
  $ 44.27     $ 44.25     $ 42.44     $ 41.79     $ 37.60     $ 36.40     $ 30.30     $ 32.79  
Closing
  $ 56.01     $ 45.30     $ 48.18     $ 45.22     $ 47.12     $ 42.60     $ 37.60     $ 34.15  
 
NRG had 122,323,551 shares outstanding as of December 31, 2006, and as of February 23, 2007, there were 122,335,466 shares outstanding. As of February 22, 2007, there were approximately 36,500 common stockholders of record.
 
Dividends
 
NRG has not declared or paid dividends on its common stock and the amount available for dividends is currently limited by the Company’s senior secured credit agreements and high yield note indentures.


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Repurchase of equity securities
 
NRG’s repurchases of equity securities during 2006 were as follows:
 
                                 
                Total Number
       
                of Shares
    Dollar Value
 
                Purchased as
    of Shares That
 
    Total Number
    Average Price
    Part of Publicly
    May be Purchased
 
    of Shares
    Paid per
    Announced Plans
    Under the Plans
 
For the Year Ended December 31, 2006   Purchased     Share     or Programs     or Programs  
 
First quarter
                       
                                 
Second quarter
                       
                                 
July 1 – July 31
                       
August 1 – August 31
                    $ 500,000,000  
September 1 – September 30
    6,113,000     $ 48.61       6,113,000       202,847,070  
                                 
Third quarter total
    6,113,000       48.61       6,113,000        
                                 
October 1 – October 31
    4,474,700       45.32       4,474,700       500,053,666  
November 1 – November 30
    4,212,881       55.00       4,212,881       268,345,211  
December 1 – December 31
                       
                                 
Fourth quarter total
    8,687,581       50.01       8,687,581       268,345,211  
                                 
Total for 2006
    14,800,581     $ 49.43       14,800,581     $ 268,345,211  
                                 
 
During the third quarter 2006, as part of the Company’s Capital Allocation Program, NRG repurchased approximately $750 million of the Company’s common stock in two phases. Phase I was a $500 million stock repurchase program, which was completed on October 13, 2006, with total common stock repurchased of 10,587,700 shares.
 
Phase II, as originally announced, was to be an additional $250 million common stock buyback. This amount was subsequently increased to $500 million and Phase II commenced during the fourth quarter 2006, bringing the Company’s total announced share buyback to $1 billion. On November 24, 2006, NRG repurchased 4,212,881 shares of NRG common stock from affiliates of the Blackstone Group at a price of $55.00 per share as part of Phase II. Following this repurchase, the four largest previous shareholders of Texas Genco LLC have concluded the sale of all of their NRG common stock received pursuant to the Acquisition. We expect to complete Phase II during the first half of 2007.
 
Securities Authorized for Issuance under Equity Compensation Plans
 
                         
    (a)     (b)     (c)  
                Number of Securities
 
                Remaining Available
 
    Number of Securities
          for Future Issuance
 
    to be Issued Upon
    Weighted-Average Exercise
    Under Compensation
 
    Exercise of
    Price of Outstanding
    Plans (Excluding
 
    Outstanding Options,
    Options, Warrants and
    Securities Reflected
 
Plan Category   Warrants and Rights     Rights     in Column (a)  
 
Equity compensation plans approved by security holders
    3,395,413     $ 24.22       4,301,489(a )
Equity compensation plans not approved by security holders
        N/ A        
                         
Total
    3,395,413     $ 24.22       4,301,489(a )
                         
 
 
(a) NRG Energy, Inc.’s Long-Term Incentive Plan, or the LTIP, became effective upon the Company’s emergence from bankruptcy. The LTIP was subsequently approved by the Company’s stockholders on August 4, 2004 and was amended on April 28, 2006 to increase the number of shares available for issuance to 8,000,000 and again on December 8, 2006 to make technical and administrative changes. The LTIP provides for grants of stock options, stock appreciation rights, restricted stock, performance units, deferred stock units and dividend equivalent rights.


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NRG’s directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the LTIP. The purpose of the LTIP is to promote the Company’s long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company’s success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the LTIP. There were 4,301,489 and 1,355,193 shares of common stock remaining available for grants of awards under NRG’s LTIP as of December 31, 2006 and 2005, respectively.
 
Stock Performance Graph
 
The performance graph below compares NRG’s cumulative total shareholder return on the Company’s common stock for the period January 2, 2004 through December 31, 2006 with the cumulative total return of the Standard & Poor’s 500 Composite Stock Price Index, or S&P 500, and the Philadelphia Utility Sector Index, or UTY. Upon the Company’s emergence from bankruptcy on December 5, 2003 until March 24, 2004, NRG’s common stock traded on the Over-The-Counter Bulletin Board. On March 25, 2004, NRG’s common stock commenced trading on the New York Stock Exchange under the symbol “NRG”.
 
The performance graph shown below is being provided as furnished and compares each period assuming that $100 was invested on January 2, 2004 in each of the common stock of NRG, the stocks included in the S&P 500 and the stocks included in the UTY, and that all dividends were reinvested.
 
Comparison of Cumulative Total Return
 
(PERFORMANCE GRAPH)
 
                                                                                                                                   
      1/04     3/04     6/04     9/04     12/04     3/05     6/05     9/05     12/05     3/06     6/06     9/06     12/06
NRG
    $ 100       $ 98.89       $ 110.47       $ 120.00       $ 160.58       $ 152.12       $ 167.48       $ 189.76       $ 209.89       $ 201.43       $ 214.61       $ 201.78       $ 249.49  
S&P 500
      100         101.69         103.44         101.50         110.88         108.50         109.98         113.95         116.33         121.22         119.48         126.25         134.70  
UTY
    $ 100       $ 105.95       $ 104. 20       $ 111.74       $ 126.23       $ 133.97       $ 145.94       $ 157.53       $ 149.50       $ 146.70       $ 155.86       $ 165.24       $ 179.67  
                                                                                                                                   


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Item 6 — Selected Financial Data
 
The following table presents NRG’s historical selected financial data. The data included in the following table has been restated to reflect the assets, liabilities and results of operations of certain projects that have met the criteria for treatment as discontinued operations. For additional information refer to Item 15 — Note 4, Discontinued Operations, to the Consolidated Financial Statements.
 
This historical data should be read in conjunction with the Consolidated Financial Statements and the related notes thereto in Item 15 and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. Due to the adoption of Fresh Start reporting as of December 5, 2003, Reorganized NRG’s balance sheet and statement of operations have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of Fresh Start reporting.
 
                                                   
    Reorganized NRG       Predecessor Company  
                      December 6 -
      January 1 -
    Year Ended
 
    Year Ended December 31,     December 31,
      December 5,
    December 31,
 
    2006     2005     2004     2003       2003     2002  
    (In millions except ratio and per share data)  
Statement of income data:
                                                 
Total operating revenues
  $ 5,623     $ 2,430     $ 2,104     $ 121       $ 1,589     $ 1,688  
Total operating costs and expenses
    4,743       2,311       1,875       110         (1,603 )     4,544  
Income/(loss) from continuing operations, net
    555       72       155       12         3,131       (2,697 )
Income/(loss) from discontinued operations, net
    66       12       31       (1 )       (365 )     (767 )
Net income/(loss)
    621       84       186       11         2,766       (3,464 )
Common share data:
                                                 
Basic shares outstanding — average
    129       85       100       100                    
Diluted shares outstanding — average
    150       85       100       100                    
Shares outstanding — end of year
    122       81       87       100                    
Per share data:
                                                 
Income from continuing operations — basic
    3.90       0.61       1.55       0.12                    
Income from continuing operations — diluted
    3.63       0.61       1.54       0.12                    
Net income — basic
    4.41       0.76       1.86       0.11                    
Net income — diluted
    4.07       0.75       1.85       0.11                    
Book value
    38.96       22.61       26.26       24.37                    
 


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    Reorganized NRG       Predecessor Company  
                      December 6 -
      January 1 -
    Year Ended
 
    Year Ended December 31,     December 31,
      December 5,
    December 31,
 
    2006     2005     2004     2003       2003     2002  
    (In millions except ratio and per share data)  
Business metrics:
                                                 
Cash flow from operations
    408       68       645       (589 )       238       430  
Liquidity position
  $ 2,227     $ 758     $ 1,600     $ 1,545       N/ A     N/ A  
Ratio of earnings to fixed charges
    2.38       1.56       1.88       1.71         11.61       (5.17 )
Ratio of earnings to fixed charges and preference dividends
    2.10       1.33       1.88       1.71         11.61       (5.17 )
Return on equity
    10.98       3.77       6.91     N/ A       N/ A     N/ A  
Ratio of debt to total capitalization
    57.48       44.82       44.99       56.09       N/ A     N/ A  
Balance sheet data:
                                                 
Current assets
  $ 3,083     $ 2,196     $ 2,121     $ 2,186       N/ A     $ 1,584  
Current liabilities
    2,032       1,357       1,091       2,098       N/ A       9,865  
Property, plant and equipment, net
    11,600       2,609       2,685       3,315       N/ A       5,196  
Total assets
    19,435       7,466       7,873       9,320       N/ A       10,964  
Long-term debt, including current maturities and capitol leases
    8,777       2,505       3,271       3,648       N/ A       7,117  
Total stockholders’ equity/(deficit)
  $ 5,658     $ 2,231     $ 2,692     $ 2,437       N/ A     $ (696 )
 
                                                 
 
N/A not applicable
 
The following table provides the details of NRG’s operating revenues:
 
                                                   
    Reorganized NRG       Predecessor Company  
                      December 6 -
      January 1 -
    Year Ended
 
    Year Ended December 31,     December 31,
      December 5,
    December 31,
 
    2006     2005     2004     2003       2003     2002  
              (In millions)  
Energy
  $ 3,193     $ 1,870     $ 1,205     $ 53       $ 788     $ 1,028  
Capacity
    1,516       563       612       37         566       553  
Risk management activities
    124       (292 )     61               19       7  
Contract amortization
    628       9       (6 )     13                
Thermal
    124       124       112       9         24       30  
Hedge Reset
    (129 )                                
Other
    167       156       120       9         192       70  
                                                   
Total operating revenues
  $ 5,623     $ 2,430     $ 2,104     $ 121       $ 1,589     $ 1,688  
                                                   
 
Energy revenue consists of revenues received from third parties for sales in the day-ahead and real-time markets, as well as bilateral sales. Beginning in 2006, energy revenues also included revenues from the settlement of financial instruments that qualify for cash flow hedge accounting treatment.
 
Capacity revenue consists of revenues received from a third party at either the market or negotiated contract rates for making installed generation capacity available in order to satisfy system integrity and reliability

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requirements. In addition, capacity revenue includes revenue received under tolling arrangements, which entitle third parties to dispatch NRG’s facilities and assume title to the electrical generation produced from that facility.
 
Risk management activities are comprised of fair value changes of financial instruments that have yet to be settled as well as ineffectiveness on financial transactions accorded cash flow hedge accounting treatment. It also includes the settlement of all derivative transactions that do not qualify for cash flow hedge accounting treatment. Prior to 2006, risk management activities included the settlement of financial instruments that qualified for cash flow hedge accounting treatment.
 
Thermal revenue consists of revenues received from the sale of steam, hot and chilled water generally produced at a central district energy plant and sold to commercial, governmental and residential buildings for space heating, domestic hot water heating and air conditioning. It also includes the sale of high-pressure steam produced and delivered to industrial customers that is used as part of an industrial process.
 
Contract amortization revenues consists of acquired power contracts, gas swaps, and certain power sales agreements assumed at Fresh Start related to the sale of electric capacity and energy in future periods, which are amortized into revenue over the term of the underlying contracts based on actual generation or contracted volumes.
 
Hedge Reset is the impact from the net settlement of long-term power contracts and gas swaps by negotiating prices to current market. This transaction was completed in November 2006.
 
Other revenue primarily consists of operations and maintenance fees, O&M fees, sale of natural gas and emission allowances, and revenue from ancillary services. O&M fees consist of revenues received from providing certain unconsolidated affiliates with services under long-term operating agreements. Ancillary services are comprised of the sale of energy-related products associated with the generation of electrical energy such as spinning reserves, reactive power and other similar products.


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Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
In this discussion and analysis, the Company discusses and explains the financial condition and the results of operations for NRG during 2006 that will include the points below:
 
  •  Factors which affect NRG’s business;
 
  •  NRG’s earnings and costs in the periods presented;
 
  •  Changes in earnings and costs between periods;
 
  •  Impact of these factors on NRG’s overall financial condition;
 
  •  A discussion of known trends that may affect NRG’s future results of operations and financial condition;
 
  •  Expected future expenditures for capital projects; and
 
  •  Expected sources of cash for future operations and capital expenditures.
 
As you read this discussion and analysis, refer to NRG’s Consolidated Statements of Operations, which present the results of the Company’s operations for the years ended December 31, 2006, 2005 and 2004. The Company analyzes and explains the differences between the periods in the specific line items of NRG’s Consolidated Statements of Operations. This discussion and analysis has been organized as follows:
 
  •  Business strategy;
 
  •  Business environment in which NRG operates including how regulation, weather, and other factors affect the business;
 
  •  Significant events that are important to understanding the results of operations and financial condition;
 
  •  Results of operations including an overview of the Company’s results, followed by a more detailed review of those results by operating segment;
 
  •  Financial condition addressing its credit ratings, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements;
 
  •  Known trends that will affect NRG’s results of operations in the future; and
 
  •  Critical accounting policies which are most important to both the portrayal of the Company’s financial condition and results of operations, and which require management’s most difficult, subjective or complex judgment.
 
Executive Summary
 
Overview
 
NRG Energy, Inc., NRG, or the Company, is a wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is primarily engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the United States and internationally. As of December 31, 2006, NRG had a total global portfolio of 223 active operating generation units at 51 power generation plants, with an aggregate generation capacity of approximately 24,175 MW. Within the United States, the Company has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,940 MW of generation capacity in 207 active generating units at 45 plants. These power generation facilities are primarily located in Texas, (approximately 10,760 MW), and the Northeast (approximately 7,240 MW), South Central (approximately 2,850 MW) and the West (approximately 1,965 MW) regions of the United States, with approximately 125 MW from the Company’s thermal assets. NRG’s principal domestic power plants consist of a diversified mix of natural gas-, coal-, oil-fired and nuclear facilities, representing approximately 45%, 34%, 16% and 5% of the Company’s total domestic generation capacity, respectively. In addition, 15% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option, and consist primarily of baseload,


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intermediate and peaking power generation facilities, which are referred to as the merit order, and also include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company’s revenues and provides a stable source of cash flow. In addition, NRG’s diverse 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. In addition, NRG is pursuing opportunities to repower existing facilities and develop new generation capacity in markets in which NRG currently owns assets in an initiative referred to as Repowering NRG. In connection with NRG’s acquisition of Padoma Wind Power LLC, the Company has and will continue to actively evaluate and potentially develop or construct domestic terrestrial wind projects as part of the Repowering NRG program.
 
Business Strategy
 
NRG’s strategy is to optimize the value of the Company’s generation assets while using that asset base as a platform for growth and enhanced financial performance which can be sustained and expanded upon in the years to come. NRG plans to maintain and enhance the Company’s position as a leading wholesale power generation company in the United States in a cost-effective and risk-mitigating manner in order to serve the bulk power requirements of NRG’s existing customer base and other entities that offer load or otherwise consume wholesale electricity products and services in bulk. NRG’s strategy includes the following elements:
 
Pursue additional growth opportunities at existing sites — NRG is favorably positioned to pursue growth opportunities through expansion of its existing generating capacity and development of new generating capacity at its existing facilities. NRG intends to invest in the Company’s existing assets through plant improvements, repowerings, brownfield development and site expansions to meet anticipated requirements for additional capacity in NRG’s core markets. In furtherance of this goal, NRG has initiated a company-wide program, known as Repowering NRG, to develop, construct and operate new and enhanced power generation facilities at its existing sites, with an emphasis on new baseload capacity that is supported by long-term power sales agreements and financed with limited or non-recourse project financing. NRG expects that these efforts will provide one or more of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; an improved ability to dispatch economically across the merit order; increased technological and fuel diversity; and reduced environmental impacts, including facilities that either have zero greenhouse gas emissions or can be equipped to capture and, eventually, sequester greenhouse gas emissions.
 
Increase value from existing assets — NRG has a highly diversified portfolio of power generation assets in terms of region, fuel-type and dispatch levels. NRG will continue to focus on extracting value from its portfolio by improving plant performance, reducing costs and harnessing the Company’s advantages of scale in the procurement of fuels and other commodities, parts and services, and in doing so improve the Company’s return on invested capital, or ROIC — a strategy that NRG has branded FORNRG, or Focus on ROIC@NRG.
 
Maintain financial strength and flexibility — NRG remains focused on cash flow and maintaining appropriate levels of liquidity, debt and equity in order to ensure continued access to capital for investment, to enhance risk-adjusted returns and to provide flexibility in executing NRG’s business strategy. NRG will continue to focus on maintaining operational and financial controls designed to ensure that the Company’s financial position remains strong. At the same time, NRG expects to continue its practice of returning excess cash flows to its debt and equity investors on a regular basis.  
 
Reduce the volatility of the Company’s cash flows through asset-based commodity hedging activities — NRG will continue to execute asset-based risk management, hedging, marketing and trading strategies within well defined risk and liquidity guidelines in order to manage the value of the Company’s physical and contractual assets. The Company’s marketing and hedging philosophy is centered on generating stable returns from its portfolio of baseload power generation assets while preserving an ability to capitalize on strong spot market conditions and to capture the extrinsic value of the Company’s intermediate and peaking facilities and portions of its baseload fleet. NRG believes that it can successfully execute this strategy by leveraging its expertise in marketing power and ancillary services, its knowledge of markets, its balanced financial structure and its diverse portfolio of power generation assets.


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Pursue strategic acquisitions and divestures — NRG will continue to pursue selective acquisitions, joint ventures and divestitures to enhance its asset mix and competitive position in the Company’s core regions to meet the fuel and dispatch requirements in these regions. NRG intends to concentrate on opportunities that present attractive risk-adjusted returns. NRG will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures.
 
Business Environment
 
General Industry — 2006 was yet another year of progress and transition for the power generation industry. The industry dynamics and external influences that are most likely to significantly affect the Company and the power generation industry in 2007 include:  
 
Emissions — Environmental compliance policies on a federal and state level continue to accelerate in a variety of ways, presenting challenges to the industry as a result of various uncertainties. In the case of SO2 and NOx, the regulatory regime is well-settled but the tightening standards taking effect in 2010 and 2014 have caused a need to add capital intensive “back end” controls. This remediation requirement has led to dramatic increases in, and uncertainty with respect to, the ultimate cost to comply with the stricter regulations. In the case of mercury (Hg), there is greater regulatory and technical uncertainty as various states have imposed, or are intending to impose, tougher standards than currently provided for under federal law and the technological solutions to comply with such standards are less certain both with respect to efficacy and cost. Finally, the move towards federal carbon regulation to combat global warming is gaining momentum but the timing, shape and ultimate disposition of that legislation and the impact it will have are unknown.
 
Consolidation — Two “mega-utility” combinations (FPL Group Inc./Constellation Energy Group and Exelon Corp./PSEG) failed due to state regulatory opposition in 2006. While there are still likely to be some regulated utility mergers in the future, mergers and acquisitions activity in the power generation sector for the time being are likely to involve utility-merchant or merchant-merchant combinations and acquisitions by private equity funds or consortia of power generation assets, portfolios or entire companies. There may also be interest by foreign power companies, particularly European utilities, in the American power generation sector.
 
Infrastructure Development — In response to record peak demand, tightening reserve margins, persistently high and volatile natural gas prices and ever increasing environmental sensitivity, the power generation industry has announced significant expansion plans for both transmission and generation. In stark contrast to the previous wave of new power generation in the United States, which was almost exclusively natural gas-fired, much of the new generation announced around the nation has focused on non-gas fuel sources, including coal, nuclear and renewable sources.
 
Capacity Markets — Considerable progress was made in ISO-NE and PJM towards approval and implementation of locational capacity markets. The CPUC also took steps towards establishing locational capacity requirements, thus a bilateral market for capacity. The objective of such market structures is to provide timely and accurate market signals to encourage new investment in transmission and new generation in the locations where the new investment is needed.
 
Commodity Prices and Volatility — Commodity prices have abated after hitting record highs during 2005. The single biggest driver on a national level for the downtrend in prices has been driven primarily by mild weather conditions resulting in excess gas storage due to below normal withdrawals. However, volatility continues to predominate the commodities market with many financial and hedge fund players seeking to participate and build up their trading positions in the energy sector.
 
Skills Scarcity — After more than a decade long contraction of the power generation industry’s workforce, the industry finds itself poised for expansion, but hampered by an aging workforce, with current and projected shortages of experienced engineers, skilled operators, and maintenance workers. This skills deficit also has the potential to hamper the power generation industry’s ability to design and construct the next wave of power generation infrastructure needed in this country.


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Competition
 
Competition — Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. NRG competes on the basis of the location of its plants and owning multiple plants in its regions, which increases the stability and reliability of its energy supply. Wholesale power generation is basically a local business that is currently highly fragmented relative to other commodity industries and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies NRG competes against depending on the market.
 
Regulatory
 
As an operator of power plants and a participant in the wholesale markets, NRG is subject to regulation by various federal and state government agencies. These include CFTC, FERC, NRC, PUCT and other public utility commissions in certain states where NRG’s generating assets are located. In addition, NRG is also subject to the market rules, procedures, and protocols of the various ISO markets in which NRG participates. These wholesale power markets are subject to ongoing legislative and regulatory changes. The Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on NRG’s business. NRG supports the efficient operation of the wholesale markets; however, opposition to wholesale power markets has increased. Support for the mitigation of sellers has increased in order to reduce prices. In some of NRG’s regions, interested parties have advocated for material market design changes, including the elimination of a single clearing price mechanism, as well as proposals to re-regulate the markets or require divestiture by generating companies to reduce their market share.
 
Weather
 
Weather conditions in the different regions of the United States influence the financial results of NRG’s businesses. Weather conditions can affect the supply and demand for electricity and fuels. Changes in energy supply and demand may impact the price of these energy commodities in both the spot and forward markets, which may affect the Company’s results in any given period. Typically, demand for and the price of electricity is higher in the summer and the winter seasons, when temperatures are more extreme. The demand for and price of natural gas and oil are higher in the winter. However, all regions of North America typically do not experience extreme weather conditions at the same time, thus NRG is typically not exposed to the effects of extreme weather in all parts of its business at once.
 
Other Factors
 
A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for NRG’s business. These factors include:
 
  •  seasonal daily and hourly changes in demand;
 
  •  extreme peak demands;
 
  •  available supply resources;
 
  •  transportation and transmission availability and reliability within and between regions;
 
  •  location of NRG’s generating facilities relative to the location of its load-serving opportunities;
 
  •  procedures used to maintain the integrity of the physical electricity system during extreme conditions; and
 
  •  changes in the nature and extent of federal and state regulations.
 
These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in:
 
  •  weather conditions;
 
  •  market liquidity;


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  •  capability and reliability of the physical electricity and gas systems;
 
  •  local transportation systems; and
 
  •  the nature and extent of electricity deregulation.
 
Environmental Matters and Legal Proceedings
 
NRG discusses details of its environmental matters in Item 15 — Note 23, Environmental Matters, to its Consolidated Financial Statements and Item 1, Business — Environmental Matters, section. NRG discusses details of its legal proceedings in Item 15 — Note 21, Commitments and Contingencies, to its Consolidated Financial Statements. Some of this information is about costs that may be material to the Company’s financial results.
 
Impact of inflation on NRG’s results
 
Unless discussed specifically in the relevant segment, for the years ended December 31, 2006, 2005 and 2004, the impact of inflation and changing prices (due to changes in exchange rates) on NRG’s revenues and income from continuing operations was immaterial.
 
Capital Allocation Strategy
 
NRG’s capital allocation philosophy includes reinvestment in its core facilities, maintenance of prudent debt levels and interest coverage, the regular return of capital to shareholders and investment in repowering opportunities. Each of these components is described further as follows:
 
  •  Reinvestment in Existing Assets — Opportunities to invest in the existing business, including maintenance and environmental capital expenditures that improve operational performance, ensure compliance with environmental laws and regulations, and expansion projects.
 
  •  Management of Debt Levels — The Company uses several metrics to measure the efficiency of its capital structure and debt balances. Generally, the Company’s targeted net debt to total capital ratio range is 45% to 60%. The Company intends in the normal course of business to continue to manage its debt levels towards the lower end of the range and may, from time to time, pay down its debt balances for a variety of reasons.
 
  •  Return of Capital to Shareholders — The Company’s debt instruments include restrictions on the amount of capital that can be returned to shareholders. The Company has in the past returned capital to shareholders while maintaining compliance with existing debt agreements and indentures. The Company expects to regularly return capital either through dividends or share repurchases to shareholders.
 
  •  Repowering Opportunities — The Company intends to pursue repowering initiatives that enhance and diversify its portfolio and provide a targeted economic return to the Company.
 
Known Trends and Uncertainties
 
  •  Initiation of a portfolio repowering effort to add approximately 10,350 MW of new multi-fuel, multi-technology generation capacity at NRG’s existing domestic sites to meet growing demand in all of the Company’s core domestic markets.
 
  •  Continued share repurchases through the Company’s Capital Allocation Program.
 
  •  Increasing the baseload hedge profile to 59% in 2010, 65% in 2011 and 24% in 2012, to provide certainty around the Company’s future cash flows.
 
Significant events that affected NRG’s results of operations for the year ended December 31, 2006
 
Operational
 
  •  Reset legacy Texas region long-term out-of-market power contracts and gas swaps by negotiating to current market price levels resulting in a reduction in operating income of $135 million.


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  •  Total generation increased by 154% primarily due to the addition of the Texas region to the NRG total portfolio.
 
  •  Improved operating performance and new tolling agreements contributed to $97 million of higher operating income from the South Central region.
 
  •  A mild winter and summer coupled with weak power prices lowered generation demand for the Northeast region’s generation assets by 18%.
 
  •  NRG recorded $187 million in refinancing costs and $599 million in interest expense primarily due to new debt facilities associated with the acquisition of NRG Texas.
 
  •  Record peak energy demand in each of the market’s served by NRG’s major business segments ranging with increases of 4% to 11% over previous records.
 
  •  Recognized $124 million in gains from risk management activities.
 
Acquisitions/Dispositions
 
  •  On February 2, 2006, NRG acquired Texas Genco LLC. Texas Genco LLC and its affiliates are now wholly-owned subsidiaries of NRG, and is managed and accounted for as a separate business segment referred to as Texas region.
 
  •  On August 30, 2006, NRG announced the completion of the sale of its 100% owned Flinders power station and related assets. NRG received approximately $242 million in cash and recognized an after-tax gain on the sale of approximately $60 million.
 
  •  On March 31, 2006, NRG acquired Dynegy’s 50% ownership interest in WCP, and became the sole owner of WCP’s 1,825 MW of generation in Southern California. The results of operations of WCP were consolidated as of April 1, 2006, prior to which, NRG’s 50% ownership of WCP was recorded as an equity method investment.
 
  •  On November 8, 2006, NRG completed the sale of its Newport and Elk River Resource Recovery facilities, its Becker Ash Disposal facility as well as its ownership in NRG Processing Solutions, LLC, to Resource Recovery Technologies, LLC for approximately $22 million. The Company recognized a gain of approximately $5 million.
 
Other
 
  •  On January 31, 2006, NRG finalized a settlement agreement with an equipment manufacturer related to certain turbine purchase agreements. Upon finalization of the settlement, NRG recorded a total of $67 million of other income, of which $35 million was related to the discharge of accounts payable previously recorded and $32 million was related to the receiving and recording of the equipment at fair value.
 
  •  Incurred approximately $36 million in development costs primarily related to Repowering NRG program.


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Consolidated Results of Operations
 
2006 compared to 2005
 
The following table provides selected financial information for NRG Energy, Inc., for the years ended December 31, 2006 and 2005.
 
                         
    Year Ended December 31,        
    2006     2005     Change %  
    (In millions except otherwise noted)        
 
Operating Revenues
                       
Energy revenue
  $ 3,193     $ 1,870       71 %
Capacity revenue
    1,516       563       169  
Risk management activities
    124       (292 )     NA  
Contract amortization
    628       9       NA  
Thermal revenue
    124       124        
Hedge Reset
    (129 )           NA  
Other revenues
    167       156       7  
                         
Total operating revenues
    5,623       2,430       131  
                         
Operating Costs and Expenses
                       
Cost of operations
    3,276       1,838       78  
Depreciation and amortization
    593       162       266  
General, administrative and development
    316       181       75  
Impairment charges
          6       NA  
Corporate relocation charges
          6       NA  
                         
Total operating costs and expenses
    4,185       2,193       91  
                         
Operating Income
    1,438       237       507  
Other Income/(Expense)
                       
Equity in earnings of unconsolidated affiliates
    60       104       (42 )
Write downs and gains/(losses) on sales of equity method investments
    8       (31 )     NA  
Other income, net
    160       58       176  
Refinancing expenses
    (187 )     (65 )     188  
Interest expense
    (599 )     (184 )     226  
                         
Total other expenses
    (558 )     (118 )     373  
                         
Income from Continuing Operations before income tax expense
    880       119       639  
Income tax expense
    325       47       591  
                         
Income from Continuing Operations
    555       72       671  
Income from discontinued operations, net of income tax expense
    66       12       450  
                         
Net Income
  $ 621     $ 84       639  
                         
Business Metrics
                       
Average natural gas price — Henry Hub ($/MMbtu)
    6.75       8.89       (24 )%


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For the benefit of the following discussions, the table below represents the results of NRG excluding the impact of the Company’s Texas region, the Hedge Reset and WCP:
 
                                         
    Year Ended December 31,  
    2006     2005  
                      Total excluding
       
    Consolidated     Texas Region     WCP     Texas Region/WCP     Consolidated  
    (In millions)  
 
Energy revenue
  $ 3,193     $ 1,726     $ 72     $ 1,395     $ 1,870  
Capacity revenue
    1,516       849       64       603       563  
Risk management activities
    124       (30 )           154       (292 )
Contract amortization
    628       609             19       9  
Thermal revenue
    124                   124       124  
Hedge Reset
    (129 )     (129 )                  
Other revenues
    167       63       5       99       156  
                                         
Total Operating revenues
    5,623       3,088       141       2,394       2,430  
                                         
Cost of operations
    3,276       1,669       112       1,495       1,838  
Depreciation and amortization
    593       413       2       178       162  
General, administrative and development
    316       125       10       181       181  
Impairment charges
                            6  
Corporate relocation charges
                            6  
                                         
Total operating costs and expenses
    4,185       2,207       124       1,854       2,193  
                                         
Operating Income
  $ 1,438     $ 881     $ 17     $ 540     $ 237  
                                         
 
Operating Revenues
 
Total operating revenues were $5,623 million for the year ended December 31, 2006 compared to $2,430 million for the year ended December 31, 2005, an increase of $3,193 million. Energy revenues for the year ended December 31, 2006 increased $1,323 million from $1,870 million to $3,193 million, with 51% contracted compared to 2005 when 14% was contracted. The current year’s results were favorably impacted by the acquisition of Texas Genco LLC, now referred to as the Company’s Texas region, which contributed $3,088 million to operating revenues including $1,726 million of energy revenues, $849 million of capacity revenues and $609 million of contract amortization revenues. In addition, the acquisition of Dynegy’s 50% interest in WCP contributed $141 million to total operating revenues. Excluding the Company’s Texas region, the Hedge Reset transaction and WCP, total operating revenues for the current year decreased by $36 million. Energy revenues, excluding the Texas region and WCP, declined by $475 million, or 25%, as generation demand for the Northeast region’s intermediate and peaking plants declined by 54%, accompanied by a 19% to 23% year over year decline in power prices in the Northeast region’s three major markets. Reduced revenues due to lower generation were partially offset by $446 million in gains from risk management results as such activities swung from last year’s loss of $292 million to a gain of $154 million, primarily due to the decline in settled and forward prices of electricity and natural gas.
 
Capacity revenues for the year ended December 31, 2006 were $1,516 million compared to $563 million for the year ended December 31, 2005, an increase of $953 million. Of this increase, $849 million was related to the Company’s Texas region, primarily from auction sales. In addition, capacity revenues increased $64 million in the West region due to the acquisition of WCP. Increased capacity revenues, reflective of higher capacity prices for the New York Rest of State market, led to a $30 million increase in the Northeast region’s 2006 yearly capacity revenue. The South Central region’s capacity revenues also grew by $9 million as pricing increased due to increased peak demand.


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Risk Management Activity — The following table shows NRG’s risk management activities that do not qualify for hedge accounting treatment for the year ended December 31, 2006.
 
                                         
    Year Ended December 31, 2006  
                South
             
    Texas     Northeast     Central     Other     Total  
    (In millions)  
 
Financial revenues
                                       
Net losses on settled positions, or financial revenues
    (152 )     (10 )     (6 )     (3 )     (171 )
                                         
Subtotal net losses on settled positions, or financial revenues
    (152 )     (10 )     (6 )     (3 )     (171 )
Mark-to-market results
                                       
Reversal of previously recognized unrealized losses on settled positions
          90                   90  
Net unrealized gains on open positions related to economic hedges
    122       50                   172  
Net unrealized gains on open positions related to trading activity
            14       19             33  
                                         
Subtotal mark-to-market results
    122       154       19             295  
Total derivative gain/(losses)
  $ (30 )   $ 144     $ 13     $ (3 )   $ 124  
                                         
 
Risk management activities that do not qualify for hedge accounting treatment resulted in a total derivative gain of approximately $124 million for the year ended December 31, 2006 compared to a $292 million loss for the year ended December 31, 2005. For the year ended December 31, 2006, these losses were comprised of $171 million in settled financial revenue losses and $295 million of mark-to-market gains. The $171 million loss in financial revenues represents the settled value for financial instruments that do not qualify for hedge accounting treatment and were primarily related to $152 million in losses of gas swaps acquired with the purchase of Texas Genco LLC. Of the $295 million in mark-to-market gains, $172 million represents the change in the fair value of forward sales of electricity and fuel, including $28 million of hedge accounting ineffectiveness related to hedge contracts in the Company’s Texas region due to a decline in the correlation between natural gas and power prices. In addition, $90 million of the $295 million mark-to-market gains represents the reversal of mark-to-market losses, which ultimately settled as financial revenues. NRG also recognized a $33 million gain associated with the Company’s trading activity.
 
Since NRG’s risk management activities are intended to mitigate the risk of commodity price movements on revenues and cost of energy sold, the changes in these results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on energy revenues (which are recorded net of financial instrument hedges that qualify for hedge accounting treatment) and costs of energy. In late 2005 and in 2006, NRG hedged a portion of the Company’s 2006 and 2007 Northeast region’s generation. Since that time, the settled and forward prices of electricity have decreased, resulting in the recognition of mark-to-market forward sales and the settlement of such positions at reduced losses.
 
Hedge Reset
 
In November 2006, NRG executed a series of transactions designed to both extend and strengthen the Company’s baseload hedging positions and to enable further optimization of the Company’s ongoing Capital Allocation Program. It involved net settling legacy Texas region long-term power contracts and gas swaps by negotiating prices to current market levels with certain counterparties. This resulted in the accelerated amortization of approximately $1,073 million of out-of-market power contracts and $145 million of gas swaps derivative liability offset by a payment of approximately $1,347 million to the counterparties, for a net reduction of approximately $129 million in the Company’s total operating revenues. In addition, as part of NRG’s Hedge Reset transactions, the Company recorded $6 million of costs related to the transaction.


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Cost of Operations
 
Cost of operations includes cost of energy, operating and maintenance expenses, and non-income tax expenses. For the year ended December 31, 2006, cost of operations was $3,276 million or 58% of total operating revenues compared to $1,838 million, or 76%, of total operating revenues for 2005, an increase of $1,438 million. This increase in absolute terms, but decrease in relative percentage terms, was primarily due to the acquisition of the Company’s Texas region which incurred costs of $1,669 million. Cost of energy which includes fuels, purchased power, and cost contract amortization increased from $1,431 million for 2005 to $2,460 million in 2006. The increase of $1,029 million was primarily due to the Company’s Texas region, which incurred $1,276 million in cost of energy and WCP, which incurred $79 million of energy cost this year, partially offset by lower cost of energy in the Company’s Northeast region. Excluding NRG Texas and WCP, cost of energy decreased by $326 million. This decrease was driven by $254 million in lower cost of energy in the Northeast region, primarily due to $143 million lower oil costs and $101 million in lower gas fuel costs related to lower generation from oil- and gas-fired assets of approximately 70% and 45%, respectively. The South Central region’s cost of energy was $66 million lower in 2006, as higher coal plant availability and increased utilization of the region’s tolling agreements reduced the need to purchase energy to support contract load requirements.
 
Other operating costs increased in 2006 by $410 million to $816 million, $393 million related to the acquisition of NRG Texas and $33 million for WCP. Excluding the impact of NRG Texas and WCP, other operating costs were $16 million lower than last year primarily due to lower operating and maintenance costs, which benefited in the second quarter 2006 from an accrual reversal of $18 million related to a favorable court decision in a station service dispute at NRG’s Western New York plants. In addition, as part of NRG’s Hedge Reset transactions, the Company recorded $6 million of costs related to the transaction.
 
Depreciation and Amortization
 
NRG’s annual depreciation and amortization expense for 2006 and 2005 was $593 million and $162 million, respectively. The Texas region’s depreciation and amortization comprised $413 million of the $431 million year-over-year increase.
 
General, Administrative and Development, or G&A
 
NRG’s G&A costs for 2006 were $316 million compared to $181 million in the previous year. Corporate costs represented $143 million, or 3% of 2006 total operating revenues and $112 million, or 5% of the Company’s 2005 total operating revenues. G&A costs were adversely impacted by $6 million of costs associated with the unsolicited acquisition offer by Mirant Corporation and approximately $14 million of NRG Texas integration costs. The balance of the corporate increase was mainly comprised of increased staffing and administrative costs after the acquisition of Texas Genco LLC. Total G&A costs, excluding WCP and the Company’s Texas region remained flat at $181 million. NRG also incurred approximately $36 million in development expenses in 2006 to support its recently announced Repowering NRG program.
 
Equity in Earnings of Unconsolidated Affiliates
 
Equity earnings from NRG’s investments in unconsolidated affiliates were $60 million for the year ended December 31, 2006, compared to $104 million for the year ended December 31, 2005, a decline of approximately 42%. The decline in earnings was primarily due to the sale of certain non-core assets that were completed during 2006 as well as the Company’s purchase of WCP. NRG’s purchase of the remaining 50% interest in WCP accounted for $21 million of the decline, as the results of WCP were fully consolidated as of March 31, 2006. As part of that transaction, NRG sold its 50% interest in the Rocky Road investment, which accounted for $7 million of the decline in total equity earnings. In addition, NRG’s Enfield investment, which was sold on April 1, 2005, earned $16 million during 2005. Sales of other equity investments in 2006 included James River, Cadillac and certain Latin American power funds. Declines in equity earnings as a result of these sales were partially offset by a $4 million improvement in equity income from the Company’s MIBRAG investment. MIBRAG experienced improved results compared to 2005 as a result of fewer customer outages.


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Write Downs and Gains/(Losses) on Sales of Equity Method Investments
 
During 2006, NRG continued to divest of its non-core assets by selling the Company’s interests in James River and Cadillac, as well as interests in certain Latin American power funds for a pre-tax loss of $6 million, a pre-tax gain of $11 million and a pre-tax gain of $3 million, respectively.
 
For the year ended December 31, 2005, NRG recorded a $31 million loss due to the sale and impairment of certain equity investments. On April 1, 2005, NRG sold its 25% interest in Enfield, resulting in net pre-tax proceeds of $65 million and a pre-tax gain of $12 million. In 2005, NRG also sold its interest in Kendall and recorded a pre-tax gain of approximately $4 million. These gains on sales were offset by approximately $47 million in impairment charges recorded last year. In December 2005, NRG executed an agreement with Dynegy to sell the Company’s 50% interest in Rocky Road LLC in conjunction with NRG’s purchase of Dynegy’s 50% interest in WCP. Based on the terms of the transaction which valued the Company’s investment in Rocky Road at $45 million, NRG impaired its interest in Rocky Road by writing down the value of the investment by approximately $20 million. The sale of Rocky Road closed on March 31, 2006. In 2005, NRG also recorded an impairment of $27 million on its investment in the Saguaro power plant. With the expiration of the plant’s long-term gas supply contract, the Saguaro power plant became exposed to the risk of fluctuating natural gas prices beginning in the second half of 2005, triggering a permanent write down of NRG’s investment value in Saguaro.
 
Other Income, Net
 
Other income increased by $102 million for the year ended December 31, 2006 to $160 million compared to the same period in 2005. Other income in 2006 was favorably impacted by $67 million of income associated with a non-cash settlement with an equipment manufacturer related to turbine purchase agreements entered into in 1999 and 2001, a $13 million non-cash gain associated with the discharge of liabilities upon dissolution of an inactive legal entity, and $5 million from the favorable settlement with respect to post closing adjustments on the acquisition of the Company’s western New York plants in 1998 and 1999. In 2005, NRG recorded an $11 million gain from the settlement related to the Company’s TermoRio project in Brazil and a contingent gain of $4 million related to the sale of a former project, the Crockett Cogeneration Facility, which was sold in 2002. Other income was also favorably impacted in 2006 by $25 million of higher interest income related to higher levels of cash and more efficient management of cash balances.
 
Refinancing Expenses
 
Refinancing expenses incurred in 2006 and 2005 were $187 million and $65 million, respectively. In the first quarter 2006, NRG partially financed the acquisition of Texas Genco LLC through borrowings under new debt facilities and repaid and terminated previous debt facilities. As a result of this financing, the Company incurred $178 million of refinancing expenses: $127 million was related to the premium paid to NRG’s previous debt holders, $34 million for the amortization of the remaining balance of a bridge loan commitment entered into on September 30, 2005, and $31 million related to write-offs of deferred financing costs associated with NRG’s previous debt, and a credit of $14 million related to a debt premium write-off. In 2005, NRG redeemed and purchased a total of approximately $645 million of the Company’s second priority notes. As a result of the redemption and purchases, NRG incurred approximately $54 million in premiums and wri