10-K 1 a2202097z10-k.htm 10-K

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, 2010.

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
(State or other jurisdiction of incorporation or organization)
  41-1724239
(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

     Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share

     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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þ    No o

     Indicate by check mark 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, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer þ

 

Accelerated filer o

 

Non-accelerated filer o
(Do not check if a smaller reporting company)

 

Smaller reporting company o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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 $5,295,318,781 based on the closing sale price of $21.21 as reported on the New York Stock Exchange.

     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 16, 2011
Common Stock, par value $0.01 per share   247,536,568


Documents Incorporated by Reference:

Portions of the Proxy Statement for the 2011 Annual Meeting of Stockholders
are incorporated by reference into Part III of this Form 10-K


TABLE OF CONTENTS

 

GLOSSARY OF TERMS

  3

PART I

  7
 

Item 1 — Business

  7
 

Item 1A — Risk Factors Related to NRG Energy,  Inc. 

  31
 

Item 1B — Unresolved Staff Comments

  44
 

Item 2 — Properties

  45
 

Item 3 — Legal Proceedings

  47
 

Item 4 — Removed and Reserved

  49

PART II

  50
 

Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

  50
 

Item 6 — Selected Financial Data

  53
 

Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations

  55
 

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

  95
 

Item 8 — Financial Statements and Supplementary Data

  99
 

Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

  99
 

Item 9A — Controls and Procedures

  100
 

Item 9B — Other Information

  100

PART III

  101
 

Item 10 — Directors, Executive Officers and Corporate Governance

  101
 

Item 11 — Executive Compensation

  101
 

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  101
 

Item 13 — Certain Relationships and Related Transactions, and Director Independence

  101
 

Item 14 — Principal Accounting Fees and Services

  101

PART IV

  102
 

Item 15 — Exhibits, Financial Statement Schedules

  102

EXHIBIT INDEX

  192

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Glossary of Terms

        When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

AB32

  Assembly Bill 32 — California Global Warming Solutions Act of 2006

ASC

  The FASB Accounting Standards Codification, which the FASB established as the source of authoritative U.S. GAAP

ASU

  Accounting Standards Updates – updates to the ASC

Baseload capacity

  Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year

BACT

  Best Available Control Technology

BTA

  Best Technology Available

BTU

  British Thermal Unit

CAA

  Clean Air Act

CAGR

  Compound annual growth rate

CAIR

  Clean Air Interstate Rule

CAISO

  California Independent System Operator

CATR

  Clean Air Transport Rule

Capital Allocation Plan

  Share repurchase program

Capital Allocation Program

  NRG's plan of allocating capital between debt reduction, reinvestment in the business, and share repurchases through the Capital Allocation Plan

CDWR

  California Department of Water Resources

C&I

  Commercial, industrial and governmental/institutional

CFTC

  U.S. Commodity Futures Trading Commission

CO2

  Carbon dioxide

CPS

  CPS Energy

CS

  Credit Suisse Group

CSF I

  NRG Common Stock Finance I LLC

CSF II

  NRG Common Stock Finance II LLC

CSF Debt

  CSF I and CSF II issued notes and preferred interest, individually referred to as CSF I Debt and CSF II Debt

CSRA

  Credit Sleeve Reimbursement Agreement with Merrill Lynch in connection with acquisition of Reliant Energy, as hereinafter defined

CSRA Amendment

  Amendment of the existing CSRA with Merrill Lynch which became effective October 5, 2009

DNREC

  Delaware Department of Natural Resources and Environmental Control

EPC

  Engineering, Procurement and Construction

ERCOT

  Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas

ESPP

  Employee Stock Purchase Plan

EWG

  Exempt Wholesale Generator

Exchange Act

  The Securities Exchange Act of 1934, as amended

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Expected Baseload Generation

  The net baseload generation limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages)

FCM

  Forward Capacity Market

FERC

  Federal Energy Regulatory Commission

FPA

  Federal Power Act

Fresh Start

  Reporting requirements as defined by ASC-852, Reorganizations

Funded Letter of Credit Facility

  NRG's $1.3 billion term loan-backed fully funded senior secured letter of credit facility, of which $500 million matures on February 1, 2013, and $800 million matures on August 31, 2015, and is a component of NRG's Senior Credit Facility

GenOn

  GenOn Energy, Inc. (formerly RRI Energy, Inc., formerly Reliant Energy, Inc.)

GHG

  Greenhouse Gases

Green Mountain Energy

  Green Mountain Energy Company

GWh

  Gigawatt hour

Heat Rate

  A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWh's generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh

IGCC

  Integrated Gasification Combined Cycle

ISO

  Independent System Operator, also referred to as Regional Transmission Organizations, or RTO

ISO-NE

  ISO New England Inc.

ITISA

  Itiquira Energetica S.A.

kV

  Kilovolts

kW

  Kilowatts

kWh

  Kilowatt-hours

LFRM

  Locational Forward Reserve Market

LIBOR

  London Inter-Bank Offer Rate

LTIP

  Long-Term Incentive Plan

MACT

  Maximum Achievable Control Technology

Mass

  Residential and small business

Merit Order

  A term used for the ranking of power stations in order of ascending marginal cost

MIBRAG

  Mitteldeutsche Braunkohlengesellschaft mbH

MMBtu

  Million British Thermal Units

MW

  Megawatts

MWh

  Saleable megawatt hours net of internal/parasitic load megawatt-hours

MWt

  Megawatts Thermal Equivalent

NAAQS

  National Ambient Air Quality Standards

NEPOOL

  New England Power Pool

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, 2010

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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Net Exposure

  Counterparty credit exposure to NRG, net of collateral

Net Generation

  The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation.

NINA

  Nuclear Innovation North America LLC

NOx

  Nitrogen oxide

NOL

  Net Operating Loss

NPNS

  Normal Purchase Normal Sale

NRC

  U.S. Nuclear Regulatory Commission

NSPS

  Newsource Performance Standards

NSR

  New Source Review

NYISO

  New York Independent System Operator

OCI

  Other comprehensive income

Phase II 316(b) Rule

  A section of the Clean Water Act regulating cooling water intake structures

PJM

  PJM Interconnection, LLC

PJM market

  The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia

PM 2.5

  Particulate matter particles with a diameter of 2.5 micrometers or less

PPA

  Power Purchase Agreement

PSD

  Prevention of Significant Deterioration

PUCT

  Public Utility Commission of Texas

PUHCA of 2005

  Public Utility Holding Company Act of 2005

PURPA

  Public Utility Regulatory Policy Act of 2005

QF

  Qualifying Facility under PURPA

Reliant Energy

  NRG's retail business in Texas purchased on May 1, 2009, from Reliant Energy, Inc. which is now known as GenOn Energy, Inc., or GenOn

Repowering

  Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency

RepoweringNRG

  NRG's program designed to develop, finance, construct and operate new, highly efficient, environmentally responsible capacity

REPS

  Reliant Energy Power Supply, LLC

RERH

  RERH Holding, LLC and its subsidiaries

Revolving Credit Facility

  NRG's $875 million senior secured revolving credit facility, which matures on August 31, 2015, and is a component of NRG's Senior Credit Facility

RGGI

  Regional Greenhouse Gas Initiative

RMR

  Reliability Must-Run

ROIC

  Return on invested capital

Sarbanes-Oxley

  Sarbanes-Oxley Act of 2002, as amended

Schkopau

  Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which NRG has a 41.9% interest

SEC

  United States Securities and Exchange Commission

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Securities Act

  The Securities Act of 1933, as amended

Senior Credit Facility

  NRG's senior secured facility is comprised of a Term Loan Facility, an $875 million Revolving Credit Facility and a $1.3 billion Funded Letter of Credit Facility

SIFMA

  Securities Industry and Financial Markets Association

Senior Notes

  The Company's $6.5 billion outstanding unsecured senior notes consisting of $1.2 billion of 7.25% senior notes due 2014, $2.4 billion of 7.375% senior notes due 2016, $1.1 billion of 7.375% senior notes due 2017, $700 million of 8.5% senior notes due 2019 and $1.1 billion of 8.25% senior notes due 2020

SERC

  Southeastern Electric Reliability Council/Entergy

SO2

  Sulfur dioxide

STP

  South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% Interest

STPNOC

  South Texas Project Nuclear Operating Company

TANE

  Toshiba America Nuclear Energy Corporation

TANE Facility

  NINA's $500 million credit facility with TANE which matures on February 24, 2012

TEPCO

  The Tokyo Electric Power Company of Japan, Inc.

Term Loan Facility

  A senior first priority secured term loan, of which approximately $975 million matures on February 1, 2013 and $1.0 billion matures on August 31, 2015, and is a component of NRG's Senior Credit Facility

Texas Genco

  Texas Genco LLC, now referred to as the Company's Texas Region

Tonnes

  Metric tonnes, which are units of mass or weight in the metric system each equal to 2,205lbs and are the global measurement for GHG

TWh

  Terawatt hour

U.S.

  United States of America

U.S. DOE

  United States Department of Energy

U.S. EPA

  United States Environmental Protection Agency

U.S. GAAP

  Accounting principles generally accepted in the United States

VaR

  Value at Risk

VIE

  Variable Interest Entity

WCP

  WCP (Generation) Holdings, Inc.

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PART I

Item 1 — Business

General

        NRG Energy, Inc., or NRG or the Company, is a primarily wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is engaged in: the ownership, development, construction and operation of power generation facilities; the transacting in and trading of fuel and transportation services; the trading of energy, capacity and related products in the United States and select international markets; and the supply of electricity, energy services, and cleaner energy and carbon offset products to retail electricity customers in deregulated markets through its retail subsidiaries Reliant Energy and Green Mountain Energy.

        As of December 31, 2010, NRG had a total global generation portfolio of 193 active operating fossil fuel and nuclear generation units, at 45 power generation plants, with an aggregate generation capacity of approximately 24,570 MW, as well as ownership interests in renewable facilities with an aggregate generation capacity of 470 MW. NRG's portfolio includes approximately 24,035 MW in the United States and 1,005 MW in Australia and Germany, and approximately 265 MW under construction, which includes partner interests of 120 MW. In addition, NRG has a district energy business that has a steam and chilled water capacity of approximately 1,140 megawatts thermal equivalent, or MWt.

        NRG's principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired, nuclear and renewable facilities, representing approximately 46%, 31%, 16%, 5% and 2% of the Company's total domestic generation capacity, respectively. In addition, 7% of NRG's domestic generating facilities have dual or multiple fuel capacity.

        NRG's domestic generation facilities consist of intermittent, baseload, intermediate and peaking power generation facilities. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company's revenues. In addition, NRG's generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.

        Reliant Energy and Green Mountain Energy arrange for the transmission and delivery of electricity to customers, bill customers, collect payments for electricity sold and maintain call centers to provide customer service. Based on metered locations, as of December 31, 2010, Reliant Energy and Green Mountain Energy combined serve approximately 1.9 million residential, small business, commercial and industrial customers.

        Furthermore, NRG is focused on the development and investment in energy-related new businesses and new technologies where the benefits of such investments represent significant commercial opportunities and create a comparative advantage for the Company. These investments include low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, solar photovoltaic, biomass, gasification, the retrofit of post-combustion carbon capture technologies, and fueling infrastructure for electric vehicle ecosystems.

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NRG's Business Strategy

        NRG's business strategy is intended to maximize shareholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the market's increasing demand for sustainable and low carbon energy solutions. This dual strategy is designed to optimize the Company's core business of competitive power generation and establish the Company as a leading provider of sustainable energy solutions that both promote national energy security and enhance our environment, while utilizing the Company's retail businesses to complement and advance both initiatives.

        The Company's core business is focused on: (i) excellence in safety and operating performance of its existing operating assets; (ii) serving the energy needs of end-use residential, commercial and industrial customers in our core markets; (iii) optimal hedging of baseload generation and retail load operations, while retaining optionality on the Company's gas fleet; (iv) repowering of power generation assets at existing sites and reducing environmental impacts; (v) pursuit of selective acquisitions, joint ventures, divestitures and investments; and (vi) engaging in a proactive capital allocation plan focused on achieving the regular return of and on shareholder capital within the dictates of prudent balance sheet management.

        In addition, the Company believes that it is well-positioned to capture the opportunities arising out of a long-term societal trend towards sustainability as a result of technological developments and new product offerings in "green" energy. The Company's initiatives in this area of future growth are focused on: (i) low carbon baseload — primarily nuclear generation; (ii) renewables, with a concentration in solar and wind generation and development; (iii) fast start, high efficiency gas-fired capacity in the Company's core regions; (iv) electric vehicle ecosystems; and (v) smart grid services. The Company's advances in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in Item 1 — Business, New and On-going Company Initiatives and Development Projects.

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 ownership of multiple plants in various regions, which increases the stability and reliability of its energy supply. Wholesale power generation is a regional 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 with depending on the market.

        The deregulated retail energy business in ERCOT and other similar markets is a highly competitive business. In general, competition in the retail energy business is on the basis of price, service, brand image, product offerings and market perceptions of creditworthiness. Reliant Energy and Green Mountain Energy sell electricity pursuant to a variety of product types, including fixed, indexed and renewable products, and customers elect terms of service typically ranging from one month to five years. Retail energy rates are market-based, and not subject to traditional cost-of-service regulation by the Public Utility Commission of Texas, or PUCT. Non-affiliated transmission and distribution service companies provide, on a non-discriminatory basis, the wires and metering services necessary to access customers.

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Competitive Strengths

        Scale and diversity of assets — NRG has one of the largest and most diversified power generation portfolios in the United States, with approximately 23,565 MW of fossil fuel and nuclear generation capacity in 185 active generating units at 43 plants and 470 MW renewable generation capacity which consists of ownership interests in four wind farms and a solar facility, and less than 5 MW of distributed solar as of December 31, 2010. 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 has a significant power generation presence in major U.S. competitive power markets as set forth in the map below:

GRAPHIC

(1)
Includes 115 MW as part of NRG's Thermal assets. For combined scale, approximately 1,800 MW is dual-fuel capable. Reflects only domestic generation capacity as of December 31, 2010.

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        The Company's U.S. power generation portfolio by dispatch level is comprised of approximately 36% baseload, 38% intermediate, 24% peaking and 2% intermittent units. NRG's U.S. baseload facilities, which consist of approximately 8,545 MW of generation capacity measured as of December 31, 2010, provide the Company with a significant source of cash flow, while its intermediate and peaking facilities, with approximately 15,020 MW of generation capacity as of December 31, 2010, provide NRG with opportunities to capture upside potential that can arise from time to time during periods of high demand. In addition, approximately 7% of the Company's domestic generation facilities have dual or multiple fuel capability, which allows most of these plants to optimize dispatch with the lower cost fuel option.

        The following chart demonstrates the diversification of NRG's U.S. power generation asset portfolio as of December 31, 2010.

GRAPHIC

        Locational advantages — Many of NRG's generation assets are located within densely populated areas that tend to have more robust wholesale pricing as a result of relatively favorable local supply-demand balance. NRG has generation assets located within Houston, New York City, southwestern Connecticut, and the Los Angeles and San Diego load basins. These facilities are often ideally situated for repowering or the addition of new capacity, because their location and existing infrastructure give them significant advantages over undeveloped sites.

        Reliability of future cash flows from hedging and risk management of wholesale and retail — NRG has hedged a portion of its expected baseload generation capacity with decreasing hedge levels through 2015. NRG also has cooperative load contract obligations in the South Central region which expire over various dates through 2025. In addition, as of December 31, 2010, the Company had purchased fuel forward under fixed price contracts, with contractually-specified price escalators, for approximately 43% of its expected baseload coal requirement from 2011 to 2015, including inventory. The Company has the capacity and intent to enter into additional hedges when market conditions are favorable. The Company also has the option of backing NRG's retail load-serving requirements, which may reduce the need to sell and buy power from other financial institutions and intermediaries, resulting in lower transaction costs and credit exposures. This combination of generation and retail allows for a reduction in actual and contingent collateral, initially through offsetting transactions and over time by reducing the need to hedge the retail power supply through third parties. The generation and retail combination also provides stability in cash flows, as changes in commodity prices generally have offsetting impacts between the two businesses. These forward positions, along with the offsetting nature of generation and retail in relation to changes in market prices, provide a 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 favorable market dynamics.

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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, or PPAs, fuel supply contracts, capacity auctions, natural gas swap agreements and other financial instruments. The PPAs that NRG enters into require the Company to deliver MWh of power to its counterparties. In addition, because changes in power prices in the markets where NRG operates are generally correlated to changes in natural gas prices, NRG uses hedging strategies which may include power and natural gas forward sales contracts to manage the commodity price risk primarily associated with the Company's baseload generation assets. The objective of these hedging strategies is to stabilize the cash flow generated by NRG's portfolio of assets.

        The following table summarizes NRG's U.S. baseload capacity and the corresponding revenues and average natural gas prices resulting from baseload hedge agreements extending beyond December 31, 2011, and through 2015:

 
  2011   2012   2013   2014   2015   Annual
Average for
2011-2015
 
 
  (Dollars in millions unless otherwise stated)
 

Net Baseload Capacity (MW) (a)

    8,477     8,450     8,450     8,295     8,295     8,393  

Forecasted Baseload Capacity (MW) (b)

    6,659     6,569     6,554     6,459     6,482     6,545  

Total Baseload Sales (MW) (c)(d)

    6,700     3,310     1,989     803     680     2,697  

Percentage Baseload Capacity Sold Forward (e)

    101 %   50 %   31 %   12 %   10 %   41 %

Total Forward Hedged Revenues (f)(g)

  $ 2,866   $ 1,704   $ 943   $ 326     NM  (h) $ 1,460  

Weighted Average Hedged Price ($ per MWh) (f)

  $ 49   $ 59   $ 54   $ 46     NM  (h) $ 52  

Average Equivalent Natural Gas Price ($ per MMBtu)

  $ 6.10   $ 7.63   $ 7.14   $ 6.41     NM  (h) $ 6.67  
(a)
Nameplate capacity net of station services reflecting unit retirement schedule.
(b)
Forecasted generation dispatch output (MWh) based on forward price curve as of December 31, 2010, which is then divided by 8,760 hours (8,784 hours in 2012) to arrive at MW capacity. The dispatch takes into account planned and unplanned outage assumptions.
(c)
Includes amounts under power sales contracts and natural gas hedges. The forward natural gas quantities are reflected in equivalent MWh based on forward market implied heat rate as of December 31, 2010 and then combined with power sales to arrive at equivalent MWh hedged which is then divided by 8,760 hours (8,784 hours in 2012) to arrive at MW hedged.
(d)
Includes inter-segment sales from the Company's Texas wholesale power generation business to Reliant Energy.
(e)
Percentage hedged is based on total MW sold as power and natural gas converted using the method as described in (c) above divided by the forecasted baseload capacity.
(f)
Represents all North American baseload sales, including energy revenue and demand charges.
(g)
The South Central region's weighted average hedged prices ranges from $40/MWh — $50/MWh. These prices include demand charges and an estimated energy charge.
(h)
NM — Not meaningful, as the transportation component of coal costs is subject to renegotiation with the railroad.

        NRG's retail operations sell electricity on fixed price or indexed products, and these contracts have terms typically ranging from one month to five years. In a typical year, the Company sells approximately 50 TWh of load, but this amount can be affected by weather, economic conditions and competition. The wholesale supply is typically purchased as the load is contracted in order to secure profit margin. The wholesale supply is purchased from a combination of NRG's wholesale portfolio and other third parties, depending on the existing hedge position for the NRG wholesale portfolio at the time.

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    Capacity Revenue Sources

        NRG revenues and free cash flows benefit from capacity/demand payments originating from either market clearing capacity prices, Resource Adequacy, or RA, contracts and tolling arrangements as many of NRG's plants are well situated within load pockets and make critical contributions to system stability. Specifically, in the Northeast, the Company's largest sources for capacity revenues are derived from market capacity auctions in New York, PJM Interconnection, LLC, or PJM, and New England. Previously, New England also derived its capacity revenues from RMR agreements; however, all RMR agreements expired on May 31, 2010. In South Central, NRG earns significant demand payments from its long-term full-requirements load contracts with ten Louisiana distribution cooperatives, which are not unit specific. Of the ten contracts, seven expire in 2025 and account for 56% of the contract load, while the remaining three expire in 2014 and comprise 44% of contract load. Demand payments from these long term contracts are tied to summer peak demand as well as provide a mechanism for recovering a portion of the costs for mandated environmental projects over the remaining life of the contract. In the West, most of the Company's sites benefit from either tolling agreements and/or RA contracts.

        The table below reflects the plants and relevant capacity revenue sources for the Northeast and West regions, as well as the Company's thermal generation facilities:

Region, Market and Facility
  Zone   Sources of
Capacity Revenue:
Market Capacity,
RMR and Tolling
Arrangements

Northeast Region:

       
 

NEPOOL (ISO-NE):

       
   

Devon

  SWCT   LFRM/FCM
   

Connecticut Jet Power

  SWCT   LFRM/FCM
   

GenConn Devon

  SWCT   LFRM/FCM (a)
   

Montville

  CT — ROS   FCM (b)
   

Middletown

  CT — ROS   FCM (b)
   

Norwalk Harbor

  SWCT   FCM (b)
 

PJM:

       
   

Indian River

  PJM — East   DPL — South
   

Vienna

  PJM — East   DPL — South
   

Conemaugh

  PJM — West   PJM — MAAC
   

Keystone

  PJM — West   PJM — MAAC
 

New York (NYISO):

       
   

Oswego

  Zone C   UCAP — ROS
   

Huntley

  Zone A   UCAP — ROS
   

Dunkirk

  Zone A   UCAP — ROS
   

Astoria Gas Turbines

  Zone J   UCAP — NYC
   

Arthur Kill

  Zone J   UCAP — NYC

West Region:

       
 

California (CAISO):

       
   

Blythe

  CAISO   Toll (c)
   

El Segundo Power

  CAISO   RA Capacity (d)
   

Encina

  CAISO   Toll (e)
   

Long Beach

  CAISO   Toll (f)
   

San Diego Combustion Turbines

  CAISO   RA Capacity (g)

Thermal:

       
   

Dover

  PJM — East   DPL — South
   

Paxton Creek

  PJM — West   PJM — MAAC
(a)
GenConn Devon's energy and capacity are sold pursuant to a 30-year cost of service type contract with The Connecticut Light and Power Company, under which FCM revenues received are netted against amounts received.
(b)
RMR agreements expired May 31, 2010, and were replaced by the First Installed Capacity Commitment Period of the FCM effective June 1, 2010. Per the terms of the RMR agreement, any FCM transition capacity payments were offset against approved RMR payments.
(c)
Blythe reached commercial operations on December 18, 2009 under a renewable power purchase and sale agreement that will terminate on December 31, 2029.
(d)
El Segundo includes approximately 335 MW and 596 MW of RA contracts for 2010 and 2011, respectively.
(e)
Toll expires December 31, 2011.
(f)
NRG has purchased back the energy and ancillary service value of the toll through July 31, 2011. Toll expires August 1, 2017.
(g)
RA contracts covering the entire San Diego Combustion Turbines portfolio during 2010 and 2011 (RA contracts for 88 MW run through November 30, 2013).

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    Fuel Supply and Transportation

        NRG's fuel requirements consist primarily of nuclear fuel and various forms of fossil fuel including coal, natural gas and oil. The prices of fossil fuels are highly volatile. The Company obtains its fossil fuels 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. The preceding factors related to the sources and availability of raw materials are fairly uniform across the Company's business segments.

        Coal — The Company is largely hedged for its domestic coal consumption over the next three years. Coal hedging is dynamic and is based on forecasted generation and market volatility. As of December 31, 2010, NRG had purchased forward contracts to provide fuel for approximately 43% of the Company's requirements from 2011 through 2015, including inventory. 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/barge transportation agreements, and rail car lease arrangements. The Company purchased approximately 28 million tons of coal in 2010, of which 97% is Powder River Basin coal.

        The following table shows the percentage of the Company's coal requirements from 2011 through 2015 that have been purchased forward:

 
  Percentage of
Company's
Requirement (a)(b)
 

2011

    84 %

2012

    58 %

2013

    17 %

2014

    17 %

2015

    16 %
(a)
The hedge percentages reflect the current plan for the Jewett mine, which supplies lignite for NRG's Limestone facility. NRG has the contractual ability to change volumes and may do so in the future.
(b)
Does not include coal inventory.

        As of December 31, 2010, NRG had approximately 6,200 privately leased or owned rail cars in the Company's transportation fleet. NRG has entered into rail transportation agreements with varying tenures that provide for substantially all of the Company's rail transportation requirements up to the next three years.

        Natural Gas — NRG operates a fleet of natural gas plants in the Texas, Northeast, South Central and West regions which are primarily comprised of peaking assets that run in times of high power demand. Due to the uncertainty of their dispatch, the fuel needs are managed on a spot basis as the Company does not believe it is prudent to forward purchase natural gas for units the dispatch of which is highly unpredictable. The Company contracts for natural gas storage services as well as natural gas transportation services to ensure delivery of natural gas when needed.

        Nuclear Fuel — South Texas Project's, or STP's, owners satisfy STP's fuel supply requirements by: (i) acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride; (ii) contracting for enrichment of uranium hexafluoride; and (iii) contracting for fabrication of nuclear fuel assemblies. Through its proportionate participation in STPNOC, which is the NRC-licensed operator of STP and responsible for all aspects of fuel procurement, 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 thereafter. Similarly, 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.

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    Seasonality and Price Volatility

        Annual and quarterly operating results of the Company's wholesale power generation segments 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 October, when demand for electricity is generally at its highest in the Company's 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 delivered fuel prices have tended to drive seasonal electricity prices. The preceding factors related to seasonality and price volatility are fairly uniform across the Company's wholesale generation business segments.

        The sale of electric power to retail customers is also a seasonal business with the demand for power generally peaking during the summer months. As a result, net working capital requirements for the Company's retail operations generally increase during summer months along with the higher revenues, and then decline during off-peak months. Weather may impact operating results and extreme weather conditions could materially affect results of operations. The rates charged to retail customers may be impacted by fluctuations in the price of natural gas, transmission constraints, competition, and changes in market heat rates.

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Table of Contents

Regional Segment Review

    Revenues

        The following table contains a summary of NRG's operating revenues by segment for the years ended December 31, 2010, 2009 and 2008, as discussed in Item 15 — Note 18, Segment Reporting, to the Consolidated Financial Statements. Refer to that footnote for additional financial information about NRG's business segments and geographic areas, including a profit measure and total assets. In addition, refer to Item 2 — Properties, for information about facilities in each of NRG's business segments.

 
  Year Ended December 31, 2010  
 
  Energy
Revenues
  Capacity
Revenues
  Retail
Revenues
  Mark-to-
Market
Activities
  Other
Revenues
  Total
Operating
Revenues
 
 
  (In millions)
 

Reliant Energy

  $   $   $ 5,210   $ (1 ) $ (219 ) $ 4,990  

Texas

    2,850     25         91     91     3,057  

Northeast

    726     396         (124 )   27     1,025  

South Central

    387     235         (38 )   24     608  

West

    31     113         (2 )   2     144  

International

    46     71             11     128  

Thermal

                (2 )   145     143  

Corporate and Eliminations (a)(b)

    (1,186 )   (16 )   67     (60 )   (51 )   (1,246 )
                           

Total

  $ 2,854   $ 824   $ 5,277   $ (136 ) $ 30   $ 8,849  
                           
(a)
Energy revenues include inter-segment sales between Texas and both Reliant Energy and Green Mountain Energy.
(b)
Retail revenues include Green Mountain Energy retail revenues of $69 million for the period November 5, 2010, to December 31, 2010.

 
  Year Ended December 31, 2009  
 
  Energy
Revenues
  Capacity
Revenues
  Retail
Revenues
  Mark-to-
Market
Activities
  Other
Revenues
  Total
Operating
Revenues
 
 
  (In millions)
 

Reliant Energy (c)

  $   $   $ 4,440   $   $ (258 ) $ 4,182  

Texas

    2,770     193         (102 )   85     2,946  

Northeast

    873     407         (107 )   28     1,201  

South Central

    367     269         (78 )   23     581  

West

    26     122             2     150  

International

    52     79             13     144  

Thermal

                (2 )   137     135  

Corporate and Eliminations (d)

    (362 )   (47 )       (1 )   23     (387 )
                           

Total

  $ 3,726   $ 1,023   $ 4,440   $ (290 ) $ 53   $ 8,952  
                           
(c)
For the period May 1, 2009, to December 31, 2009.
(d)
Energy revenues include inter-segment sales between Texas and Reliant Energy.

 
  Year Ended December 31, 2008  
 
  Energy
Revenues
  Capacity
Revenues
  Mark-to-
Market
Activities
  Other
Revenues
  Total
Operating
Revenues
 
 
  (In millions)
 

Texas

  $ 2,775   $ 493   $ 413   $ 345   $ 4,026  

Northeast

    1,076     406     82     66     1,630  

South Central

    462     233     26     25     746  

West

    39     125         7     171  

International

    56     86         16     158  

Thermal

            4     150     154  

Corporate and Eliminations

                     
                       

Total

  $ 4,408   $ 1,343   $ 525   $ 609   $ 6,885  
                       

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    Operational Statistics

        The following are industry statistics defined by the North American Electric Reliability Council, or NERC, and are more fully described below:

        Annual Equivalent Availability Factor, or EAF — Measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account.

        Net heat rate — The net heat rate for the Company's fossil-fired power plants represents the total amount of fuel in BTU required to generate one net kWh provided.

        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.

        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, 2010, and 2009:

 
  Year Ended December 31, 2010  
 
  Net Owned
Capacity (MW)
  Net
Generation
(MWh)
  Annual
Equivalent
Availability
Factor
  Average Net
Heat Rate
BTU/kWh
  Net Capacity
Factor
 
 
  (In thousands of MWh)
 

Texas (a)

    10,745     44,700     89.6 %   10,300     48.1 %

Northeast (b)

    6,900     9,355     88.3     11,000     14.1  

South Central (c)

    4,125     11,168     91.3     10,500     41.9  

West

    2,150     571     89.7     11,800     4.8  

 

 
  Year Ended December 31, 2009  
 
  Net Owned
Capacity (MW)
  Net
Generation
(MWh)
  Annual
Equivalent
Availability
Factor
  Average Net
Heat Rate
BTU/kWh
  Net Capacity
Factor
 
 
  (In thousands of MWh)
 

Texas (a)

    11,340     44,993     88.2 %   10,200     46.4 %

Northeast (b)

    7,015     9,220     89.2     10,900     13.5  

South Central

    2,855     10,398     89.6     10,500     41.1  

West

    2,150     1,279     86.5     12,300     8.2  
(a)
Net generation (MWh) does not include Sherbino I Wind Farm LLC, which is accounted for under the equity method.
(b)
Factor data and heat rate do not include the Keystone and Conemaugh facilities.
(c)
Includes Cottonwood for the period November 15, 2010 (acquisition date) to December 31, 2010.

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        The generation performance by fuel-type for the recent three-year period is as shown below:

 
  Net Generation  
 
  2010   2009   2008  
 
  (In thousands of MWh)
 

Texas

                   

Coal

    29,633     30,023     32,825  

Gas (a)

    4,794     5,224     4,647  

Nuclear (b)

    9,295     9,396     9,456  

Wind

    978     350     9  
               
 

Total Texas

    44,700     44,993     46,937  
               

Northeast

                   

Coal

    7,905     7,945     11,506  

Oil

    103     134     349  

Gas

    1,347     1,141     1,494  
               
 

Total Northeast

    9,355     9,220     13,349  
               

South Central

                   

Coal

    10,778     10,235     10,912  

Gas

    390     163     236  
               
 

Total South Central

    11,168     10,398     11,148  
               

West

                   

Gas

    519     385     362  

Solar

    52     1      
               
 

Total West

    571     386     362  
               
(a)
MWh information reflects the undivided interest in total MWh generation from Cedar Bayou 4 beginning June 2009.
(b)
MWh information reflects the undivided interest in total MWh generated by STP.

    Market Framework

    Texas

        NRG's largest wholesale power generation business segment is located in Texas in the physical control areas of the Electric Reliability Council of Texas, or ERCOT, market. In addition, Reliant Energy and Green Mountain Energy activities in Texas are subject to standards and regulations adopted by the PUCT and ERCOT. In the ERCOT market, NRG's retail businesses are certified by the PUCT as Retail Electric Providers, or REPs, to contract with end-users to sell electricity and provide other value-enhancing services. In addition, NRG's retail businesses contract with transmission and distribution service providers, or TDSPs, to arrange for transportation to the customer.

        The ERCOT market is one of the nation's largest and historically fastest growing power markets. For 2010, hourly demand ranged from a low of 21,770 MW to a high of 65,776 MW, with installed generation capacity of approximately 80,000 MW (23,840 MW from coal, lignite and nuclear plants, 47,040 MW from gas, and 9,120 MW from wind). The ERCOT market has limited interconnections compared to other markets in the United States.

        In November 2010, the ERCOT board of directors approved a new target equilibrium reserve margin level of 13.75%. The reserve margin for 2010 was forecast to be 21.4% in ERCOT's May 2010 Capacity, Demand and Reserve Report, or CDR. The latest CDR, published in December 2010, forecasts a reserve margin level of 15.94% for 2011. There are currently plans being implemented by the PUCT to build a significant amount of transmission from west Texas and continuing across the state to enable wind generation to reach load. The ultimate impact on the reserve margin and wholesale dynamics from these plans are unknown.

        Prior to December 1, 2010, the ERCOT market was divided into four regions or congestion zones, namely: North, Houston, South and West, which reflected transmission constraints that were commercially significant and which had limits as to the amount of power that could flow across the zonal boundaries. However, on December 1, 2010, in compliance with a rule adopted by the PUCT, ERCOT replaced the zonal wholesale market design with a nodal market design that is based on Location Marginal Prices, or LMPs. The new nodal market also includes, among other design changes, a financially binding day-ahead energy and ancillary services market administered by ERCOT. The nodal market design is expected to result in improved dispatch of generation resources, more efficient management of transmission congestion, and an improved ability to integrate increased quantities of intermittent resources, such as wind and solar generating resources. Transmission congestion costs in the nodal market are directly assigned to the parties causing the congestion.

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Table of Contents

    Northeast

        NRG's second largest asset base is located in the Northeast region of the United States with generation assets 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. Although each of the three Northeast Independent Systems Operators, or 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 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 time-frame is a financially firm, day-ahead unit commitment market. The second time-frame is a 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.

    South Central

        NRG's South Central region operates primarily in the Southeastern Electric Reliability Council/Entergy, or SERC-Entergy, region, which is a bilateral market without a regional transmission organization, or RTO. In the South Central region, all power sales and purchases are consummated bilaterally between individual counterparties. Transacting counterparties are required to procure transmission service from the relevant transmission owners at their FERC-approved tariff rates. In this market structure, NRG is able to provide balancing authority services in addition to wholesale power that allows NRG to provide full requirement services to load-serving entities, thus making NRG a competitive alternative to the integrated utilities operating in the region. NRG operates four Balancing Authorities including the LAGN Balancing Authority which encompasses the generating facilities and the Company's cooperative load.

    West

        Except for the Saguaro facility, NRG's generation assets in the West region operate within the balancing authority of California Independent System Operator, or CAISO. CAISO's current market allows NRG's CAISO assets to serve multiple load serving entities, or LSEs, and operates a nodal balancing market and congestion clearing mechanism. CAISO also has a locational capacity requirement, which requires LSEs to supply a significant portion of load from defined local reliability areas. All of NRG's CAISO assets are in the Los Angeles or San Diego local reliability areas. CAISO's new market, known as Market Redesign and Technology Upgrade, or MRTU, became operational on April 1, 2009. MRTU established a day-ahead market for energy and ancillary services and settles prices locationally. NRG's CAISO assets are all peaking and intermediate in nature and are well positioned to capitalize on the higher locational prices that may result from LMPs in location constrained areas and will continue to satisfy local distribution company capacity requirements. Longer term, NRG's California portfolio's locational advantage may be impacted by new transmission, which may affect load pocket procurement requirements. So far, however, the impacts of increasing demand and need for flexible cycling capability combined with delays in the online date of new transmission have muted the impact of this long-term threat.

        California's resource mix will be significantly shaped in the years ahead by California's renewable portfolio standard and its greenhouse gas reduction rules. In particular, the state's renewable portfolio standard is currently set at 20% for 2010 and the Governor, by Executive Order, has directed that the standard be increased to 33% by 2020. This increase is expected to create greater demand for low emission resources. The intermittent and remote nature of most renewable resources will create a strong demand for flexible load pocket resources. NRG's California portfolio may also be impacted by legislation and by any mechanism, such as cap-and-trade, that places a price on incremental carbon emissions. NRG's expectation is that the emission costs will be reflected in the market price of power and that the net cost to the Company's existing portfolio of intermediate and peaking resources will be manageable.

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Table of Contents

New and On-going Company Initiatives and Development Projects

        NRG has a comprehensive set of initiatives and development projects that supports its strategy focused on: (i) excellence in safety and enhanced operating performance; (ii) earning a margin by selling electricity to end-use customers; (iii) repowering of power generation assets at existing sites and development of new power generation projects; (iv) empowering retail customers with distinctive products and services; (v) engaging in a proactive capital allocation plan; and (vi) pursuing selective acquisitions, joint ventures, divestitures and investment in new energy-related businesses and new technologies in order to enhance the Company's asset mix and combat climate change.

FORNRG Update

        The FORNRG 2.0 program seeks to increase the Company's ROIC 100 basis points by 2012, tracked as increases in cash flow. ROIC improvements are measured by benchmarking project benefits against the Company's 2008 financial results; plant performance calculations are based on historical baselines.

        The 2010 FORNRG goal is a 65 basis point improvement, which corresponds to approximately $98 million in cash flows. This goal includes recurring benefits created in 2009 and new project benefits created in 2010. As of December 31, 2010, the Company has delivered an 80 basis point improvement in ROIC, which is equivalent to approximately $119 million in cash flows.

        Given the consistent success of the program and new 2011 projects, NRG anticipates concluding the FORNRG 2.0 program, as currently configured, in 2011 by achieving the program goal of 100 basis points.

RepoweringNRG Update

        NRG has several projects in varying stages of development. The Company's development projects are generally subject to certain conditions, milestones, and other factors that may result in the Company's decision to no longer pursue the development of these projects. The Company also seeks to expand its portfolio through selective acquisitions.

Conventional Power Development and Acquisitions

    Projects Under Construction

        The Company's El Segundo Energy Center LLC, or ESEC, has begun demolition work at its El Segundo Power Generating Station in El Segundo, California in order to construct a 550 MW fast start, gas turbine combined cycle generating facility. The new units, which will replace El Segundo Power Units 1 & 2, are being constructed pursuant to a 10 year, 550 MW PPA with Southern California Edison Company, or SCE. The Company received the final air permit by the South Coast Air Quality Management District, or SCAQMD, on July 13, 2010. The Company expects a commercial operation date of August 1, 2013.

        GenConn, a 50/50 joint venture of NRG and The United Illuminating Company, or United Illuminating, was formed to construct, own and operate two 200 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. Each of these facilities is being constructed pursuant to 30-year cost of service type contracts with The Connecticut Light & Power Company. All four units at the GenConn Devon facility were released to the ISO-NE by July 2010. The Middletown project, which is fully permitted, is in the advanced stages of construction, with a target commercial operation date of June 1, 2011.

        NRG is in the advanced stages of construction for a combined heat and power system at the University Medical Center of Princeton. This facility will include the production of electricity, steam and chilled water, achieved by means of a thermal energy storage system, pursuant to a 13-year agreement with the hospital. Full commercial operations are expected by the first quarter of 2012.

    Acquisitions

        Northwind Phoenix, LLC — On June 22, 2010, NRG, through NRG Thermal, acquired Northwind Phoenix, which owns and operates a district cooling system in Phoenix and provides chilled water, steam and electricity in metropolitan Tucson and to portions of Arizona State University. For further discussion see Item 15 — Note 3, Business Acquisitions, to the Consolidated Financial Statements.

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Table of Contents

        Cottonwood — On November 15, 2010, NRG acquired Cottonwood, a 1,265 MW combined cycle natural gas plant in the Entergy zone of East Texas. Cottonwood, one of the newest and most efficient plants in the region, will strengthen NRG's regional and dispatch diversity by greatly expanding the Company's load following mid-merit generation profile while lowering the overall carbon intensity of NRG's fleet. Prior to its acquisition, NRG contracted with Cottonwood to support current long-term contracts in Louisiana, Arkansas and East Texas. Owning Cottonwood should enable NRG to realize future contracting opportunities and will provide additional balancing and ancillary services. For further discussion see Item 15 — Note 3, Business Acquisitions, to the Consolidated Financial Statements.

    Nuclear Innovation North America

        NINA, a majority-owned subsidiary of NRG, is focused on marketing, siting, developing, financing and investing in new advanced design nuclear projects in select markets across North America, including the planned STP Units 3 and 4 Project. Toshiba American Nuclear Energy Corporation, or TANE, a wholly-owned subsidiary of Toshiba Corporation, is the minority owner of NINA. The total rated capacity of STP Units 3 and 4 would be approximately 3,000 MW, subject to NRC approval. NINA is a bankruptcy remote entity under NRG's corporate structure and designated as an Excluded Project Subsidiary under NRG's senior credit facilities and senior unsecured notes, which require that NRG not be obligated to contribute any capital to service NINA's debt or fund the repayment of any NINA debt in the event of a default. Furthermore, NRG is not required to continue the funding of NINA and any capital distributed to NINA from NRG is in the form of equity contributions, thus the termination of any such capital distributions to NINA could result in the dilution of NRG's equity interest.

        The STP Units 3 and 4 Project is currently in the final stages of the U.S. Department of Energy, or U.S. DOE, loan guarantee program process. However, NINA and NRG cannot accurately predict at this time as to timing, certainty, or terms and conditions of a conditional commitment award from the U.S. DOE. In early 2010, NRG announced that if the STP Units 3 and 4 Project did not receive a loan guarantee from the U.S. DOE in a timely fashion, it was the intention of the Company both to reduce substantially its commitment to fund on-going project expenditures as well as to reduce development spending on the project overall while the outcome of the loan guarantee was uncertain. When the loan guarantee was not received by summer 2010, NRG, after consultation with its partners, dramatically reduced its ongoing equity contributions into NINA for project development, but did so in a manner that allowed the project to stay on its current schedule. It is anticipated that during the third quarter 2011, NRG, in consultation with project partners, will make an assessment of project viability and each partner's willingness to continue to pursue the project and fund the project's development. NRG's assessment of project viability, in particular, will depend upon receipt of the conditional federal loan guarantee and our assessment of the project's ability to satisfy the conditions to that loan guarantee, particularly the status of long-term PPAs for the project. A negative assessment will likely lead to NRG's cessation of ongoing project funding activities. In that circumstance, the impact on the project's further development and future prospects will depend upon the other project partners' assessment of project viability. Should NRG or any of its partners withdraw support from the project, this would result in a reassessment of the probability of success of the project and a potential impairment and permanent write-down of some or all of the value of the capitalized assets for STP Units 3 and 4. Through December 31, 2010, NRG has made equity contributions of $319 million into NINA. NINA has capitalized $791 million of construction-in-progress, of which $317 million was funded by Toshiba equity contributions and the Shaw and TANE Facilities, and $161 million in its accounts payable balance.

        In March 2010, an agreement was reached with CPS for NINA to acquire a controlling interest in the STP Units 3 and 4 Project through a settlement of the litigation between the parties. For further discussion, see Item 15 — Note 22, Commitments and Contingencies, to the Consolidated Financial Statements.

        In April 2010, NINA announced an agreement for the Building and Construction Trades Department, or BCTD, of the AFL-CIO to provide skilled union labor to construct STP Units 3 and 4. The BCTD is an alliance of 13 national and international unions that collectively represent over two million skilled craft professionals in the United States and Canada.

        In May 2010, NINA and Tokyo Electric Power Company of Japan, or TEPCO, signed an Investment and Option Agreement whereby TEPCO agreed to acquire up to a 20% interest in NINA Investments Holdings LLC. For further discussion, see Item 15 — Note 22, Commitments and Contingencies, to the Consolidated Financial Statements.

        On November 29, 2010, NINA awarded the EPC contract for the STP Units 3 and 4 Project to a restructured EPC consortium, or the Consortium, formed by TANE and The Shaw Group Inc., or Shaw. In connection with this amended EPC agreement, NINA expects to update, in 2011, its previously announced estimates of EPC cost, owners' costs and financing costs including the projected timing of these expenditures. As part of the negotiations around the Amended and Restated EPC Agreement, NINA amended and restated the TANE Credit Facility in order to allow for the payment of services beyond purchases of long lead materials and equipment, as well as enter into incremental financing agreements that will provide for additional funds to cover project costs.

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Table of Contents

Renewable Development and Acquisitions

        As part of its core strategy, NRG intends to invest significantly in the development and acquisition of renewable energy projects, including wind, solar and biomass. NRG's renewable strategy is intended to capitalize on first mover advantage in a high growth segment of NRG's business, the Company's existing regional presence in regions with attractive renewable resources and the prevalence, in the Company's core markets, of state-mandated renewable portfolio standards. As a result, a brief description of the Company's development efforts with respect to each renewable technology follows.

    Green Mountain Energy Acquisition

        On November 5, 2010, NRG acquired Austin-based Green Mountain Energy, the nation's leading competitive provider of cleaner energy and carbon offset products, which has residential and commercial customers primarily in Texas and the New York metropolitan region. Green Mountain Energy also delivers renewable products and services to a public utility in Oregon, as well as utility programs in New York and New Jersey. Green Mountain Energy will be managed and operated as a distinct retail business within NRG. Green Mountain continues to expand its market share in Texas, where it has operated for over nine years, and New York, where it launched just over a year ago. Green Mountain Energy has applied for licenses to sell electricity in New Jersey, and is continually evaluating new market opportunities. For further discussion, see Item 15 — Note 3, Business Acquisitions, to the Consolidated Financial Statements.

    Solar

        NRG has acquired and is developing a number of solar projects utilizing photovoltaic, or PV, as well as solar thermal technologies. Specifically, NRG has projects that have entered into off-take arrangements with Southern California Edison, Pacific Gas & Electric, El Paso Electric Co. and Tucson Electric Power, each of which will utilize either PV or solar thermal technology. The development of each of these projects is subject to certain regulatory approvals, conditions and milestones which may affect the Company's decision to pursue further development of one or more of these projects.

        The following table is a brief summary of the major solar projects that the Company (i) currently owns and is developing or (ii) has entered into an agreement with the project sponsor wherein the Company will have a right to own and develop the project.

NRG Owned Projects
  Location   PPA   MW (a)   Expected COD   Status
 

Avenal

  Kings County, CA   20 year     45     2011   Under Construction
 

Roadrunner

  Santa Teresa, NM   20 year     20     2011   Under Construction

Projects Under Agreement

                       
 

Ivanpah

  Ivanpah, CA   20-25 year     392     2013   Under Construction
 

Agua Caliente

  Yuma County, AZ   25 year     290     2012-2014   Under Construction
 

CVSR

  San Luis Obispo, CA   25 year     250     2011-2013   Pre Construction
(a)
Represents total project size.

        Below is a further description of these projects:

        Avenal — In September 2010, the Company together with Eurus Energy America announced a 50/50 joint venture in which Eurus will build a PV generating facility in California, with a capacity of 45 MW. The project is composed of three sites — Avenal Park (6 MW), Sun City (20 MW) and Sand Drag (19 MW) — all located in Kings County, California. The venture has secured construction financing on all three sites, and has given full notice to proceed to an engineering, procurement and contracting firm, with anticipated commercial operation in mid-2011. The California Public Utilities Commission has approved a 20-year Avenal Park PPA with Pacific Gas & Electric.

        Roadrunner — In the fourth quarter of 2010, NRG broke ground on the Company's first generation site in New Mexico, a 20 MW PV solar facility. Power generated from the project will be sold to El Paso Electric Co. under a 20-year PPA, which has been approved by the New Mexico Public Regulation Commission. The project will be built on a 210-acre privately owned parcel of industrial-zoned land near Santa Teresa, New Mexico, about 10 miles from El Paso, Texas. When completed by year end 2011, the New Mexico Solar Project will be one of the first large-scale solar projects built in New Mexico.

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        Ivanpah — On October 27, 2010, the Company executed a Letter of Intent to partner with BrightSource Energy, Inc., or BSE, to construct, finance and operate the largest solar thermal technology project in the world, the 392 MW Ivanpah Solar Electric Generating System in southeastern California's Mohave Desert, or the Ivanpah Project. NRG plans to become the lead investor in Ivanpah, investing up to $300 million in the Ivanpah Project over the next three years. The investment is subject to definitive documentation (including the satisfaction of several conditions precedent), which is anticipated to be executed by the end of first quarter 2011. The Ivanpah Project is composed of three separate facilities — Ivanpah 1 (126 MW), Ivanpah 2 (133 MW), and Ivanpah 3 (133 MW), and all three facilities are expected to be fully operational by the end of 2013. The Ivanpah Project has received a $1.375 billion conditional commitment from the U.S. DOE for a loan guarantee, and has obtained all necessary permits and approvals. Power generated from the Ivanpah Project will be sold to Southern California Edison and Pacific Gas & Electric, under multiple 20-25 year PPAs, each of which have been approved by the California Public Utilities Commission. Ivanpah is located approximately 50 miles northwest of Needles, California, about five miles from the Nevada border on federal land managed by the U.S. Department of Interior's Bureau of Land Management.

        Agua Caliente — On December 14, 2010, the Company and First Solar, Inc. announced that the Company has agreed to acquire a 290 MW PV solar project, Agua Caliente, from First Solar. The project is scheduled to be completed by 2014 and has a 25-year power purchase agreement with Pacific Gas & Electric, which has been approved by the California Public Utilities Commission. Closing of the acquisition is contingent on receiving a federal loan guarantee from the U.S. DOE which is anticipated by end of first quarter 2011. On January 20, 2011, the U.S. DOE announced the offer of a conditional commitment to Agua Caliente for a loan guarantee of up to $967 million. NRG plans to invest up to $800 million in the project through 2014. The Agua Caliente project is located in Arizona between Yuma and Phoenix and, upon completion, is expected to be the largest operational PV site in the world.

        CVSR — On November 30, 2010, the Company and SunPower Corp., or SunPower, announced an agreement to build the 250 MW California Valley Solar Ranch, or CVSR, in San Luis Obispo County. Under the agreement, NRG will assume all ownership and financing responsibilities for CVSR, while SunPower will continue to develop the project, and will build, operate and maintain the facility. NRG anticipates closing the transaction by end of the third quarter of 2011. The project is on track to begin partial operations by the end of 2011. Power from CVSR will be sold to Pacific Gas & Electric under 25-year PPAs which have been approved by the California Public Utilities Commission. The project is currently seeking a loan guarantee from the U.S. DOE. The U.S. DOE has provided a draft term sheet for the project, which is a significant milestone in the process leading to a conditional loan guarantee commitment. Subject to final total project cost and further negotiation of financing terms and conditions, the Company plans to invest up to $450 million in the project over the next four years. Construction is expected to begin in the third quarter of 2011, contingent on a number of factors, including the receipt of all applicable permits.

        Solar Development Pipeline — Consistent with its business strategy, NRG is currently focused on early stage development efforts in a number of markets as well as conducting due diligence with respect to various equity investment opportunities for solar projects utilizing solar technologies that range from concentrated solar thermal to PV. In June 2010, NRG acquired a pipeline of solar development projects from US Solar Ventures, an affiliate of Arclight Capital Partners, LLC. These development projects total 720 MW and range in size from 20 MW to 99 MW, and have the potential to be operational between 2011 and 2014. In addition to the US Solar Ventures projects, the Company has an additional pipeline of solar development projects that total approximately 320 MWs. These projects have site control and interconnection rights and are in various stages of development, with expected commercial operation dates that range between 2012 and 2014.

        Distributed solar — NRG's efforts to date have focused on larger (by renewable standards) "utility" sized solar projects. However, in September 2010, the Company announced its involvement in smaller scale "distributed" solar in Arizona. As a first stage of the program, NRG is building solar pavilions at four separate school districts in the areas of Phoenix and Tucson. The solar cells on these pavilions will collectively generate more than 2.5 MW of power. By January 2011, three of the school district projects achieved commercial operations.

    Wind

        Terrestrial Wind

        On June 14, 2010, NRG acquired South Trent Wind LLC, owner of the South Trent wind farm, or South Trent, a 100 MW wind farm near Sweetwater, Texas. For further discussion, see Item 15 — Note 3, Business Acquisitions, to the Consolidated Financial Statements.

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        Offshore Wind

        NRG Bluewater Holdings LLC, or NRG Bluewater, plans to build its Mid-Atlantic Wind Park on the Outer Continental Shelf, or OCS, off the coast of Delaware. On November 8, 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, notified NRG Bluewater that it was qualified to hold a lease for wind energy generation on the OCS.

        On September 7, 2010, the Delaware Public Service Commission approved NRG Bluewater's amended PPA with Delmarva Power & Light Company, which extended certain deadline and milestone dates by an additional two years, including revising the initial commercial operation date to December 1, 2016.

    Biomass

        In April 2010, the Company was awarded a 10-year contract from the New York State Energy Research and Development Authority for power generated using renewable biomass fuel at its Dunkirk Generating Station in western New York. The project will produce up to 15 MW of the station's total output by co-firing with clean wood biomass. In addition to the Dunkirk project, NRG has a biomass project under development at its Montville Generating Station. The project, which has received siting approval and an air permit, would involve the repowering one of the facility's existing units to produce up to 40 MW of electricity from locally sourced biomass.

Retail Growth Initiatives

        Reliant Energy is continuing its development efforts in smart energy by enhancing the products and services that provide energy usage insights, choices and convenience, and increasing the scale at which Reliant Energy can offer these services. Reliant Energy continues to lead the Texas market at delivering the benefits of the smart grid to its residential customers by offering six unique products and having over 170,000 customers enrolled on smart energy products.

        In an effort to leverage NRG's physical assets in the Northeast and Reliant Energy's relationships with national accounts that it has gained through its number one position in ERCOT C&I sales, Reliant Energy has expanded its C&I sales operations to include Pennsylvania, New Jersey, Maryland, Delaware and Washington, DC.

Electric Vehicle Development

        In 2009, NRG began development of a services business to support the large-scale deployment of electric vehicles, or EVs, in Texas. NRG's EV Services, LLC has already started offering a range of integrated products and services that enable both public and home charging of EVs in the Houston ecosystem and has announced the launch of its business offerings in the Dallas-Ft. Worth market.

        On November 18, 2010, NRG announced the nation's first privately funded, comprehensive EV ecosystem in Houston, the start of a rollout across Texas in 2011. Under the brand name eVgo, NRG provides EV owners throughout the greater Houston area with convenient and affordable fueling packages. NRG plans to invest approximately $10 million in Houston's EV ecosystem, and will be the first company to equip an entire major market with the privately funded infrastructure needed for successful EV adoption and integration.

Carbon Capture Sequestration Project

        On March 9, 2010, NRG was selected by the U.S. DOE to negotiate to receive up to $167 million, including funding from the American Recovery and Reinvestment Act, to build a 60 MW post-combustion carbon capture demonstration unit at NRG's WA Parish plant southwest of Houston with use of the captured carbon in enhanced oil recovery in adjacent oil fields. Construction would begin in late 2012 with commercial operations anticipated in the fourth quarter of 2014.

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Regulatory Matters

        As operators of power plants and participants in wholesale energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, and PUCT as well as other public utility commissions in certain states where NRG's generating or thermal assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which it participates. Certain of the retail entities are competitive Retail Electric Providers, or REPs, and as such are subject to the rules and regulations of the PUCT governing REPs, as well as other states where NRG is licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by the North American Electric Reliability Corporation, or NERC, and the regional reliability entities in the regions where the Company operates.

        The operations of, and wholesale electric sales from, NRG's Texas region are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. 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

        The 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. On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which, among other things, aims to improve transparency and accountability in derivative markets. The Dodd-Frank Act increases the CFTC's regulatory authority over over-the-counter derivatives, market clearing, position reporting, and capital requirements. While there are many details that remain to be addressed in CFTC rulemaking proceedings, at this time the Company does not anticipate any material impact on its current operations or collateral requirements.

    Federal Energy Regulatory Commission

        The 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, the 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. The 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 qualifies as a QF, or the subsidiary owning the facility qualifies as an EWG.

        Federal Power Act — The FPA gives the FERC exclusive rate-making jurisdiction over the wholesale sale of electricity and transmission of electricity in interstate commerce. Under the FPA, the FERC, with certain exceptions, regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as public utilities.

        Public utilities are required to obtain the 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 entities make sales of electricity pursuant to market-based rates, as opposed to traditional cost-of-service regulated rates. Every three years FERC conducts a review of the Company's market based rates and potential market power on a regional basis. On April 27, 2009, July 21, 2009, and November 3, 2010, FERC accepted the Company's updated market power analyses for its Northeast, Southeast, and Southwest assets, respectively. NRG's next such market power update filing is due June 30, 2011, for its Northeast assets.

        The FPA also gives the FERC jurisdiction to review certain transactions and numerous other activities of public utilities. Section 203 of the FPA requires the FERC's prior approval for the transfer of control of assets subject to the FERC's jurisdiction. Section 204 of the FPA gives the FERC jurisdiction over a public utility's issuance of securities or assumption of liabilities. However, the FERC typically grants blanket approval for future securities issuances and the assumption of liabilities to entities with market-based rate authority.

        In accordance with the Energy Policy Act of 2005, or EPAct of 2005, the FERC has approved the NERC as the national Energy Reliability Organization, or ERO. As the ERO, NERC is responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. In addition to complying with NERC requirements, each NRG entity must comply with the requirements of the regional reliability entity for the region in which it is located.

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        Public Utility Holding Company Act of 2005 — PUHCA of 2005 provides the 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, it is exempt from the accounting, record retention, and reporting requirements of the PUHCA of 2005.

        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 the FERC is primarily charged with administering PURPA as it applies to QFs. Certain QFs are exempt from regulation under the FPA as public utilities.

    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 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 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, 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. See also Item 15 — Note 7, Nuclear Decommissioning Trust Fund, to the Consolidated Financial Statements for additional discussion.

        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, those excesses will be refunded to the respective rate payers of CenterPoint or AEP, or their successors.

    Public Utility Commission of Texas, or PUCT

        The Company's Texas generation subsidiaries are registered as power generation companies with the PUCT. The PUCT also has jurisdiction over power generation companies with regard to their sales in the wholesale markets, the implementation of measures to address undue market power or price volatility, and the administration of nuclear decommissioning trusts. The PUCT exercises its jurisdiction both directly, and indirectly, through its oversight of the ERCOT, the regional transmission organization. Certain of the Company's subsidiaries within the Texas region are also subject to regulatory oversight as a power marketer or as a Qualified Scheduling Entity. NRG Power Marketing, LLC, or PML, 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 the ERCOT. Certain of the Company's retail entities are competitive REPs, and as such are subject to the rules and regulations of the PUCT governing REPs.

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    New York State Public Service Commission, or NYSPSC

        The Company's NYSPSC generation subsidiaries are electric corporations subject to "lightened" regulation by the NYSPSC. As such, the NYSPSC exercises its jurisdictional authority over certain non-rate aspects of the facilities, including safety, retirements, and the issuance of debt secured by recourse to the Company's generation assets located in New York. The Company has increased its blanket authorization from the NYSPSC for the issuance of such debt from $10 billion to $15 billion.

    Regional Regulatory Developments

        In New England, New York, the Mid-Atlantic region, the Midwest and California, the FERC has approved regional transmission organizations, also commonly referred to as ISOs. Most of these ISOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by the 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 granted similar responsibilities to the ERCOT. NRG is affected by rule/tariff changes that occur in the ISO regions.

        For further discussion on regulatory developments see Item 15 — Note 23, Regulatory Matters, to the Consolidated Financial Statements.

    Northeast Region

        New England — On February 22, 2010, ISO-NE filed with FERC proposed amendments to its Forward Capacity Market, or FCM, design. A number of generators protested the ISO-NE filing, arguing that FERC should not accept the proposed amendments. On March 23, 2010, an association of generators filed a complaint alleging that the proposed FCM amendments are not just and reasonable due to market distortions such as out-of-market contracts, and thus would continue to under-compensate capacity suppliers in New England. On April 2, 2010, NRG and PSEG jointly filed a second complaint alleging that the existing FCM market fails to adequately establish zonal prices and thus does not adequately compensate suppliers for the locational value of their capacity. These complaints are seeking only prospective relief. Any changes to the FCM market in response to these complaints could benefit from the Company's existing New England assets in future FCM auctions. On April 23, 2010, FERC issued an order consolidating the proceedings. In its order, FERC accepted some of the ISO-NE's proposed changes, but also set several of the central issues for hearing and settlement processes.

        New York — On November 30, 2010, the NYISO filed at FERC its proposed installed capacity demand curves for 2011/2012, 2012/2013, and 2013/2014. The demand curves are a critical determinant of capacity market prices. The Company and other market participants protested the NYISO's filing, and on January 28, 2011, the FERC found in favor of generators on a number of issues principally related to determining the cost of new entry and the resulting adjustments to the demand curves should positively affect capacity clearing prices. Separately, the state-wide Installed Reserve Margin, or IRM, is set annually by the New York State Reliability Council, or NYSRC, and affects the overall demand for capacity in the New York market. The NYSRC approved a 2011 IRM of 15.5%, which is a decrease of 2.5% from the 2010 requirement.

        PJM — On January 28, 2011, New Jersey Governor Chris Christie signed into law, Senate Bill 2381 (N.J. 214th Leg. 2011), designed to procure up to 2,000 MW of new generation. While this legislation may create opportunities for the Company, it also has the potential of distorting the PJM capacity market because the new generation must be offered into PJM's capacity market at prices low enough to guarantee clearing which in turn may reduce the clearing price available to existing generating resources. On February 1, 2011, the PJM Power Providers Group filed a complaint with FERC seeking to require PJM to revise its rules to mitigate the adverse impacts of the legislation. In addition, on February 9, 2011, a group of generators filed a lawsuit in the U.S. District Court for the District of New Jersey seeking to bar the implementation of Senate Bill 2381 based upon the Supremacy Clause and Commerce Clause of the U.S. Constitution.

    West Region

        California — On December 1, 2010, the CAISO filed to replace its interim backstop Capacity Procurement Mechanism, or CPM, with a permanent version. The proposed CPM would provide monthly capacity contracts to generating units not contracted to fulfill California's Resource Adequacy requirements, but nevertheless needed for reliability. On December 22, 2010, the Company and the Independent Energy Producers Association protested CAISO's filing at FERC alleging that the CPM denies such generators adequate compensation.

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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 and NRG expects this trend to continue. The electric generation industry will face new requirements to address air emissions, climate change, combustion byproducts and water use. In general, future laws and regulations are expected to require the addition of emission controls 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.

        Climate Change — NRG emits GHGs in the process of generating electricity. The following table shows the reduction in CO2, which makes up greater than 99% of the Company's GHG emissions, from 2000 to the present. NRG anticipates reductions in its future emissions profile as NRG implements its strategy to add more renewable sources like wind and solar, modernize the fleet through RepoweringNRG, improve generation efficiencies, explore methods to capture CO2, and seek ways to offset GHGs.

GRAPHIC

        The impact from legislation or federal, regional or state regulation of GHGs on the Company's financial performance will depend on a number of factors, including the overall level of GHG reductions required under any such regulations, the price and availability of offsets, and the extent to which NRG would be entitled to receive CO2 emissions allowances without having to purchase them in an auction or on the open market. Thereafter, under any such legislation or regulation, the impact on NRG would depend on the Company's level of success in developing and deploying low and no carbon technologies.

    Federal Environmental Initiatives

        Environmental Regulatory Landscape — A number of regulations that could significantly impact the power generation industry are in development or under review by the U.S. EPA: CAIR/CATR, NSPS for GHGs, MACT, NAAQS revisions, coal combustion byproducts, and once-through cooling. While most of these regulations have been considered for some time, they are expected to gain clarity in 2011 through 2012. The timing and stringency of these regulations will provide a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. The Company has included capital to meet anticipated CAIR Phase I and II, proposed CATR, MACT standards for mercury, and the installation of Best Technology Available, or BTA, under the 316(b) Rule in the current estimated environmental capital expenditures. The Company cannot predict the impact of future regulations and could face additional investments over time. However, NRG believes it is positioned to meet more stringent requirements through its planned capital expenditures, existing controls, and the use of Powder River Basin coal.

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        Air — The U.S. EPA released the proposed CATR on July 6, 2010. It is designed to replace CAIR and address the findings of the U.S. Court of Appeals for the D.C. Circuit that initially vacated the rule. The intent of the rule is to bring 31 states and Washington, D.C. into attainment with PM 2.5 and ozone national ambient air quality standards through emission reductions in SO2 and NOx. Proposed implementation would be through a cap and trade program starting in 2012 with constrained trading between states in the CATR regions. In 2014, the SO2 cap would be further reduced in certain states. Under CATR, use of discounted Acid Rain SO2 allowances would be discontinued and replaced with a completely distinct CATR SO2 allowance program. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain Program. Under the current construct, however, additional impacts cannot be fully determined until EPA modeling is updated, an allocation distribution plan is identified, and the rule is final. This rule could result in up to a $50 million future impairment of the Company's SO2 emission allowances, which are recorded as intangible assets on the Company's balance sheet. NRG's currently planned environmental capital expenditures are consistent with reductions required per the proposed rule.

        The regulation of hazardous air pollutants under the Clean Air Act, or CAA requires maximum achievable control technology, or MACT to control emissions. The U.S. EPA announced its intention to release the proposed rule in mid-March 2011. Among the pollutants to be controlled are mercury, acid gases, certain metals and certain organics. NRG has 3,400 MW of sub-bituminous coal fired capacity, some or all of which could be required to install controls for acid gases under the final acid gas MACT rule. Additional investments for compliance and associated costs cannot be determined until the rule is final, but could be material.

        Finalization of the Endangerment Finding, a rule addressing tailpipe limitations for light duty vehicles, and a final interpretation of the Johnson Memorandum set the stage for regulation of GHGs from stationary sources. On June 3, 2010, the U.S. EPA published the final rule tailoring the applicability criteria that determine which new and modified sources will become subject to permitting requirements for GHGs under the Prevention of Significant Deterioration, or PSD and Title V programs of the CAA. The rule raised applicability triggers to 75,000 or 100,000 tons per year CO2 equivalents, or CO2e, and implemented the requirements in two phases: January 2, 2011, and July 2, 2011. In addition, the U.S. EPA announced their intent to develop New Source Performance Standards for GHGs from electric generating units. The immediate impact to NRG's existing, new and modified facilities is not expected to be material. The Company will continue to evaluate the potential long-term impact as regulatory programs are implemented over time.

        Waste — On May 4, 2010, the U.S. EPA proposed two options for the regulation of coal combustion residue, commonly known as coal ash. Under the Proposal's first regulatory option, the U.S. EPA would reverse its August 1993 and May 2000 Bevill Regulatory Determinations and list coal ash as a special waste subject to regulation under hazardous waste regulations. The second regulatory option would leave the Bevill Determination in place and regulate disposal of coal ash as non-hazardous. Under both options, an exemption for the beneficial use of coal ash would remain in place. Additionally, under both options, the U.S. EPA would establish dam safety requirements to address the structural integrity of surface impoundments. While it is not possible to predict the impact of this rule until it is final, as proposed it is not expected to have a material impact on NRG's operations, as all NRG flyash disposal sites are dry landfills. However, should the U.S. EPA implement the hazardous waste option, NRG may incur significant costs due to loss of markets for beneficial reuse. Given the recent release of this proposed rule, NRG will continue to monitor developments and their respective impact on the Company's operations.

        Water — In July 2004, the U.S. EPA published rules governing cooling water intake structures at existing power facilities commonly referred to as the Phase II 316(b) rules. These 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 BTA for minimizing adverse environmental impacts unless a facility shows that such standards would result in very high costs or little environmental benefit. As a result of a decision by the Second Circuit Court of Appeals, the U.S. EPA suspended the rule in July 2007 while preparing a revised version. The U.S. Supreme Court released a decision on April 1, 2009, in which it concluded that the U.S. EPA does have the authority to allow a cost-benefit analysis in the evaluation of BTA. This ruling is favorable for the industry and NRG as it improves the U.S. EPA's ability to include alternatives to closed-loop cooling in its redraft of the Phase II 316(b) Rules. In the absence of federal regulations, some states in which NRG operates, such as California, Connecticut, Delaware and New York, are moving ahead with guidance for more stringent requirements for once-through cooled units which may have an impact on future operations.

        In June 2010, the U.S. EPA issued a Section 308 Information Collection Request to steam electric power generating plants across the industry, including 13 NRG facilities. The questionnaire focused on water and wastewater discharges from power plants. The U.S. EPA indicated results will be used to develop new effluent guidelines for the industry. The Company is unable to predict the impact from any future revisions to the effluent guidelines.

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    Regional U.S. Environmental Initiatives

    Northeast

        The New York State Department of Environmental Conservation finalized the NOx Reasonably Available Control Technology, or RACT, Rule on July 14, 2010. This rule identifies new NOx emission limits for major sources which must be met by July 1, 2014. Plants can comply or request an alternate RACT limit. All of NRG's facilities are able to meet the new standards with the exception of the Oswego plant, which will apply for an alternate limit.

    West

        As required by Assembly Bill 32, or AB32, the state of California proposed rules for a phased, multi-sector cap-and-trade program for GHGs. Participation by the electric generation sector will begin in 2012, unless the program is delayed due to current challenges in the courts. NRG does not expect implementation of the GHG cap-and-trade program in California to have a significant adverse financial impact on the Company for a variety of reasons, including the fact that NRG's California portfolio consists mainly of natural gas-fired peaking facilities and will likely be able to pass through any costs of purchasing allowances in power prices. New NRG renewable projects in California markets will support AB32 requirements for the increased use of renewable energy.

        The California statewide 316(b) policy to mitigate once-through cooling was effective as of October 1, 2010. Options for power plants with once-through cooling include transitioning to a closed loop system, retirement or submitting an alternative plan that meets equivalent mitigation criteria. Specified compliance dates for NRG's El Segundo and Encina power plants are December 31, 2015, and December 31, 2017, respectively. NRG is analyzing compliance through a mix of alternative mitigation plans and repowering.

    South Central Region

        On February 11, 2009, the U.S. Department of Justice acting at the request of the U.S. EPA commenced a lawsuit against Louisiana Generating, LLC in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which Notice of Violations, or NOVs, were issued to Louisiana Generating, LLC on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be found in Item 3 — Legal Proceedings, United States of America v. Louisiana Generating, LLC.

Environmental Capital Expenditures

        Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2011 through 2015 to meet NRG's environmental commitments will be approximately $721 million (of which $93 million will be financed through draws on the Indian River tax exempt facilities) and are primarily associated with controls on the Company's Big Cajun and Indian River facilities. These capital expenditures, in general, are related to installation of particulate, SO2, NOx, or mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of BTA under the Phase II 316(b) Rule. NRG continues to explore cost effective compliance alternatives. A more detailed discussion of environmental capital expenditures can be found in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources, Capital Expenditures and Environmental Capital Expenditures.

    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 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. Further discussions of affected NRG sites can be found in Item 15 — Note 24, Environmental Matters, to the Consolidated Financial Statements.

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        Nuclear Waste — The program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. In order to meet the federal government's obligations to safely manage used nuclear fuel and radioactive waste under the U.S. Nuclear Waste Policy Act of 1982, the U.S. DOE has announced the establishment of a blue ribbon commission to explore alternatives. Also consistent with the Act, owners of nuclear plants, including the owners of STP, entered into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services. Since 1998, the U.S. DOE has been in default on its obligations to begin removing spent nuclear fuel and high-level radioactive waste from reactors.

        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. NRG intends to continue to ship low-level waste material from STP offsite for as long as an alternative disposal site is available. In the event these facilities become unavailable, STP's on-site storage capacity is expected to be adequate for STP's needs until other off-site facilities are identified.

Employees

        As of December 31, 2010, NRG had 4,964 employees, approximately 33% of whom were covered by U.S. bargaining agreements. During 2010, the Company did not experience any labor stoppages or labor disputes at any of its facilities.

Available Information

        NRG's annual reports on Form 10-K, quarterly reports on Form 10-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, or Exchange Act, 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 SEC. The Company also routinely posts press releases, presentations, webcasts, and other information regarding the Company on the Company's website.

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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 it 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 natural gas-fired power plants that currently have substantially higher variable costs than NRG's coal-fired baseload power plants. This 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 that 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 material adverse impact on the Company's cash flow and financial position.

        Market prices for power, 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:

    changes 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;

    electric supply disruptions, including plant outages and transmission disruptions;

    changes in power transmission infrastructure;

    fuel transportation capacity constraints;

    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.

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.

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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 2014, and the Company also sells forward the output from its intermediate and peaking facilities when it 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 the 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. During limited peak demand periods, the load requirements of these contract customers exceed the baseload capacity of NRG's coal-fired Big Cajun II plant. During such peak demand periods, NRG either employs its owned or leased gas-fired assets or purchases power from external sources and, depending upon the then-current gas commodity pricing, these purchases can be at higher prices than can be recovered under the Company's contracts. NRG's financial returns from its South Central region could be negatively impacted for a limited period if the rural cooperatives significantly grow their customer base during the remaining terms of these contracts prior to the expiration of half of the cooperative contracts in 2014. In addition, NRG has other obligations to supply power to load serving entities and, at times, NRG's load obligations may exceed its available generation and long-term purchases thus requiring the Company to purchase energy at market prices.

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. The Company also relies on counterparty performance under its hedging agreements and is exposed to the credit quality of its counterparties under those agreements. 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.

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        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, offset of netting arrangements, letters of credit, a first or 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 ASC-815, Derivatives and Hedging, or ASC 815, 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. All economic hedges may not necessarily qualify for cash flow hedge accounting treatment. As a result, the Company's quarterly and annual results are subject to significant fluctuations caused by changes in market prices.

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 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 emission 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.

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The Company may incur additional costs or delays in the development, construction and operation of new plants, improvements to existing plants, or the implementation of environmental control equipment at existing plants and may not be able to recover their investment or complete the project.

        The Company is in the process of developing or constructing new generation facilities including nuclear and solar facilities; improving its existing facilities; and adding environmental controls to its existing facilities. The development, construction, expansion, modification and refurbishment of power generation facilities involve many additional risks, including:

    the inability to receive U.S. DOE loan guarantees and cash grants;

    delays in obtaining necessary permits and licenses;

    the inability to sell down interests in a project or develop successful partnering relationships;

    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;

    exchange rate risks; and

    failure of contracting parties to perform under contracts, including EPC contractors.

        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. Insurance is maintained to protect against these risks, warranties are generally obtained for limited periods relating to the construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. The insurance, warranties or performance guarantees, however, may not be adequate to cover increased expenses. As a result, a project may cost more than projected and may be unable to fund principal and interest payments under its construction financing obligations, if any. A default under such a financing obligation could result in losing the Company's interest in a power generation facility. Furthermore, the Company's inability to find a replacement contracting party, particularly an EPC contractor, where the original contracting party has failed to perform, could result in the abandonment of the development and/or construction of such project, while the Company could remain obligated on other agreements associated with the project, including PPAs.

        If the Company is unable to complete the development or construction of a facility or environmental control, or decides to delay or cancel such project, it may not be able to recover its investment in that facility or environmental control. In addition, the Company's nuclear development initiatives are an integral part of the Company's overall low or no carbon growth initiatives and the inability of the Company to maintain significant involvement in new nuclear development may result in the Company's inability to successfully implement the Company's other growth initiatives. Furthermore, if construction projects are not completed according to specification, the Company may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced net income.

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The Company's development programs are subject to financing and public policy risks that could adversely impact NRG's financial performance or result in the abandonment of such development projects.

        While NRG currently intends to develop and finance the more capital intensive, projects 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 EPC contracts, construction costs, PPAs 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 project or should the credit rating agencies attribute a material amount of the project finance debt to NRG's credit, the financing of the development projects could have a negative impact on the credit ratings of NRG.

        As part of the RepoweringNRG 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.

        Furthermore, the viability of the Company's renewable development projects are largely contingent on public policy mechanisms including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, renewable portfolio standards, or RPS, and carbon trading plans. These mechanisms have been implemented at the state and federal levels to support the development of renewable generation, demand-side and smart grid, nuclear, and other clean infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics and viability of the Company's development program and expansion into clean energy investments.

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.

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NRG relies on power transmission facilities that it 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.

        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 the Company's 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. 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 or which complement the Company's industry. The acquisition of 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, the ability to retain customers 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.

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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 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 U.S. make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. The 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 the 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 the 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 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, the Company's business prospects and financial results could be negatively impacted.

        NRG cannot predict at this time the outcome of the ongoing efforts by the Commodities Futures Trading Commission to implement the Dodd-Frank Act and to increase the regulation of over-the-counter derivatives including those related to energy commodities. The CFTC efforts are seeking, among other things, increased clearing of such derivatives through clearing organizations and the increased standardization of contracts, products, and collateral requirements. Such changes could negatively impact NRG's ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, limiting NRG's ability to utilize liens as collateral and decreasing liquidity in the forward commodity markets.

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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 owns a 44.0% interest, is subject to regulation by the 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 1,175 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 U.S. DOE 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 for further discussion. 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 the Company's plants. Should NRG fail 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 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. Regulations currently under revision by U.S. EPA, including CAIR, MACT standards to control mercury or acid gases and the 316 (b) rule to mitigate impact by once-through cooling, could result in tighter standards or reduced compliance flexibility. While the NRG fleet employs advanced controls and utilizes industry's best practices, new regulations to address tightened National Ambient Air Quality Standards for Ozone and PM 2.5 including CATR, limit GHG emissions or restrict ash handling at coal-fired power plants could also further affect plant operations.

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Policies at the national, regional and state levels to regulate GHG emissions could adversely impact NRG's result of operations, financial condition and cash flows.

        NRG's GHG emission for 2010 can be found in Item 1 — Business — Environmental Matters. The impact of further legislation or regulation of GHGs on the Company's financial performance will depend on a number of factors, including the overall level of GHG reductions required, the extent to which mitigation is required, the price and availability of offsets, and the extent to which NRG would be entitled to receive CO2 emissions allowances without having to purchase them in an auction or on the open market.

        Approximately 8 million metric tons were emitted from the Company's generating units in Connecticut, Delaware, Maryland, Massachusetts, and New York that are subject to RGGI. While 2009 through 2011 RGGI CO2 allowance prices have remained low, the impact of RGGI on future power prices (and thus on the Company's financial performance), indirectly through generators seeking to pass through the cost of their CO2 emissions, cannot be predicted.

        In addition, under certain conditions, GHG emissions from power plants are subject to existing sections of the CAA including PSD/NSR and Title V permitting. Implementation practices under the PSD/NSR and emission rates set under the New Source Performance Standards will determine the extent to which power plant operations are affected over time.

        Hazards customary to the power production industry include the potential for unusual weather conditions, which could affect fuel pricing and availability, the Company's route to market or access to customers, i.e. transmission and distribution lines, or critical plant assets. To the extent that climate change contributes to the frequency or intensity of weather related events, NRG's operations and planning process could be impacted.

NRG's business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by its unionized employees or inability to replace employees as they retire.

        As of December 31, 2010, approximately 65% of NRG's employees at its U.S. generation plants were 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. In addition, a number of the Company's employees at NRG's plants are close to retirement. The Company's inability to replace those workers could create potential knowledge and expertise gaps as those workers retire.

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.

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NRG's level of indebtedness could adversely affect its ability to raise additional capital to fund its operations, or return capital to stockholders. It could also 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 return capital to stockholders or otherwise engage in activities that may be in its long-term best interests. 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.

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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 ASC-350, Intangibles — Goodwill and Other; or ASC 350, 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.

Volatile power supply costs and demand for power could adversely affect the financial performance of NRG's retail business.

        Although NRG has begun the process of becoming the primary provider of Reliant Energy's supply requirements, Reliant Energy presently purchases a significant portion of its supply requirements from third parties. As a result, Reliant Energy's financial performance depends on its ability to obtain adequate supplies of electric generation from third parties at prices below the prices it charges its customers. Consequently, the Company's earnings and cash flows could be adversely affected in any period in which Reliant Energy's power supply costs rise at a greater rate than the rates it charges to customers. The price of power supply purchases associated with Reliant Energy's energy commitments can be different than that reflected in the rates charged to customers due to, among other factors:

    varying supply procurement contracts used and the timing of entering into related contracts;

    subsequent changes in the overall price of natural gas;

    daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;

    transmission constraints and the Company's ability to move power to its customers; and

    changes in market heat rate (i.e., the relationship between power and natural gas prices).

        The Company's earnings and cash flows could also be adversely affected in any period in which the demand for power significantly varies from the forecasted supply, which could occur due to, among other factors, weather events, competition and economic conditions.

Significant events beyond the Company's control, such as hurricanes and other weather-related problems or acts of terrorism, could cause a loss of load and customers and thus have a material adverse effect on the Company's Texas retail business.

        The uncertainty associated with events beyond the Company's control, such as significant weather events and the risk of future terrorist activity, could cause a loss of load and customers and may affect the Company's results of operations and financial condition in unpredictable ways. In addition, significant weather events or terrorist actions could damage or shut down the power transmission and distribution facilities upon which the retail business is dependent. Power supply may be sold at a loss if these events cause a significant loss of retail customer load.

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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 of 1933, as amended, or 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 Item 1A — Risk Factors Related to NRG Energy, Inc. and the following:

    General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;

    Volatile power supply costs and demand for power;

    Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;

    The effectiveness of NRG's risk management policies and procedures, and the ability of NRG's counterparties to satisfy their financial commitments;

    Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;

    NRG's ability to operate its businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;

    NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;

    The liquidity and competitiveness of wholesale markets for energy commodities;

    Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other greenhouse gas emissions;

    Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately compensate NRG's generation units for all of its costs;

    NRG's ability to borrow additional funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;

    NRG's ability to receive Federal loan guarantees or cash grants to support development projects;

    Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;

    NRG's ability to implement its RepoweringNRG strategy of developing and building new power generation facilities, including new nuclear, wind and solar projects;

    NRG's ability to implement its econrg strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;

    NRG's ability to implement its FORNRG strategy of increasing the return on invested capital through operational performance improvements and a range of initiatives at plants and corporate offices to reduce costs or generate revenues;

    NRG's ability to achieve its strategy of regularly returning capital to shareholders;

    NRG's ability to maintain retail market share;

    NRG's ability to successfully evaluate investments in new business and growth initiatives;

    NRG's ability to successfully integrate and manage any acquired businesses; and

    NRG's ability to develop and maintain successful partnering relationships.

        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.


Item 1B — Unresolved Staff Comments

        None.

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Item 2 — Properties

        Listed below are descriptions of NRG's interests in facilities, operations and/or projects owned as of December 31, 2010. 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, 2010. The following table summarizes NRG's power production and cogeneration facilities by region:

Name and Location of Facility
  Power Market   % Owned   Net
Generation
Capacity (MW) (a)
  Primary
Fuel-type

Texas Region:

                   

Cedar Bayou, Baytown, TX

  ERCOT     100.0     1,495   Natural Gas

Cedar Bayou 4, Baytown, TX

  ERCOT     50.0     260   Natural Gas

Elbow Creek Wind Farm, Howard County, TX

  ERCOT     100.0     125   Wind

Greens Bayou, Houston, TX

  ERCOT     100.0     355   Natural Gas

Langford Wind Farm, Christoval, TX

  ERCOT     100.0     150   Wind

Limestone, Jewett, TX

  ERCOT     100.0     1,690   Coal

San Jacinto, LaPorte, TX

  ERCOT     100.0     160   Natural Gas

Sherbino Wind Farm, Pecos County, TX

  ERCOT     50.0     75   Wind

South Texas Project, Bay City, TX (b)

  ERCOT     44.0     1,175   Nuclear

South Trent Wind Farm, Sweetwater, TX

  ERCOT     100.0     100   Wind

S. R. Bertron, Deer Park, TX

  ERCOT     100.0     470   Natural Gas

T. H. Wharton, Houston, TX

  ERCOT     100.0     1,025   Natural Gas

W. A. Parish, Thompsons, TX (c)

  ERCOT     100.0     2,490   Coal

W. A. Parish, Thompsons, TX (c)

  ERCOT     100.0     1,175   Natural Gas

Northeast Region:

                   

Arthur Kill, Staten Island, NY

  NYISO     100.0     865   Natural Gas

Astoria Gas Turbines, Queens, NY

  NYISO     100.0     550   Natural Gas

Conemaugh, New Florence, PA

  PJM     3.7     65   Coal

Connecticut Jet Power, CT (four sites)

  ISO-NE     100.0     140   Oil/Natural Gas

Devon, Milford, CT

  ISO-NE     100.0     135   Oil

GenConn Devon, Milford, CT

  ISO-NE     50.0     95   Oil

Dunkirk, NY

  NYISO     100.0     530   Coal

Huntley, Tonawanda, NY

  NYISO     100.0     380   Coal

Indian River, Millsboro, DE (d)

  PJM     100.0     660   Coal

Keystone, Shelocta, PA

  PJM     3.7     65   Coal

Middletown, CT

  ISO-NE     100.0     770   Oil

Montville, Uncasville, CT

  ISO-NE     100.0     500   Oil

Norwalk Harbor, So. Norwalk, CT

  ISO-NE     100.0     340   Oil

Oswego, New York

  NYISO     100.0     1,635   Oil

Vienna, MD

  PJM     100.0     170   Oil

South Central Region:

                   

Bayou Cove, Jennings, LA

  SERC-Entergy     100.0     300   Natural Gas

Big Cajun I, Jarreau, LA

  SERC-Entergy     100.0     430   Natural Gas/Oil

Big Cajun II, New Roads, LA (e)

  SERC-Entergy     86.0     1,495   Coal

Cottonwood, Deweyville, TX

  SERC-Entergy     100.0     1,265   Natural Gas

Rockford I, IL

  PJM     100.0     305   Natural Gas

Rockford II, IL

  PJM     100.0     155   Natural Gas

Sterlington, LA

  SERC-Entergy     100.0     175   Natural Gas

West Region:

                   

Blythe, Blythe, CA

  CAISO     100.0     20   Solar

El Segundo Power, CA

  CAISO     100.0     670   Natural Gas

Encina, Carlsbad, CA

  CAISO     100.0     965   Natural Gas

Long Beach, CA

  CAISO     100.0     260   Natural Gas

Saguaro Power Co., Henderson, NV

  WECC     50.0     45   Natural Gas

San Diego Combustion Turbines, CA (four sites)

  CAISO     100.0     190   Natural Gas

International Region:

                   

Gladstone Power Station, Queensland, Australia

  Enertrade/Boyne Smelter     37.5     605   Coal

Schkopau Power Station, Germany

  Vattenfall Europe     41.9     400   Lignite
(a)
Actual capacity can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time.
(b)
Generation capacity figure consists of the Company's 44% individual interest in the two units at STP.
(c)
W.A. Parish has nine units, four of which are baseload coal-fired units and five of which are natural gas-fired units.
(d)
Indian River Unit 1 will be retired May 1, 2011, and Indian River Unit 3 will be retired by December 31, 2013.
(e)
Units 1 and 2 owned 100.0%, Unit 3 owned 58.0%.

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Thermal Facilities

        The Company's thermal businesses in Pittsburgh, Harrisburg and San Francisco are regulated by their respective state's Public Utility Commission. The other thermal businesses are subject to contract terms with their customers.

        The following table summarizes NRG's thermal steam and chilled water facilities as of December 31, 2010:

 
Name and Location of Facility
  % Owned   Thermal Energy Purchaser   Megawatt
Thermal
Equivalent
Capacity (MWt)
  Generating
Capacity
 

NRG Energy Center Minneapolis, MN

    100.0   Approx. 100 steam and 50 chilled water customers     334
141
  Steam: 1,140 MMBtu/hr.
Chilled Water: 40,200 tons
 

NRG Energy Center San Francisco, CA

    100.0   Approx 170 steam customers     133   Steam: 454 MMBtu/Hr.
 

NRG Energy Center Harrisburg, PA

    100.0   Approx 210 steam and 3 chilled water customers     129
8
  Steam: 440 MMBtu/hr.
Chilled water: 2,400 tons
 

NRG Energy Center Phoenix, AZ

    100.0   Approx 30 chilled water customers     90   Chilled water: 25,600 tons
 

NRG Energy Center Pittsburgh, PA

    100.0   Approx 25 steam and 25 chilled water customers     87
45
  Steam: 296 MMBtu/hr.
Chilled water: 12,920 tons
 

NRG Energy Center San Diego, CA

    100.0   Approx 20 chilled water customers     26   Chilled water: 7,425 tons
 

Camas Power Boiler Camas, WA

    100.0   Georgia Pacific Group     59   Steam: 200 MMBtu/hr.
 

NRG Energy Center Dover, DE

    100.0   Kraft Foods Inc. and Proctor & Gamble Company     56   Steam: 190 MMBtu/hr.

        The following table summarizes NRG's thermal power generation facilities as of December 31, 2010:

Name and Location of Facility
  Power Market/
Zone
  % Owned   Generation
Capacity (MW)
  Primary
Fuel Type

Paxton Creek Cogeneration Harrisburg, PA

  PJM / East     100.0     12   Natural Gas

Dover Cogeneration, DE

  PJM / West     100.0     103   Natural Gas/Coal

Other Properties

        In addition, NRG owns several real properties and facilities relating to its generation assets, other vacant real property unrelated to the Company's 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, its Reliant Energy and Green Mountain Energy offices and call centers, and various other office space.

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Item 3 — Legal Proceedings

        Public Utilities Commission of the State of California v. Long-Term Sellers of Long-Term Contracts to the California Department of Water Resources, FERC Docket No. EL02-60 et al. — This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC's review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP's appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller's market-based rate authority; (ii) that the public interest "bar" required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit's decision agreeing that the case should be remanded to the FERC to clarify the FERC's 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008, decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court's June 26, 2008, decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their reply. At this time, the FERC has not acted on remand.

        At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG's financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy's 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.

        On January 14, 2010, the U.S. Supreme Court issued its decision in an unrelated proceeding involving the Mobile-Sierra doctrine that will affect the standard of review applied to the CDWR contract on remand before the FERC. In NRG Power Marketing v. Maine Public Utilities Commission, the Supreme Court held that the Mobile-Sierra presumption regarding the reasonableness of contract rates does not depend on the identity of the complainant who seeks a FERC investigation/refund.

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        United States of America v. Louisiana Generating, LLC., U.S.D.C Middle District of Louisiana, Civil Action No. 09-100-RET-CN (filed February 11, 2009) — On February 11, 2009, the U.S. Department of Justice, or U.S. DOJ, acting at the request of the U.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC, or LaGen, in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to LaGen on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990's, several years prior to NRG's acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the best available control technology, or BACT, to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint includes a request for an injunction to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA's Prevention of Significant Deterioration program; (vi) award to the Department of Justice its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.

        On April 27, 2009, LaGen made several filings. LaGen filed an objection in the Cajun Electric Cooperative Power, Inc.'s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. LaGen also filed a complaint, or adversary proceeding, in the same bankruptcy proceeding, seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric with respect to environment liabilities arising prior to the acquisition; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for any of the violations alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have merit. On April 15, 2010, the bankruptcy court signed an order granting LaGen's stipulation of voluntary dismissal without prejudice of the adversary proceeding. The bankruptcy proceeding has since closed.

        On June 8, 2009, the parties filed a joint status report in the U.S. DOJ lawsuit setting forth their views of the case and proposing a trial schedule. On April 28, 2010, the district court entered a Joint Case Management Order, in which the district court tentatively scheduled trial on a liability phase for mid-2011 and, if necessary, trial on the damages (remedy) phase for mid-2012. These dates are subject to change. On January 18, 2011, the district court entered a Third Amended Case Scheduling Order which extended certain case deadlines by several weeks.

        On August 24, 2009, LaGen filed a motion to dismiss this lawsuit, and on September 25, 2009, the U.S. DOJ filed its opposition to the motion. Thereafter, on February 18, 2010, the Louisiana Department of Environmental Quality, or LDEQ, filed a motion to intervene in the above lawsuit and a complaint against LaGen for alleged violations of Louisiana's PSD regulations and Louisiana's Title V operating permit program. LDEQ seeks substantially similar relief to that requested by the U.S. DOJ. On February 19, 2010, the district court granted LDEQ's motion to intervene. On April 26, 2010, LaGen filed a motion to dismiss the LDEQ complaint. On July 21, 2010, the motions to dismiss the U.S. DOJ and LDEQ complaints were argued to the district court. On August 20, 2010, the parties submitted proposed findings of fact and conclusions of law, and both parties have submitted additional briefing on emerging jurisprudence from other jurisdictions touching on the issues at stake in the U.S. DOJ lawsuit. On February 4, 2011, LaGen filed motions for summary judgment requesting that the court dismiss all of the U.S. DOJ's claims. Also on February 4, 2011, the U.S. DOJ filed three motions for partial summary judgment.

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        Excess Mitigation Credits — From January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or EMCs, to its monthly charges to retail electric providers as ordered by the PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers' monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from GenOn Energy, Inc.., or GenOn, totaled $385 million for RERS's "Price to Beat" Customers. It is unclear what the actual number may be. "Price to Beat" was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT's order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment with the Court of Appeals for the Third District of Texas with the first such appeal filed on the same date as the state district court judgment and the last such appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District reversed the lower court's decision ruling that CenterPoint Energy's stranded cost recovery should exclude only EMCs credited to RERS for its "Price to Beat" customers. On June 2, 2008, CenterPoint Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Supreme Court of Texas agreed to consider the CenterPoint Energy's petition for review as well as two related petitions for review filed by other entities. Oral argument occurred on October 6, 2009.

        In November 2008, CenterPoint Energy and RRI, on behalf of itself and affiliates including RERS, agreed to suspend unexpired deadlines, if any, related to limitations periods that might exist for possible claims against REI and its affiliates if CenterPoint Energy is ultimately not allowed to include in its stranded cost calculation those EMCs previously credited to RERS. Regardless of the outcome of the Texas Supreme Court proceeding, NRG believes that any possible future CenterPoint Energy claim against RERS for EMCs credited to RERS would lack legal merit. No such claim has been filed.

        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.


Item 4 — (Removed and Reserved)

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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 22,000,000 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 the 3.625% Convertible Perpetual Preferred Stock.

        NRG's common stock is listed on the New York Stock Exchange and has been assigned the symbol: NRG. The high and low sales prices, as well as the closing price for the Company's common stock on a per share basis for 2010 and 2009 are set forth below:

Common Stock Price
  Fourth
Quarter
2010
  Third
Quarter
2010
  Second
Quarter
2010
  First
Quarter
2010
  Fourth
Quarter
2009
  Third
Quarter
2009
  Second
Quarter
2009
  First
Quarter
2009
 

High

  $ 21.64   $ 23.81   $ 25.19   $ 25.70   $ 29.18   $ 29.26   $ 25.96   $ 25.38  

Low

    18.22     20.02     20.49     20.20     22.82     21.94     16.50     15.19  

Closing

    19.54     20.82     21.21     20.90     23.61     28.19     25.96     17.60  

        NRG had 247,197,355 shares outstanding as of December 31, 2010, and as of February 16, 2011, there were 247,536,568 shares outstanding. As of February 16, 2011, there were 152 common stockholders of record.

Dividends

        NRG has not declared or paid dividends on its common stock. To the extent NRG declares such a dividend, the amount available for dividends is currently limited by the Company's senior secured credit agreements and high yield note indentures.

Repurchase of equity securities

        NRG's repurchases of equity securities for the year ended December 31, 2010, were as follows:

For the Year Ended December 31, 2010
  Total Number of
Shares Purchased
  Average Price
Paid per Share
  Total Number
of Shares
Purchased as
Part of Publicly
Announced Plans
or Programs
  Dollar Value of
Shares that may be
Purchased Under the
2010 Capital
Allocation Plan
 

First quarter

      $       $ 180,000,000  

Second quarter

    2,214,000     22.57     2,214,000     130,002,304  

Third quarter

    3,208,292     20.26     3,208,292     65,002,304  

Fourth quarter

    3,040,919     21.38     3,040,919      
                       

Total for 2010

    8,463,211     21.27     8,463,211      
                       

        On February 23, 2010, the Company announced a plan to repurchase $180 million of common stock under the Company's 2010 Capital Allocation Plan. The Company repurchased $50 million of common stock during second quarter of 2010. In August 2010, the Company entered into an accelerated share repurchase agreement, or ASR Agreement, under which the Company repurchased the remaining $130 million of common stock. In connection with this agreement, the Company paid $130 million and received 3,208,292 shares of the Company's common stock in August 2010. Upon final settlement, which occurred on October 22, 2010, the Company received a settlement amount of 3,040,919 additional shares of common stock. The shares repurchased under the ASR Agreement complete the Company's $180 million share buyback program for 2010. The Company's share repurchases are subject to market prices, financial restrictions under the Company's debt facilities, and as permitted by securities laws.

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Securities Authorized for Issuance under Equity Compensation Plans

Plan Category
  (a)
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
  (b)
Weighted-Average Exercise
Price of Outstanding
Options, Warrants and
Rights
  (c)
Number of Securities
Remaining Available
for Future Issuance
Under Equity Compensation
Plans (Excluding
Securities Reflected
in Column (a))
 

Equity compensation plans approved by security holders

    8,491,959   $ 24.22     10,141,819  

Equity compensation plans not approved by security holders

        N/A      
               

Total

    8,491,959   $ 24.22     10,141,819  
               
(a)
Consists of NRG Energy, Inc.'s Long-Term Incentive Plan, or the LTIP, and NRG Energy, Inc.'s Employee Stock Purchase Plan, or the ESPP. 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 16,000,000, on a post-split basis, and again on December 8, 2006, to make technical and administrative changes. On July 28, 2010, the LTIP was amended to increase the number of shares available for issuance to 22,000,000. The LTIP provides for grants of stock options, stock appreciation rights, restricted stock, performance units, deferred stock units and dividend equivalent rights. 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 10,141,819 and 5,129,593 shares of common stock remaining available for grants of awards under NRG's LTIP as of December 31, 2010, and 2009, respectively. The ESPP was approved by the Company's stockholders on May 14, 2008. There were 500,000 shares reserved from the Company's treasury shares for the ESPP. As of December 31, 2010, there were 297,478 shares of treasury stock reserved for issuance under the ESPP. In the first quarter of 2011, 65,716 shares were issued to employees' accounts from the treasury stock reserve for the ESPP.

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Stock Performance Graph

        The performance graph below compares NRG's cumulative total shareholder return on the Company's common stock for the period December 31, 2005, through December 31, 2010, 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. NRG's common stock trades 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 December 31, 2005, 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

         GRAPHIC

 
  Dec-2005   Dec-2006   Dec-2007   Dec-2008   Dec-2009   Dec-2010  

NRG Energy, Inc. 

  $ 100.00   $ 118.87   $ 183.96   $ 99.02   $ 100.21   $ 82.94  

S&P 500

    100.00     115.79     122.16     79.96     97.33     111.99  

UTY

  $ 100.00   $ 120.19   $ 142.99   $ 103.98   $ 114.42   $ 120.94  

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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 recast to reflect the assets, liabilities and results of operations of certain projects that have met the criteria for treatment as discontinued operations as well as the retroactive effect of the two-for-one stock split effective May 25, 2007. For additional information refer to Item 15 — Note 4, Discontinued Operations and Dispositions, 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.

 
  Year Ended December 31,  
 
  2010   2009   2008   2007   2006  
 
  (In millions except ratios and per share data)
 

Statement of income data:

                               

Total operating revenues

  $ 8,849   $ 8,952   $ 6,885   $ 5,989   $ 5,585  

Total operating costs and expenses

    8,119     7,283     5,119     5,073     4,724  

Income from continuing operations, net

    476     941     1,053     556     539  

Income from discontinued operations, net

            172     17     78  

Net income attributable to NRG Energy, Inc. 

  $ 477   $ 942   $ 1,225   $ 573   $ 617  

Common share data:

                               

Basic shares outstanding — average

    252     246     235     240     258  

Diluted shares outstanding — average

    254     271     275     288     301  

Shares outstanding — end of year

    247     254     234     237     245  

Per share data:

                               

Income attributable to NRG from continuing operations — basic

  $ 1.86   $ 3.70   $ 4.25   $ 2.09   $ 1.89  

Income attributable to NRG from continuing operations — diluted

    1.84     3.44     3.80     1.90     1.76  

Net income attributable to NRG — basic

    1.86     3.70     4.98     2.16     2.19  

Net income attributable to NRG — diluted

    1.84     3.44     4.43     1.96     2.02  

Book value

  $ 32.65   $ 29.72   $ 26.75   $ 19.55   $ 19.60  

Business metrics:

                               

Cash flow from operations

  $ 1,623   $ 2,106   $ 1,479   $ 1,517   $ 408  

Liquidity position (a)

  $ 4,660   $ 3,971   $ 4,124   $ 2,715   $ 2,227  

Ratio of earnings to fixed charges

    2.00     3.27     3.65     2.24     2.36  

Ratio of earnings to fixed charges and preference dividends

    1.96     3.04     3.19     1.99     2.08  

Return on equity

    5.91 %   12.24 %   17.20 %   10.38 %   10.85 %

Ratio of debt to total capitalization

    42.94 %   43.49 %   47.50 %   55.58 %   57.18 %

Balance sheet data:

                               

Current assets

  $ 7,137   $ 6,208   $ 8,492   $ 3,562   $ 3,083  

Current liabilities

    4,220     3,762     6,581     2,277     2,032  

Property, plant and equipment, net

    12,517     11,564     11,545     11,320     11,546  

Total assets

    26,896     23,378     24,808     19,274     19,436  

Long-term debt, including current maturities, capital leases, and funded letter of credit

    10,511     8,418     8,161     8,346     8,698  

Total stockholders' equity

  $ 8,072   $ 7,697   $ 7,123   $ 5,519   $ 5,686  
(a)
Liquidity position is determined as disclosed in Item 7, Liquidity and Capital Resources, Liquidity Position. It includes funds deposited by counterparties of $408 million, $177 million and $754 million as of December 31, 2010, 2009, and 2008, respectively, which represents cash held as collateral from hedge counterparties in support of energy risk management activities. It is the Company's intention to limit the use of these funds for repayment of the related current liability for collateral received in support of energy risk management activities.

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        The following table provides the details of NRG's operating revenues:

 
  Year Ended December 31,  
 
  2010   2009   2008   2007   2006  
 
  (In millions)
 

Energy

  $ 2,854   $ 3,726   $ 4,408   $ 4,349   $ 1,770  

Capacity

    824     1,023     1,343     1,175     1,516  

Retail revenue

    5,277     4,440              

Mark-to-market activities

    (136 )   (290 )   525     (77 )   295  

Other revenue

    30     53     609     542     2,004  
                       

Total operating revenues

  $ 8,849   $ 8,952   $ 6,885   $ 5,989   $ 5,585  
                       

        Energy revenue consists of revenues received from third parties for sales in the day-ahead and real-time markets, as well as bilateral sales. Energy revenues also included revenues from the settlement of financial instruments.

        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 requirements. Capacity revenues also included revenues from the settlement of financial instruments. 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.

        Retail revenue, representing operating revenues of Reliant Energy and Green Mountain Energy, consists of revenues from retail electric sales to residential, small business, commercial, industrial and governmental/institutional customers, as well as revenues from the sale of excess supply into various markets in Texas.

        Mark-to-market activities includes fair value changes of economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges and trading activities.

        Other revenue includes the following components:

    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 and Texas Genco purchase accounting dates 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. Also included is amortization of the intangible asset for net in-market C&I contracts that was established in connection with the acquisition of Reliant Energy.

    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 also consists of operations and maintenance fees, or O&M fees, construction management services, or CMA 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. CMA fees are earned where NRG provides certain management and oversight of construction projects pursuant to negotiated agreements such as for the GenConn and Cedar Bayou 4 construction projects. 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

        The discussion and analysis below has been organized as follows:

    Executive Summary, including business strategy, the business environment in which NRG operates, how regulation, weather, competition and other factors affect the business, and significant events that are important to understanding the results of operations and financial condition for the 2010 period;

    Results of operations, including an explanation of significant differences between the periods in the specific line items of NRG's Consolidated Statements of Operations;

    Financial condition addressing credit ratings, liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements; 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.

        As you read this discussion and analysis, refer to NRG's Consolidated Statements of Operations to this Form 10-K, which presents the results of the Company's operations for the years ended December 31, 2010, 2009 and 2008, and also refer to Item I to this Form 10-K for more detailed discussion about the Company's business.

Executive Summary

    Business Strategy

        NRG is engaged in the ownership, development, construction and operation of power generation facilities; the transacting in and trading of fuel and transportation services; the trading of energy, capacity and related products in the United States and select international markets; and the supply of electricity, energy services, and cleaner energy and carbon offset products to retail electricity customers in deregulated markets through its retail subsidiaries Reliant Energy and Green Mountain Energy.

        The Company's core business is focused on: (i) excellence in safety and operating performance of its existing operating assets; (ii) serving the energy needs of end-use residential, commercial and industrial customers in our core markets; (iii) optimal hedging of baseload generation and retail load operations, while retaining optionality on the Company's gas fleet; (iv) repowering of power generation assets at existing sites and reducing environmental impacts; (v) pursuit of selective acquisitions, joint ventures, divestitures and investments; and (vi) engaging in a proactive capital allocation plan focused on achieving the regular return of and on shareholder capital within the dictates of prudent balance sheet management.

        In addition, the Company believes that it is well-positioned to capture the opportunities arising out of a long-term societal trend towards sustainability as a result of technological developments and new product offerings in "green" energy. The Company's initiatives in this area of future growth are focused on: (i) low carbon baseload — primarily nuclear generation; (ii) renewables, with a concentration in solar and wind generation and development; (iii) fast start, high efficiency gas-fired capacity in the Company's core regions; (iv) electric vehicle ecosystems; and (v) smart grid services.

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    Business Environment

        The industry dynamics and external influences affecting the Company and the power generation industry in 2010 and for the future medium term include:

        Consolidation — There were several mergers and acquisitions in the U.S. power sector in 2010. Over the long term, industry consolidation is expected to continue.

        Environmental Landscape — A number of regulations that could significantly impact the power generation industry are in development or under review by the U.S. EPA: CAIR/CATR, NSPS for GHGs, MACT, NAAQS revisions, coal combustion byproducts, and once-through cooling. While most of these regulations have been considered for some time, they are expected to gain clarity in 2011 through 2012. The timing and stringency of these regulations will provide a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. The Company has included capital to meet anticipated CAIR Phase I and II, proposed CATR, MACT standards for mercury, and the installation of BTA under the 316(b) Rule in the current estimated environmental capital expenditure. The Company cannot predict the impact of future regulations and could face additional investments over time. However, NRG believes it is positioned to meet more stringent requirements through its planned capital expenditures, existing controls, and the use of Powder River Basin coal.

        Public Policy Support and Government Financial Incentives for Clean Infrastructure Development — Policy mechanisms including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, renewable portfolio standards, or RPS, and carbon trading plans have been implemented at the state and federal levels to support the development of renewable generation, demand-side and smart grid, nuclear, and other clean infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics of the Company's development program and expansion into clean energy investments.

        Natural Gas Market — The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Natural gas prices are driven by variables including demand from the industrial, residential, and electric sectors, productivity across natural gas supply basins, costs of natural gas production, changes in pipeline infrastructure, and the financial and hedging profile of natural gas consumers and producers. In 2010, settled natural gas prices were higher compared to 2009, but remain below levels experienced in 2008 and earlier as supply continued to reflect increased production from low-extraction-cost resources, particularly the shale basins. The supply chain has pressured forward prices, which decreased from 2009 to 2010. The Company expects rebalancing of the natural gas market to be driven primarily by the supply roll-off of producer hedges, reduced availability of financing to support drilling incremental wells, and strong gas demand growth from the power sector when proposed environmental regulations induce widespread coal-fired power plant retirements.

        Electricity Price — The price of electricity is a key determinant of the profitability of the Company's generation portfolio. In 2010 prices for electricity were higher than in 2009 affected by higher prices for natural gas as well as higher electric demand due to hot summer weather in many parts of the United States and continued economic recovery. The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the years ended December 31, 2010, 2009, and 2008:

 
  Average on Peak Power Price ($/MWh)  
Region
  2010   2009   2008  

Texas

  $ 40.40   $ 35.43   $ 86.23  

Northeast

    56.69     46.14     91.68  

South Central

    40.25     33.58     71.25  

West

    40.05     39.70     82.20  

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    Weather

        Weather conditions in the regions of the United States in which NRG does business influence the Company's financial results. 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;

    capability and reliability of the physical electricity and gas systems;

    local transportation systems; and

    the nature and extent of electricity deregulation.

    Environmental Matters, Regulatory Matters and Legal Proceedings

        NRG discusses details of its other environmental matters in Item 15 — Note 24, Environmental Matters, to the Consolidated Financial Statements and Item 1, Business — Environmental Matters, section. NRG discusses details of its regulatory matters in Item 15 — Note 23, Regulatory Matters, to the Consolidated Financial Statements and Item 1, Business — Regulatory Matters, section. NRG discusses details of its legal proceedings in Item 15 — Note 22, Commitments and Contingencies, to these Consolidated Financial Statements. Some of this information relates to 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, 2010, 2009 and 2008, the impact of inflation and changing prices (due to changes in exchange rates) on NRG's revenues and income from continuing operations was immaterial.

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Significant events during the year ended December 31, 2010

    Results of Operations and Financial Condition

    Lower net income — Net income decreased by 49% from $941 million to $476 million, which reflects a decrease in gross margin for Reliant Energy driven by fewer customers and price reductions, as well as a decrease in results from the wholesale power generation regions due to lower hedge prices and increased fuel and transportation costs.

    Liquidity position — The Company's total liquidity, excluding collateral received, rose $458 million in 2010. Cash balances grew by $647 million since the end of 2009 as operating activities provided $1.6 billion of cash and the proceeds from the issuance of debt provided $1.5 billion. These increases were offset in part by $706 million of capital expenditures, $758 million in debt payments, $180 million in treasury share repurchases, and $1.0 billion in cash used for business acquisitions.

    Acquisition of businesses — Businesses acquired during 2010 added $88 million in revenue and $48 million in cost of sales to the Company's 2010 results. For further discussion see Item 15 — Note 3 — Business Acquisitions, to the Consolidated Financial Statements.

    Long-term debt — In June 2010, NRG completed an amendment and extension of its Senior Credit Facility, resulting in an extension in the maturity of $1.0 billion of the outstanding Term Loan Facility to August 2015, a reduction in borrowing capacity and extension in maturity of the Revolving Credit Facility, and conversion of the synthetic letter of credit facility into an on-balance sheet term loan-backed funded letter of credit facility. Additionally, NRG issued $1.1 billion of 8.25% Senior Notes due 2020 in August 2010, executed a $190 million tax-exempt bond financing for its Indian River plant in October 2010 and an additional $57 million in December 2010, and entered into various other financing arrangements related to business acquisitions. For further discussion see Item 15 — Note 12 — Debt and Capital Leases, to the Consolidated Financial Statements.

    Other

    NINA — In March 2010, NINA acquired a controlling interest in the STP Units 3 and 4 Project through a settlement of the litigation with CPS. Additionally, in May 2010, TEPCO agreed to acquire up to a 20% interest in NINA Investment Holdings LLC, subject to certain conditions precedent. Further, in November 2010, NINA amended the TANE Facility to allow for additional indebtedness and entered into the Shaw Facility to finance working capital needs and the expenses of Shaw and its subsidiaries for the design, construction, engineering and services incurred in the construction of STP Units 3 and 4. See Item 15 — Note 12 — Debt and Capital Leases and Note 22 — Commitments and Contingencies, to the Consolidated Financial Statements for further discussion.

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Consolidated Results of Operations

    2010 compared to 2009

        The following table provides selected financial information for NRG Energy, Inc., for the years ended December 31, 2010, and 2009:

 
  Year Ended December 31,    
 
(In millions except otherwise noted)
  2010   2009   Change %  

Operating Revenues

                   
 

Energy revenue (a)

  $ 2,854   $ 3,726     (23 )%
 

Capacity revenue (a)

    824     1,023     (19 )
 

Retail revenue

    5,277     4,440     19  
 

Mark-to-market activities

    (136 )   (290 )   53  
 

Other revenue

    30     53     (43 )
                 
   

Total operating revenues

    8,849     8,952     (1 )
                 

Operating Costs and Expenses

                   
 

Generation cost of sales (a)

    2,153     1,882     14  
 

Retail cost of sales (a)

    2,822     3,121     (10 )
 

Mark-to-market activities

    (111 )   (842 )   87  
 

Other cost of operations

    1,209     1,162     4  
                 
   

Total cost of operations

    6,073     5,323     14  
                 
 

Depreciation and amortization

    838     818     2  
 

Selling, general and administrative

    598     550     9  
 

Reliant Energy acquisition-related transaction and integration costs

        54     (100 )
 

Development costs

    55     48     15  
                 
   

Total operating costs and expenses

    7,564     6,793     11  
 

Gain on sale of assets

    23         N/A  
                 

Operating income

    1,308     2,159     (39 )
                 

Other Income/(Expense)

                   
 

Equity in earnings of unconsolidated affiliates

    44     41     7  
 

Gain on sale of equity method investments

        128     (100 )
 

Other income/(expense), net

    33     (5 )   N/A  
 

Refinancing expenses

        (20 )   (100 )
 

Interest expense

    (632 )   (634 )    
                 
   

Total other expense

    (555 )   (490 )   13  
                 

Income before income tax expense

    753     1,669     (55 )
 

Income tax expense

    277     728     (62 )
                 

Net Income

    476     941     (49 )
 

Less: Net loss attributable to noncontrolling interest

    (1 )   (1 )    
                 

  Net income attributable to NRG Energy, Inc

  $ 477   $ 942     (49 )
                 

Business Metrics

                   

Average natural gas price — Henry Hub ($/MMBtu)

    4.39     3.92     12 %
(a)
Includes realized gains and losses from financially settled transactions.

N/A — Not applicable

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Management's discussion of the results of operations for the years ended December 31, 2010, and 2009

    Wholesale Power Generation Revenues and Cost of Sales

        The following is a more detailed discussion of the energy and capacity revenues and generation cost of sales for NRG's wholesale power generation regions, adjusted to eliminate intersegment activity primarily with Reliant Energy.

 
  Year Ended December 31, 2010  
(In millions except otherwise noted)
  Texas   Northeast   South Central   West   Other   Total
Wholesale
Power
Generation
  Eliminations   Consolidated
Total
 
 

Energy revenue

  $ 2,850   $ 726   $ 387   $ 31   $ 46   $ 4,040   $ (1,186 ) $ 2,854  
 

Capacity revenue

    25     396     235     113     71     840     (16 )   824  
 

Generation cost of sales

    1,139     493     403     15     103     2,153         2,153  

Business Metrics

                                                 
 

MWh sold (in thousands)

    46,926     10,581     13,046     269                          
 

MWh generated (in thousands)

    44,700     9,355     11,168     269                          
 

Average on-peak market power prices ($/MWh)

  $ 40.40   $ 56.69   $ 40.25   $ 40.05                          

 

 
  Year Ended December 31, 2009  
(In millions except otherwise noted)
  Texas   Northeast   South Central   West   Other   Total
Wholesale
Power
Generation
  Eliminations   Consolidated
Total
 
 

Energy revenue

  $ 2,770   $ 873   $ 367   $ 26   $ 51   $ 4,087   $ (361 ) $ 3,726  
 

Capacity revenue

    193     407     269     122     79     1,070     (47 )   1,023  
 

Generation cost of sales

    948     408     387     29     110     1,882         1,882  

Business Metrics

                                                 
 

MWh sold (in thousands)

    47,259     9,220     12,144     386                          
 

MWh generated (in thousands)

    44,993     9,220     10,398     386                          
 

Average on-peak market power prices ($/MWh)

  $ 35.43   $ 46.14   $ 33.58   $ 39.70                          

 

 
  Year Ended December 31,    
   
   
   
 
 
  Texas   Northeast   South Central   West    
   
   
   
 

Weather Metrics

                                                 

2010

                                                 
 

CDDs (a)

    2,884     850     2,006     678                          
 

HDDs (a)

    2,161     5,720     3,929     2,753                          

2009

                                                 
 

CDDs

    2,881     475     1,549     908                          
 

HDDs

    1,890     6,286     3,521     3,105                          

30 year average

                                                 

CDDs

    2,647     537     1,548     704                          

HDDs

    1,997     6,262     3,604     3,228                          
(a)
National Oceanic and Atmospheric Administration-Climate Prediction Center — A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.

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    Energy revenue — decreased $872 million, on a consolidated basis, during the year ended December 31, 2010, compared to the same period in 2009. Including intercompany sales, energy revenue for Wholesale Power Generation decreased by $47 million, due to:

    o
    Northeast — decreased by $147 million, driven by a decrease of $185 million, or 22% in realized energy prices and a decrease of $32 million of margin on megawatt hours sold from market purchase for certain load contracts which expired in May 2009 and 2010. These decreases were offset by an increase of $58 million driven by new load-serving contracts, which commenced June 1, 2010. In addition, generation increased by $12 million, or 1%, driven by a small increase in oil and gas plant generation offset by a small decrease in coal plant generation.

      This decrease in energy revenue was offset in part by:

      o
      Texas — increased by $80 million, with an increase of $113 million driven by 4% higher average realized energy prices. The realized higher energy prices are a result of increased contract prices per MWh, offset in part by lower realized merchant energy such that overall energy prices increased. The increase in overall energy prices was offset by a decrease in generation of 1% or $32 million. This decrease in generation was driven by a decrease in baseload generation due to maintenance outages and a decrease in gas plant generation, offset by an increase in owned wind farm generation as Langford wind facilities began commercial operations in December 2009 and South Trent was acquired in June 2010.

      o
      South Central — increased by $20 million due to a $70 million increase in contract revenue attributable to the region's cooperative customers from fuel cost pass-through which contributed $24 million, increased volume of $14 million and an additional $32 million from a new contract with a regional municipality. These increases were offset by a $50 million decrease in merchant revenue of which $37 million is due to lower average realized prices and $13 million resulted from lower volumes.

      o
      West — increased by $5 million primarily due to incremental revenue from the commencement of operations at Blythe and an increase in realized energy prices, offset by a decrease in generation.

    Capacity revenue — decreased $199 million, on a consolidated basis, during the year ended December 31, 2010, compared to the same period in 2009. Including intercompany sales, capacity revenue for Wholesale Power Generation decreased by $230 million:

    o
    Texas — decreased by $168 million due to a lower proportion of baseload contracts which contain a capacity component. Intercompany capacity revenue to Reliant Energy, which eliminate in consolidation, decreased by $31 million.

    o
    Northeast — decreased by $11 million, due to a $44 million decrease in revenue from NEPOOL capacity driven by the expiration of RMR contracts for the Montville, Middletown and Norwalk plants in 2010, a decrease in capacity pricing for the winter months and lower volume of capacity sales due to the retirement of the Somerset coal facility starting January 1, 2010. This decrease was offset by a $30 million increase in capacity revenue in the NYISO market driven in part by the retirement of the New York Power Authority's Poletti facility in January 2010.

    o
    South Central — decreased by $34 million due to the expiration of a capacity agreement with a regional utility.

    o
    West — decreased by $9 million due to reduced resource adequacy and call option contract sales at El Segundo in 2010 as compared to 2009.

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    Generation cost of sales — increased $271 million during the year ended December 31, 2010, compared to the same period in 2009:

    o
    Texas — increased $191 million due to higher coal and natural gas costs, an increase in purchased energy, and higher ancillary services costs.

    Coal costs increased by $62 million due to a $76 million increase in transportation cost offset by a $15 million decrease related to lower volume.

    Natural gas costs increased $15 million, reflecting a 16% increase in average natural gas prices offset by an 8% decrease in gas-fired generation.

    Costs of purchased energy increased by $61 million for increased obligations when baseload plants are unavailable and additional purchases for bilateral and toll energy agreements.

    Ancillary service costs increased by $26 million due to an increase in purchased ancillary costs incurred to meet obligations, primarily for Reliant Energy.

    Emission credit expense increased by $13 million reflecting a 2-to-1 increase in SO2 credits required by the amended CAIR rules as compared to the same period in 2009.

    ERCOT nodal fees increased by $9 million due to higher nodal surcharge to generators for the full year 2010.

    o
    Northeast — increased by $85 million due to an increase in purchased energy costs, coal costs and natural gas and oil costs.

    Costs of purchased energy increased by $53 million related to new load-serving contracts, which commenced June 1, 2010.

    Coal costs increased by $15 million due to a 6% increase in average prices.

    Natural gas costs increased by $20 million due to a 15% increase in average prices and an increase in generation.

    o
    South Central — increased by $16 million due to an increase in natural gas costs, coal costs and transmission costs offset by lower costs of purchased energy.

    Natural gas costs increased by $9 million due to a 138% increase in generation resulting from the Cottonwood acquisition.

    Coal costs increased by $7 million due to a 5% increase in generation offset by lower average contracted prices.

    Transmission costs increased by $5 million due to higher volumes into and out of the MISO region.

          These increases in South Central were offset by:

        Costs of purchased energy decreased by $5 million due to a $9 million decrease in purchased capacity from Cottonwood which was acquired in November 2010 and accounted for as owned generation, offset by an increase in MWhs purchased and average prices.

      These increases in generation cost of sales were offset by:

      o
      West — decreased by $14 million due to a 55% decrease in natural gas consumption partially offset by a 21% increase in average natural gas prices per MMBtu.

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    Retail Revenues and Cost of Sales

        The Company's retail revenues and retail cost of sales include the results of NRG's Reliant Energy business segment, as well as the results of Green Mountain Energy for the period November 5, 2010 (acquisition date) to December 31, 2010, which is included in NRG's Corporate business segment.

    Reliant Energy

        The following is a detailed discussion of retail revenues and costs of sales for NRG's Reliant Energy business segment.

(In millions except otherwise noted)
  Year ended
December 31, 2010
  Four months ended
April 30, 2010
  Eight months ended
December 31, 2010
  Eight months ended
December 31, 2009 (d)
 

Retail Revenues

                         
 

Mass revenues

  $ 3,076   $ 903   $ 2,173   $ 2,597  
 

Commercial and Industrial revenues

    1,976     640     1,336     1,592  
 

Supply management revenues

    158     56     102     251  
                   
   

Total retail operating revenues (a)

    5,210     1,599     3,611     4,440  
 

Retail cost of sales (b)

    4,020     1,232     2,788     3,531  
                   
     

Total retail gross margin

  $ 1,190   $ 367   $ 823   $ 909  
                   

Business Metrics

                         
 

Electricity sales volume — GWh

                         
   

Mass

    22,255     6,089     16,166     17,152  
   

Commercial and Industrial (a)

    26,124     8,268     17,856     20,915  
 

Average retail customers count (in thousands, metered locations)

                         
   

Mass

    1,490     1,519     1,475     1,566  
   

Commercial and Industrial (a)

    63     64     62     68  
 

Retail customers count (in thousands, metered locations)

                         
   

Mass

    1,459     1,513     1,459     1,531  
   

Commercial and Industrial (a)

    62     64     62     66  

Weather Metrics

                         
 

CDDs (c)

    3,305     166     3,139     2,972  
 

HDDs (c)

    1,812     1,267     545     699  
(a)
Includes customers of the Texas General Land Office, for whom the Company provides services.
(b)
Includes intercompany purchases from the Texas region of $1,241 million, $293 million, $948 million and $409 million, respectively.
(c)
The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Reliant Energy serves its customer base.
(d)
For the period May 1, 2009, to December 31, 2009.
    Retail gross margin — excluding gross margin of $367 million for the first four months of 2010, Reliant Energy's gross margin decreased $86 million for the comparable eight month period for both years. This was due to a $215 million decrease from 18% lower Mass margins driven by lower unit margins on acquisitions and renewals and price reductions for certain customer segments as well as 6% lower Mass volumes sold driven by fewer customers. In conjunction with the CSRA unwind, out-of-market supply contracts were terminated and a realized loss of $89 million was reflected in 2009 margin. Also, the 2010 gross margin reflects approximately $40 million lower supply costs related to the terminated contracts. Competition and lower unit margins on acquisitions and renewals could drive lower gross margin in the future.

        The following table reconciles Reliant Energy's retail gross margin to operating income/(loss):

(In millions)
  Year ended
December 31, 2010
  Four months ended
April 30, 2010
  Eight months ended
December 31, 2010
  Eight months ended
December 31, 2009
 

Total Retail gross margin

  $ 1,190   $ 367   $ 823   $ 909  
 

Mark-to-market results on energy supply derivatives

    (49 )   (249 )   200     794  
 

Contract amortization, net

    (183 )   (79 )   (104 )   (209 )
 

Other operating expenses

    (478 )   (140 )   (338 )   (356 )
 

Depreciation and amortization

    (117 )   (39 )   (78 )   (137 )
                   

Operating Income/(loss)

  $ 363   $ (140 ) $ 503   $ 1,001  
                   

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    Retail operating revenues — increased by $770 million during the year ended December 31, 2010, as compared to the eight months ended December 31, 2009. For the comparable eight month period for both years, operating revenues decreased by $829 million due to:

    o
    Mass revenues — excluding revenues of $903 million for the first four months of 2010, Mass revenues decreased by $424 million for the comparable eight month period for both years, with a decrease of $247 million due to lower revenue rates driven by lower revenue pricing on acquisitions and renewals consistent with competitive offers and price reductions for certain customer segments. In addition, a decrease of $166 million was due to 6% lower volumes which reflect 0.4% monthly net customer attrition in 2010 from increased competition. Net attrition in 2009 was 0.7%. Favorable weather in both periods resulted in 7% higher customer usage in 2010 and 5% in 2009 when compared to ten-year normal weather.

    o
    Commercial and Industrial revenue — excluding revenues of $640 million for the first four months of 2010, C&I revenues decreased by $256 million for the comparable eight month period for both years. This decrease was due to 15% lower volumes driven by fewer customers in 2010, which result from fewer new customer acquisitions and fewer contract renewals during the 2010 renewal period as the suspension of C&I contracting in late 2008 and early 2009 continued to have an impact on renewals.

    Retail cost of sales — increased by $489 million for the year ended December 31, 2010, as compared to the eight months ended December 31, 2009. For the comparable eight month period for both years, cost of sales decreased by $743 million due to:

    o
    Supply costs and financial costs of energy — including intercompany purchases from the Texas region of $1,241 million and $409 million in 2010 and 2009 respectively, and excluding supply costs of $839 million for the first four months of 2010, supply costs decreased by $675 million for the comparable eight month period in both years. This decrease is due to a $579 million decrease attributed to 20% lower hedged prices, a $225 million decrease due to 11% lower volumes driven by fewer customers, and a favorable impact of $129 million, comprised of an estimated $40 million favorable impact in 2010 and an $89 million unfavorable impact in 2009 for out-of-market supply contracts terminated in the fourth quarter of 2009 in conjunction with the CSRA unwind. The terminated contract value for January through April 2010 was an estimated $34 million. 

    o
    Transmission and distribution charges — excluding transmission and distribution costs of $393 million for the first four months of 2010, transmission and distribution charges decreased by $68 million for the comparable eight month period for both years. This decrease was due to a $93 million decrease from lower volumes transported and sold to customers in 2010 compared to 2009, which was offset by a $25 million increase due to higher rates billed by CenterPoint Energy for system restoration charges from the damage caused by Hurricane Ike effective December 2009.

    Green Mountain Energy

        Green Mountain Energy recorded $69 million in retail revenues and $46 million in retail cost of sales for the period November 5, 2010, to December 31, 2010.

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    Mark-to-market Activities

        Mark-to-market activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Total net mark-to-market results decreased by $577 million in the year ended December 31, 2010, compared to the same period in 2009.

        The breakdown of gains and losses included in operating revenues and operating costs and expenses by region are as follows:

 
  Year Ended December 31, 2010  
 
  Reliant
Energy
  Texas   Northeast   South
Central
  West   Thermal   Corporate (a)   Elimination (b)   Total  
 
  (In millions)
 

Mark-to-market results in operating revenues

                                                       

Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges

  $ (1 ) $ (68 ) $ (108 ) $ 2   $   $ (2 ) $   $ 11   $ (166 )

Reversal of previously recognized unrealized losses on settled positions related to trading activity

        46     11     11                     68  

Net unrealized gains/(losses) on open positions related to economic hedges

        125     (36 )   (47 )   (4 )           (71 )   (33 )

Net unrealized (losses)/gains on open positions related to trading activity

        (12 )   9     (4 )   2                 (5 )
                                       

Total mark-to-market (losses)/gains in operating revenues

  $ (1 ) $ 91   $ (124 ) $ (38 ) $ (2 ) $ (2 ) $   $ (60 ) $ (136 )
                                       

Mark-to-market results in operating costs and expenses

                                                       

Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges

  $ (60 ) $ 36   $ 13   $ 17   $   $   $   $ (11 ) $ (5 )

Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009

    223                                 223  

Reversal of loss positions acquired as part of the Green Mountain Energy acquisition as of November 5, 2010

                            13         13  

Net unrealized (losses)/gains on open positions related to economic hedges

    (210 )   (2 )   5     4             12     71     (120 )
                                       

Total mark-to-market (losses)/gains in operating costs and expenses

  $ (47 ) $ 34   $ 18   $ 21   $   $   $ 25   $ 60   $ 111  
                                       
(a)
Corporate segment consists of Green Mountain Energy activity.
(b)
Represents the elimination of the intercompany activity between the Texas and Reliant Energy regions.

        Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

        For the year ended December 31, 2010, the $33 million loss in operating revenue from economic hedge positions was primarily driven by a decrease in value of forward purchases and sales of natural gas and electricity due to a decrease in forward power and gas prices. The $120 million loss in operating costs and expenses from economic hedge positions was primarily driven by a decrease in value of forward purchases of natural gas, electricity and fuel due to a decrease in forward power and gas prices. Reliant Energy's $223 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of May 1, 2009, and valued using forward prices on that date. These roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period. Green Mountain Energy's $13 million gain from the roll-off of acquired derivatives consists of loss positions that were acquired as of November 5, 2010, and valued using forward prices on that date. These roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

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        In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 2010, and 2009. The unrealized financial and physical trading results are included in the mark-to-market activities above, while the realized financial and physical trading results are included in energy and capacity revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.

 
  Year Ended December 31,  
 
  2010   2009  
 
  (In millions)
 

Trading gains/(losses)

             

  Realized

  $ (25 ) $ 216  

  Unrealized

    64     (183 )
           

Total trading gains

  $ 39   $ 33  
           

Other Revenues

 
  Reliant
Energy
  Texas   Northeast   South
Central
  West   Thermal   Other   Total  
 
  (In millions)
 

Year Ended December 31, 2010

  $ (219 ) $ 91   $ 27   $ 24   $ 2   $ 145   $ (40 ) $ 30  

Year Ended December 31, 2009

  $ (258 ) $ 85   $ 28   $ 23   $ 2   $ 137   $ 36   $ 53  

        Other revenues decreased by $23 million during the year ended December 31, 2010, as compared to the same period in 2009. This decrease was driven by $16 million in lower contract amortization revenue primarily due to a reduction in the Texas region due to the roll-off of out-of-market contracted energy sales valued under purchase accounting, offset partially by an increase for Reliant Energy due to an additional four months of contract amortization in 2010. In addition, other revenues decreased due to a $31 million non-cash gain related to the settlement of a pre-existing in-the-money contract with Reliant Energy that was recognized in 2009. Thermal revenue increased as a result of the acquisition of Northwind Phoenix in 2010.

    Other Operating Costs

 
  Reliant
Energy
  Texas   Northeast   South
Central
  West   Thermal   Other   Total  
 
  (In millions)
 

Year Ended December 31, 2010

  $ 157   $ 501   $ 287   $ 93   $ 65   $ 108   $ (2 ) $ 1,209  

Year Ended December 31, 2009

  $ 104   $ 511   $ 306   $ 80   $ 63   $ 101   $ (3 ) $ 1,162  

        Other operating costs increased $47 million during the year ended December 31, 2010, compared to the same period in 2009, due to:

    Reliant Energy — increased due to the additional four months of other operating costs of $49 million included in 2010.

    Operations and maintenance expense — increased by $6 million due to the following:

    o
    South Central — increased by $12 million as the scope and duration of planned maintenance work at the region's coal facility was greater in 2010 than in the same period in 2009.

    o
    Thermal — increased by $6 million relating to Northwind Phoenix expenses since the acquisition date in 2010.

    o
    Texas — increased by $2 million which includes an increase in $8 million for maintenance work during baseload outages, offset by a net gain of $6 million related to several parcels of land that were sold or held for sale in 2010.

            These increases in operations and maintenance expense were offset by:

      o
      Reliant Energy — decreased by $11 million due to lower spending for external costs associated with customer activities including the call center, billing, remittance processing, and credit and collections as well as information technology costs associated with those activities.

      o
      Northeast — decreased by $6 million due to decreases in normal and major maintenance of $17 million as the Indian River, Arthur Kill and Dunkirk plants had major outages in 2009, offset by asset retirements of $8 million in 2010.

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        These increases in other operating costs were offset by the following:

    Property and other taxes — decreased $22 million due to the following:

    o
    Northeast — decreased $8 million due to a charge in June 2009 to reflect changes in Empire Zone regulations that eliminated the Oswego plant's ability to continue participation in the Empire Zone program.

    o
    Reliant Energy — decreased $10 million due to a decrease in gross receipts tax as a result of the decrease in retail revenues.

    o
    Texas — decreased $5 million due to a refund resulting from a sales and use tax audit.

    Depreciation and Amortization

        NRG's depreciation and amortization expense increased by $20 million during the year ended December 31, 2010, compared to the same period in 2009. An increase of $26 million was due to depreciation on the baghouse projects in western New York and additional depreciation at the Cedar Bayou plant, the Langford wind facilities and the Blythe solar facility. Cedar Bayou began commercial operation in June 2009 and the Langford wind facilities began commercial operation in December 2009. Further, an increase of $9 million was due to amortization expense at Green Mountain Energy after the date of acquisition.

        This increase was offset by an overall $20 million decrease in depreciation and amortization for Reliant Energy compared to the same period in 2009. Reliant Energy's depreciation and amortization expense decreased $59 million during the eight months ended December 31, 2010 as compared to the same period in 2009, which relates primarily to the amortization expense related to Mass customer relationships valued under purchase accounting which is recognized as the underlying contracts roll off. This decrease at Reliant Energy was offset by $39 million of additional depreciation and amortization expense for the first four months of 2010.

    Selling, General and Administrative Expenses

        Selling, general and administrative expenses increased by $48 million during the year ended December 31, 2010, compared to the same period in 2009. Excluding $68 million of additional expense for Reliant Energy in the first four months of 2010, selling, general and administrative expenses decreased by $20 million, due to:

    A decrease in bad debt expense of $20 million due to decreased revenues and improved customer payment behavior.

    Prior year non-recurring costs related to Exelon's exchange offer and proxy contest efforts of $31 million.

These decreases were offset by:

    Green Mountain Energy's costs of $10 million incurred since the acquisition date.

    The contribution of $8 million in funding for the Reliant Energy Charitable Foundation which was created in 2010.

    An increase in $8 million in professional services for various on-going projects in 2010.

    Reliant Energy Acquisition-Related Transaction and Integration Costs

        NRG incurred Reliant Energy acquisition-related transaction and integration costs of $54 million for 2009. These integration efforts were completed by the end of 2009.

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    Development Costs

        Development costs increased $7 million during the year ended December 31, 2010, compared to the same period in 2009 due to increased costs incurred primarily on NRG Solar development projects.

    Gain on Sale of Assets

        On January 11, 2010, NRG sold Padoma to Enel, recognizing a gain on sale of $23 million.

    Equity in Earnings of Unconsolidated Affiliates

        NRG's equity earnings from unconsolidated affiliates increased by $3 million during the year ended December 31, 2010, compared to the same period in 2009. The 2010 results included increased equity earnings of $15 million from Sherbino, which related to the fair value of a hedge, and $7 million from Gladstone. In 2009, NRG recognized equity earnings of $15 million from MIBRAG, which was sold in June 2009.

    Gain on Sale of Equity Method Investments and Other Income/(Loss), Net

        NRG's gain on sale of equity method investments in 2009 represents a $128 million gain on the sale of NRG's 50% ownership interest in MIBRAG.

    Other Income/(Expense), Net

        NRG's other income, net increased $38 million during the year ended December 31, 2010, compared to the same period in 2009 principally due to foreign exchange transactions. The 2010 amount included $5 million and $9 million of unrealized and realized foreign exchange gains, respectively. The 2009 amount included a $24 million loss on a forward contract for foreign currency executed to hedge the sale proceeds from the MIBRAG sale in 2009.

    Refinancing Expenses

        In 2009, NRG incurred a $20 million expense associated with the CSRA unwind with Merrill Lynch.

    Interest Expense

        NRG's interest expense decreased by $2 million during the year ended December 31, 2010, compared to the same period in 2009 due to the following:

 
  (In millions)  

Increase/(decrease) in interest expense

       
 

Increase for 2020 Senior Notes issued in August 2010

  $ 33  
 

Increase for 2019 Senior Notes issued in June 2009

    25  
 

Decrease due to settlement of the CSF Debt in 2009 and early 2010

    (26 )
 

Decrease in fees incurred on the CSRA facility

    (26 )
 

Decrease in capitalized interest

    2  
 

Decrease due to Term Loan balance reduction in 2010

    (9 )
 

Other

    (1 )
       

Total

  $ (2 )
       

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    Income Tax Expense

        Income tax expense decreased by $451 million for the year ended December 31, 2010, compared to 2009. The effective tax rate was 36.8% and 43.6% for the year ended December 31, 2010, and 2009, respectively.

 
  Year Ended December 31,  
 
  2010   2009  
 
  (In millions
except as otherwise stated)

 

Income from continuing operations before income taxes

  $ 753   $ 1,669  
           

Tax at 35%

    264     584  

State taxes, net of federal benefit

    18     23  

Foreign operations

    (3 )   (53 )

Federal and state tax credits

    (7 )    

Valuation allowance

    (34 )   119  

Expiration of capital losses

        249  

Reversal of valuation allowance on expired capital losses

        (249 )

Change in state effective tax rate

        (5 )

Foreign earnings

    17     33  

Non-deductible interest

    4     10  

Interest accrued on uncertain tax positions

    25     9  

Production tax credits

    (11 )   (10 )

Other

    4     18  
           

Income tax expense

  $ 277   $ 728  
           

Effective income tax rate

    36.8 %   43.6 %

        The Company's effective tax rate differs from the U.S. statutory rate of 35% due to:

    Valuation Allowance — The Company generated capital gains in 2010 primarily due to the derivative contracts that are treated as capital items for tax purposes. The valuation allowance is recorded primarily against capital loss carryforwards, this resulted in a decrease of $34 million in income tax expense in 2010.

    Tax Expense Reduction — The Company recorded a lower federal and state tax expense of $325 million primarily due to lower pre-tax earnings.

    Foreign Operations — In 2010, the Company had earnings from its foreign operations that were subject to tax in the United States, resulting in an increase in tax expense of $17 million.

        The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC-740, Income Taxes, or ASC 740. These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

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Consolidated Results of Operations

    2009 compared to 2008

        The following table provides selected financial information for NRG Energy, Inc., for the years ended December 31, 2009, and 2008:

 
  Year Ended December 31,    
 
(In millions except otherwise noted)
  2009   2008   Change %  

Operating Revenues

                   
 

Energy revenue (a)

  $ 3,726   $ 4,408     (15 )%
 

Capacity revenue (a)

    1,023     1,343     (24 )
 

Retail revenue

    4,440         N/A  
 

Mark-to-market activities

    (290 )   525     (155 )
 

Other revenue

    53     609     (91 )
                 
   

Total operating revenues

    8,952     6,885     30  
                 

Operating Costs and Expenses

                   
 

Generation cost of sales (a)

    1,882     2,576     (27 )
 

Retail cost of sales (a)

    3,121         N/A  
 

Mark-to-market activities

    (842 )       N/A  
 

Other cost of operations

    1,162     1,022     14  
                 
   

Total cost of operations

    5,323     3,598     48  
                 
 

Depreciation and amortization

    818     649     26  
 

Selling, general and administrative

    550     319     72  
 

Acquisition-related transaction and integration costs

    54         N/A  
 

Development costs

    48     46     4  
                 
   

Total operating costs and expenses

    6,793     4,612     47  
                 

Operating income

    2,159     2,273     (5 )
                 

Other Income/(Expense)

                   
 

Equity in earnings of unconsolidated affiliates

    41     59     (31 )
 

Gain on sale of equity method investments

    128         N/A  
 

Other income/(expense), net

    (5 )   17     (129 )
 

Refinancing expenses

    (20 )       N/A  
 

Interest expense

    (634 )   (583 )   9  
                 
   

Total other expense

    (490 )   (507 )   (3 )
                 

Income from Continuing Operations before income tax expense

    1,669     1,766     (5 )
 

Income tax expense

    728     713     2  
                 

Income from Continuing Operations

    941     1,053     (11 )
 

Income from discontinued operations, net of income tax expense

        172     (100 )
                 

Net Income

    941     1,225     (23 )
 

Less: Net loss attributable to noncontrolling interest

    (1 )       N/A  
                 

 Net income attributable to NRG Energy, Inc

  $ 942   $ 1,225     (23 )
                 

Business Metrics

                   

Average natural gas price — Henry Hub ($/MMBtu)

    3.92     8.85     (56 )%
(a)
Includes realized gains and losses from financially settled transactions.

N/A — Not applicable

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Management's discussion of the results of operations for the years ended December 31, 2009, and 2008

    Wholesale Power Generation

        The following is a more detailed discussion of the energy and capacity revenues and generation cost of sales for NRG's wholesale power generation regions, adjusted to eliminate intersegment activity primarily with Reliant Energy.

 
  Year Ended December 31, 2009  
(In millions except otherwise noted)
  Texas   Northeast   South Central   West   Other   Total
Wholesale
Power
Generation
  Eliminations   Consolidated
Total
 
 

Energy revenue

  $ 2,770   $ 873   $ 367   $ 26   $ 51   $ 4,087   $ (361 ) $ 3,726  
 

Capacity revenue

    193     407     269