UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

Commission file No. 001-15891

     NRG Energy, Inc.
(Exact name of registrant as specified in its charter)

(609) 524-4500
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

     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.

     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.

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

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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:

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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:

(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.

        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:

        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:

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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:

        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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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.

(c)

For the period May 1, 2009, to December 31, 2009.

(d)

Energy revenues include inter-segment sales between Texas and Reliant Energy.

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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:

 

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

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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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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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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        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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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.

        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.

        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 NO_x. 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 NO_x Reasonably Available Control Technology, or RACT, Rule on July 14, 2010. This rule identifies new NO_x 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, NO_x, 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:

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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:

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

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:

        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:

        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

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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

        

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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.

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

        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:

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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:

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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.

 

 

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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.

•

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):

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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:

        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.

Other Revenues

        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

        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:

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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.

        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:

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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.

 

 

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•

Energy revenue — decreased $682 million during the year ended December 31, 2009, compared to the same period in 2008. Including intercompany sales to Reliant Energy, energy revenue for Wholesale Power Generation decreased by $321 million, due to:



o

Texas — decreased $5 million as generation decreased by 2% resulting in a $44 million decrease in sales volume and as margin on MWh sold from market purchases decreased by $22 million compared to the same period in 2008. The decrease in generation was driven by a 9% decrease in coal plant generation offset by a 12% increase in gas plant generation and owned and leased wind farm generation. These increases are inclusive of the recently constructed Cedar Bayou 4 gas plant, the Elbow Creek wind farm, and the Langford wind farm which began commercial operations in June 2009, December 2008 and December 2009, respectively. Coal plant generation was adversely affected by lower energy prices driven by a 56% decrease in average natural gas prices in combination with increased wind generation in the region. These decreases were offset in part by an increase in energy prices of $39 million compared to the same period in 2008 due to the average realized energy price increasing 1%.



o

Northeast — decreased by $203 million due to a decrease of $338 million in generation in 2009 compared to 2008, driven by a 31% decrease in coal generation and a 31% decrease in oil and gas generation. Coal generation declined 24%, or 1,471,726 MWhs, in western New York; 39%, or 1,503,975 MWhs, at Indian River; and 80%, or 476,537 MWh, at Somerset. The decline in generation at these plants was due to a combination of weakened demand for power, low merchant gas prices and higher cost of production from the introduction of RGGI resulting in increased hours where the units were uneconomic to dispatch. The decline in oil and gas generation was attributable to fewer reliability run hours at the Norwalk plant and higher maintenance work at the Arthur Kill plant in 2009. This decrease was offset by an increase in energy prices of $80 million reflecting an average 11% rise in hedged energy prices and an increase of $54 million in margin on MWh sold from market purchases driven by lower net costs incurred in meeting obligations under load serving contracts in the PJM market.



o

South Central — decreased by $95 million due to a $80 million decline in contract revenue and a $15 million decrease in merchant energy revenue. The contract revenue decrease was attributed to a 10% decrease in sales volumes and a $5.15 per MWh lower average realized price. The decline in contract energy price was driven by a $16 million decrease in fuel cost pass-through to the cooperatives reflecting an overall decline in natural gas prices. Also contributing to the decline in contract revenue was a $60 million decrease due to the expiration of a contract with a regional utility. The expiration of the contract allowed more energy to be sold into the merchant market, but at lower prices resulting in the $15 million decline in merchant revenue.



o

West — decreased by $13 million due to a 16% decrease in merchant prices in 2009 compared to 2008. This decrease was offset by a 5% increase in merchant generation in 2009 compared to 2008.



•

Capacity revenue — decreased $320 million during the year ended December 31, 2009, compared to the same period in 2008. Including intercompany sales, capacity revenue for Wholesale Power Generation decreased by $273 million:



o

Texas — decreased by $300 million due to a lower proportion of baseload contracts which contain a capacity component.



o

South Central — increased by $36 million driven by a $40 million increase from new capacity agreements with regional utilities and a $5 million increase in capacity revenue contributed by the region's Rockford plants which dispatch into the PJM market, offset by reduced contract capacity revenue of $9 million.

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•

Generation cost of sales — decreased $694 million in the year ended December 31, 2009, compared to the same period in 2008 due to:



o

Texas — decreased $305 million due to a decrease in natural gas costs and ancillary service costs, offset by an increase in coals costs.



•

Natural gas costs — decreased by $281 million due to a 56% decline in average natural gas prices offset by a 12% increase in gas-fired generation.



•

Ancillary service costs — decreased by $44 million due to a decrease in purchased ancillary services costs incurred to meet contract obligations.



•

Coal costs — increased by $25 million driven by a $64 million increase in coal prices, offset by a $28 million decrease in coal volume. Additionally, an increase in higher transportation costs of $9 million was offset by a $15 million loss reserve related to a coal contract dispute in the first quarter of 2008, combined with a decrease of $3 million due to lower lignite royalties.



o

Northeast — decreased $287 million due to a decrease in natural gas and oil costs and a decrease in coal costs, offset in part by an increase in carbon emission expense.



•

Natural gas and oil costs — decreased by $187 million, or 60%, due to 31% lower generation and 56% lower average natural gas prices.



•

Coal costs — decreased by $129 million, or 35%, due to lower coal generation of 31% accounting for $111 million and lower prices accounting for $18 million. The lower prices are due to lower fuel transportation surcharges.



•

Carbon emission expense — increased by $22 million due to the January 1, 2009, implementation of RGGI and the recognition of carbon compliance cost under this program.



o

South Central — cost of energy decreased $81 million due primarily to a decline in purchased energy and a decrease in natural gas expense as well as decreases in coal and transmission expenses.



•

Purchased energy — declined by $58 million while purchased capacity rose by $3 million. The lower purchased energy was driven by lower fuel costs associated with the region's tolled facility and lower market energy prices. The energy declines were offset by increased capacity payments of $3 million on tolled facilities.



•

Natural gas expense — decreased by $15 million reflecting a 30% drop in owned gas generation and a 54% decline in gas prices. The region's gas facilities ran extensively to support transmission system stability following hurricane Gustav in September 2008.



•

Coal expense — decreased $2 million as coal generation was down 6%, offset by a 6% increase in cost per ton.



•

Transmission expense — declined by $8 million due to certain transmission line outages between electrical power regions which limited merchant energy volumes that would incur transmission costs as well as lower network interchange transmission costs associated with reduced contract customer energy volumes.

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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 increased by $27 million in years ended December 31, 2009, compared to the same period in 2008.

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

        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, 2009, the $114 million mark-to-market gain in operating revenue relating to economic hedges was due to an increase in value in forward sales and purchases of electricity and fuel due to a decrease in forward power and gas prices. The $47 million mark-to-market loss in operating costs and expenses related to economic hedges was due to an increase in value of forward purchases of electricity and natural gas relating to retail supply, offset by a decrease in value of forward fuel purchases due to a decrease in coal prices.

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        Reliant Energy's loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. The $656 million roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating revenues and operating costs and expenses during the same period. The $104 million gain from the reversal of a loss due to the termination of positions related to the CSRA unwind was offset by a realized loss at the settled prices and are reflected in operating costs and expenses during the same period.

        Since these hedging activities are intended to mitigate the risk of commodity price movements on operating revenues and operating costs and expenses, the changes in such results should not be viewed in isolation, but rather should be taken together with the effects of pricing and cost changes on operating revenue and costs. During and prior to 2009, NRG hedged a portion of the Company's 2009 through 2013 generation. During 2009, the forward power and gas prices decreased resulting in the recognition of unrealized mark-to-market gains.

        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, 2009, and 2008. 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.

Other Revenues

        Other revenues decreased by $556 million due primarily to the following:

•

Reliant Energy — $259 million of contract amortization offset other revenues in 2009 representing the roll-off of in-market C&I contracts valued under purchase accounting.



•

Texas — decreased by $260 million due to a decrease of $198 million in contract amortization related to the roll-off of out-of-market contracted energy sales valued under purchase accounting and a decrease of $47 million in ancillary services revenue provided to the market.



•

Northeast — decreased by $38 million due to $21 million from decreased activity in the trading of emission allowances and $16 million of lower allocations of net physical gas sales.

        These decreases in other revenues were offset by:

•

Corporate — recorded a $31 million non-cash gain related to settlement of a pre-existing in-the-money contract with Reliant Energy at the time of acquisition in 2009.

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Other Operating Costs

        Other operating costs increased $140 million during the year ended December 31, 2009, compared to the same period in 2008, due to:

•

Reliant Energy — increased due to the eight months of other operating costs included in 2009 totaling $104 million which consisted of $98 million for customer service operations and $55 million related to gross receipt tax on revenue, offset by $49 million in contract amortization.



•

Contract Amortization — increased $19 million in the Texas region due to a reduction in amortization for out-of-the money coal contracts assumed in the acquisition of Texas Genco as coal is delivered under that contract.



•

Property and other taxes — increased $17 million primarily related to a $14 million increase in the Northeast region due to a reduction in the eligibility related to Empire Zone tax credits in New York.



•

Operations and maintenance expense — increased by $10 million due to the following:



o

West — increased $12 million due to higher maintenance expense associated with a major overhaul at El Segundo and higher maintenance at Long Beach.



o

South Central — increased $5 million due to an increase in labor costs from higher benefit costs and major maintenance due to more extensive outage work performed at the Big Cajun II plant in 2009 compared to the same period in 2008.

These increases in operations and maintenance expense were offset by the following decrease:

o

Northeast — decreased $11 million due to a decrease of $22 million due to lower chemical spending and routine maintenance work as a result of lower generation and lower planned major maintenance work at the Huntley and Indian River plants, offset by a $12 million asset write-down due to the cancellation of the Indian River Unit 3 air pollution control equipment project and the consequent write-off of previously incurred construction costs.

Depreciation and Amortization

        NRG's depreciation and amortization expense increased by $169 million for the year ended December 31, 2009, compared to the same period in 2008. Reliant Energy's depreciation and amortization expense for the eight month period was $137 million principally for amortization of customer relationships. The balance of the increase was due to depreciation on the baghouse projects in western New York and the Elbow Creek project which came online in late 2008, and the Cedar Bayou 4 plant which came online in the second quarter of 2009.

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Selling, General and Administrative Expenses

        Selling, general and administrative expenses increased by $231 million for the year ended December 31, 2009, compared to the same period in 2008 and increased as a percentage of revenues to 6% for 2009 from 5% for 2008. The increase was due to:

•

Reliant Energy's selling, general and administrative expense — totaled $203 million, including $61 million of bad debt expense incurred during the eight months ended December 31, 2009.



•

Wage and benefits expense — increased $19 million.



•

Consultant costs — increased $12 million consisting of a rise in non-recurring costs related to Exelon's exchange offer and proxy contest efforts of $23 million offset by a decrease in other consulting costs of $11 million.

Reliant Energy Acquisition-Related Transaction and Integration Costs

        NRG incurred Reliant Energy acquisition-related transaction costs of $23 million and integration costs of $31 million for the year ended December 31, 2009.

Equity in Earnings of Unconsolidated Affiliates

        NRG's equity earnings from unconsolidated affiliates decreased by $18 million for the year ended December 31, 2009, compared to the same period in 2008. During 2009, the Company's share in Gladstone Power Station and MIBRAG decreased by $4 million and $16 million, respectively. These decreases were offset by an $11 million increase in earnings for the Company's share of NRG Saguaro, LLC in 2009 as compared to 2008. In addition, there was a $6 million decrease in Sherbino's mark-to-market unrealized loss as compared to 2009 as a result of a natural gas swap executed to hedge to future power generation.

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

        NRG's gain on sale of equity method investments was $128 million for the year ended December 31, 2009. Other income, net decreased by $22 million for the year ended December 31, 2009, compared to the same period in 2008. The 2009 amounts include a $128 million gain on the sale of NRG's 50% ownership interest in MIBRAG and a $24 million realized loss on a forward contract for foreign currency executed to hedge the proceeds from the MIBRAG sale. In addition, interest income for 2009 was reduced by $17 million as compared to 2008 due to lower interest rates. Further, in 2008, a $23 million impairment charge was recorded to restructure distressed investments in commercial paper.

Refinancing Expense

        In 2009, NRG incurred a $20 million expense associated with the CSRA unwind with Merrill Lynch. There were no such expenses in 2008.

Interest Expense

        NRG's interest expense increased by $51 million during the year ended December 31, 2009, compared to the same period in 2008 due to the following:

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Income Tax Expense

        Income tax expense increased by $15 million for the year ended December 31, 2009, compared to 2008. The effective tax rate was 43.6% and 40.4% for the year ended December 31, 2009, and 2008, respectively.

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

•

Valuation Allowance — The Company generated capital losses in 2009 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 an increase of $129 million in income tax expense in 2009.



•

Tax Expense Reduction — The Company recorded a lower federal and state tax expense of $35 million primarily due to lower pre-tax earnings.



•

Change in state effective tax rate — The Company decreased its estimated effective tax rate to 3% due to increased operational activities within the state of Texas resulting from the acquisition of Reliant Energy. This resulted in a tax benefit of $5 million.



•

Foreign Operations — The Company elected not to designate its earnings from foreign operations as permanently reinvested in 2008. In 2009, the Company sold its investment in the MIBRAG facility for a book gain of $128 million and no tax gain which resulted in minimal tax due in the local jurisdiction.

        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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Liquidity and Capital Resources

Liquidity Position

        As of December 31, 2010, and 2009, NRG's liquidity, excluding collateral received, was approximately $4.3 billion and $3.8 billion, respectively, comprised of the following:

        For the year ended December 31, 2010, total liquidity, excluding collateral received, increased by $458 million due to a higher cash balance of $647 million, partially offset by decreased availability of the Funded Letter of Credit Facility and the Revolving Credit Facility of $143 million and $52 million, respectively. The decrease in Revolving Credit Facility availability was due to a reduction in capacity of $125 million in connection with the refinancing of the Senior Credit Facility, which was offset by an increase of $59 million due to the cancellation in February 2010 of the letter of credit issued in support of the Dunkirk bonds and an adjustment to the letter of credit issued related to the Peaker Finance Co. bonds, as described further in Item 15 — Note 12, Debt and Capital Leases, to the Consolidated Financial Statements. Changes in cash balances are further discussed hereinafter under Cash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at December 31, 2010, are predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

        The line item "Funds deposited by counterparties" represents the amounts that are held by NRG as a result of collateral posting obligations from the Company's counterparties due to positions in the Company's hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of NRG's general corporate obligations. Depending on market fluctuation and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. The change in these amounts from December 31, 2009, was due to an increase in the forward values of hedges due to lower natural gas prices and a renegotiation of the credit limit with one counterparty.

        Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's preferred shareholders, and other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

Credit Ratings

        Credit rating agencies rate a firm's public debt securities. These ratings are utilized by the debt markets in evaluating a firm's credit risk. Ratings influence the price paid to issue new debt securities by indicating to the market the Company's ability to pay principal, interest and preferred dividends. Rating agencies evaluate a firm's industry, cash flow, leverage, liquidity, and hedge profile, among other factors, in their credit analysis of a firm's credit risk.

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        The following table summarizes the credit ratings for NRG Energy, Inc., its Term Loan Facility and its Senior Notes as of December 31, 2010:

Sources of Liquidity

        The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand and cash flows from operations. As described in Item 15 — Note 12 — Debt and Capital Leases, to the Consolidated Financial Statements, the Company's financing arrangements consist mainly of the Senior Credit Facility, the TANE and Shaw Facilities, the Senior Notes, project-related financings and the GenConn Energy LLC related financings.

        In addition, NRG has granted first and second liens to certain counterparties on substantially all of the Company's assets. NRG uses the first or second lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first and second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its non-baseload assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first and second lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

        The Company's lien counterparties may have a claim on its assets to the extent market prices exceed the hedged price. As of December 31, 2010, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.

        The following table summarizes the amount of MWs hedged against the Company's baseload assets and as a percentage relative to the Company's baseload capacity under the first and second lien structure as of December 31, 2010:

Uses of Liquidity

        The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations, as described more fully in Item 15 — Note 12, Debt and Capital Leases, to the Consolidated Financial Statements; (iii) capital expenditures including RepoweringNRG and environmental; and (iv) corporate financial transactions including return of capital to shareholders, as described in Item 15 — Note 15, Capital Structure, to the Consolidated Financial Statements.

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Commercial Operations

        NRG's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) initial collateral required to establish trading relationships; (iii) timing of disbursements and receipts (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of December 31, 2010, commercial operations had total cash collateral outstanding of $323 million, and $689 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions (includes a $66 million letter of credit relating to deposits at the PUCT that covers outstanding customer deposits and residential advance payments). As of December 31, 2010, total collateral held from counterparties was $408 million in cash, and $10 million of letters of credit.

        Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on NRG's credit ratings and general perception of its creditworthiness.

Debt Service Obligations

        Principal payments on debt and capital leases, including the funded letter of credit facility as of December 31, 2010, are due in the following periods:

        In addition to the debt and capital leases shown in the preceding table, NRG had issued $860 million of letters of credit under the Company's $1.3 billion Funded Letter of Credit Facility and $22 million of letters of credit under the Company's Revolving Credit Facility as of December 31, 2010.

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Capital Expenditures

        The following tables and descriptions summarize the Company's capital expenditures for the year ended December 31, 2010, and the estimated capital expenditure and repowering investments forecast for 2011.

        RepoweringNRG capital expenditures for nuclear development — RepoweringNRG project capital expenditures related to the development of STP Units 3 and 4 in Texas are as follows:

        A portion of these capital expenditures were funded by NRG equity contributions into NINA of $178 million for the year ended December 31, 2010, which were used both for capital expenditures and development expenses. The continued funding by NRG for the development of STP Units 3 and 4 in 2011 is dependent on successfully obtaining a loan guarantee from the U.S. DOE as well as satisfying any conditions that the loan guarantee will require. If we are successful, capital expenditures for the project in 2011 will accelerate as the project progresses, and will be funded from a number of sources, including: draws on the TANE and Shaw Facilities; equity contributions from Toshiba and its affiliates; equity contributions from TEPCO and its affiliates; and from NRG. Currently, NRG expects to invest approximately $50 million in NINA during 2011. For further discussion see Item 15 — Note 22, Commitments and Contingencies, to the Consolidated Financial Statements.

        Other segment capital expenditures — capital expenditures, including accruals, for maintenance, environmental and RepoweringNRG other than nuclear development are as follows:

•

RepoweringNRG capital expenditures — For the year ended December 31, 2010, the Company's RepoweringNRG capital expenditures included $56 million for the Company's El Segundo project, $33 million for solar projects, and $22 million for the Company's Princeton Hospital project. In 2011, NRG will be investing in a number of solar projects and continue our efforts at El Segundo. Subject to financial close, these solar projects, for which capital expenditures are estimated to be approximately $2.7 billion will be funded from a number of sources including third party partners, loan guarantees from the U.S. DOE and NRG contributions.



•

Maintenance capital expenditures — For the year ended December 31, 2010, the Company's maintenance capital expenditures included $28 million in nuclear fuel expenditures related to STP Units 1 and 2. In addition, $172 million of environmental capital expenditures for the 2010 year-to-date period relate to a project to install selective catalytic reduction systems, scrubbers and fabric filters on Indian River Unit 4 with an expected in-service date of year-end 2011.

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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, NO_x, and 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. This estimate reflects anticipated schedules and controls related to CAIR, the proposed CATR, MACT for mercury and the Phase II 316(b) Rule which are under remand to the U.S. EPA and, as such, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined at this time.

        The table below summarizes installed and planned air quality controls for the NRG coal fleet. Planned investments are either in construction or budgeted in the existing capital expenditures budget. Changes to regulations could result in changes to planned installation dates. NRG uses an integrated approach to fuels, controls and emissions markets to meet environmental standards.

FF-ACI — Fabric Filter with Activated Carbon Injection
LNB — Low NO_x Burner
LNB/OFA — Low NO_x Burner with Overfire Air
SCR — Selective Catalytic Reduction
ESP — Electrostatic Precipitator
SNCR — Selective Non-Catalytic Reduction
DSI — Dry Sorbent Injection with Trona

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        The following table summarizes the estimated environmental capital expenditures for the referenced periods by region:

        NRG's current contracts with the Company's rural electrical customers in the South Central region allow for recovery of a portion of the regions' capital costs once in operation, along with a capital return incurred by complying with any change in law, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.

2011 Capital Allocation Program

        On February 22, 2011, the Company announced its 2011 Capital Allocation Plan to purchase $180 million in common stock. The Company's share repurchases are subject to market prices, financial restrictions under the Company's debt facilities, and as permitted by securities laws. As part of the 2011 plan, the Company expects to invest approximately $373 million in maintenance and environmental capital expenditures in existing assets, up to $50 million in equity contributions to NINA and approximately $3.0 billion in solar and other projects under RepoweringNRG. Investing in our large solar projects is conditional on obtaining U.S. DOE loan guarantees that will fund a large portion of the capital investments, coupled with investments by third party partners and NRG equity contributions. Finally, in addition to scheduled debt amortization payments, in the first quarter 2011 the Company will offer its first lien lenders $414 million of its 2010 excess cash flow (as defined in the Senior Credit Facility), of which the Company made a prepayment of $200 million in November 2010.

Preferred Stock Dividend Payments

        For the year ended December 31, 2010, NRG paid $9 million in dividend payments to holders of the Company's 3.625% Preferred Stock. As of January 21, 2010, the Company completed the redemption of all remaining outstanding shares of the 4% Preferred Stock, with holders converting 154,029 preferred stock shares into 7,701,450 common stock shares and the Company redeeming 28 preferred stock shares for $28 thousand in cash.

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Cash Flow Discussion

        The following table reflects the changes in cash flows for the comparative years; all cash flow categories include the cash flows from both continuing operations and discontinued operations:

Net Cash Provided By Operating Activities

        The Company's cash flow from operations was lower by approximately $483 million in 2010 compared to 2009 due to a $748 million decrease in operating income adjusted for non-cash charges, offset by a $240 million increase in net collateral deposits paid and option premiums paid and collected and a $25 million increase in working capital.

Net Cash Used By Investing Activities

        Changes to net cash used in investing activities were due to:

•

Acquisition of businesses — During 2010, the Company paid $1.0 billion, net of cash acquired of $75 million, to acquire several businesses. During 2009, the Company paid $427 million, of which $360 million was for the acquisition of Reliant Energy. See Item 15 — Note 3, Business Acquisitions, to the Consolidated Financial Statements for a more complete description of these acquisitions.



•

Proceeds from renewable energy grants — During 2010, the Company received $102 million of federal cash grants for the Blythe solar and Langford wind facilities.



•

Proceeds from sale of equity method investment — Investing activities in 2009 reflect the sale of MIBRAG in June 2009 for net proceeds of $284 million. See Item 15 — Note 4, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for a more complete description of this transaction.



•

Capital expenditures — NRG's capital expenditures decreased by $28 million due to decreased spending on maintenance and RepoweringNRG.



•

Proceeds from sale of assets — Net proceeds increased by $37 million in 2010 as compared to 2009 primarily due to the sale of Padoma in January 2010. See Item 15 — Note 4, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for a more complete description of this transaction.



•

Other — Investing activities in 2010 reflect $23 million invested in equity method investees, including a partnership with Eurus Energy to develop solar projects.

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Net Cash Provided By Financing Activities

        Changes in net cash provided by financing activities were due to:

•

Increase in issuance of debt — During 2010, the Company issued $1.3 billion under new debt facilities and $164 million under existing debt facilities. The new debt facilities consist primarily of $1.1 billion 2020 Senior Notes, $100 million by NRG Thermal, $67 million in Indian River bonds, and $30 million by Blythe. The borrowings under existing facilities related mainly to additional borrowings under the TANE facility. During 2009, the Company received $688 million in gross proceeds from the 2019 Senior Notes, $108 million in NRG Connecticut Peaking financing, $52 million from the Dunkirk bonds and $19 million from other borrowings.



•

Increase in term loan and other facility payments — In 2010, the Company paid down $453 million of its Term Loan Facility, including the payment of excess cash flow. In addition, NRG Connecticut Peaking repaid the $55 million portion of the EBL used to fund the Devon project, NRG EC Minneapolis paid $20 million on the Peakers bonds and NINA paid $20 million under its revolving credit facility. In 2009, the Company paid down $429 million of its Term Loan Facility, including the payment of excess cash flow.



•

Repayment of CSF Debt — During 2010, the Company paid $190 million in principal to early settle the CSF I Debt. In November 2009, the Company paid $181 million to CS for the benefit of CSF II to unwind the Company's CSF II Debt.



•

Net receipt from acquired derivatives that include financing elements — In 2010, the Company received a net of $137 million for the settlement of gas swaps compared with a payment of $79 million in 2009 for the settlement of gas swaps related to Reliant Energy and Texas Genco.



•

Share repurchases — During 2010, the Company repurchased $180 million of NRG common stock as compared to $500 million in 2009.



•

Increase in deferred finance costs — During 2010, deferred finance costs primarily consist of fees paid as a result of the 2020 Senior Notes and the amendment and extension of the Senior Credit Facility. During 2009, deferred finance costs were lower, and related to the Reliant Energy CSRA, the 2019 Senior Notes, the Dunkirk bonds and the Reliant Energy working capital facility.



•

Decrease in preferred stock dividends — During 2010, dividend payments on preferred stock decreased by $24 million as compared to the same period in 2009 due to the conversion of the 5.75% Preferred Stock in 2009 and the conversion of the 4% Preferred Stock, which was completed in January 2010.

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NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC-740, Income Taxes, or ASC 740

        As of December 31, 2010, the Company had generated total domestic pre-tax book income of $691 million and foreign pre-tax book income of $62 million. The Company has net operating losses for tax return purposes available to offset taxable income in the current period. In addition, NRG has cumulative foreign NOL carryforwards of $270 million, of which $85 million will expire starting 2011 through 2018 and of which $185 million do not have an expiration date.

        In addition to these amounts, the Company has $663 million of tax effected uncertain tax benefits which relate primarily to net operating losses for tax return purposes which have been classified as capital loss carryforwards for financial statement purposes. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily due to foreign, state and local jurisdictions, of up to $50 million in 2011.

        However, as the position remains uncertain for the $663 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $582 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $582 million non-current tax liability for uncertain tax benefits is primarily due to taxable earnings for which there are no NOLs available to offset for financial statement purposes and interest.

        The examination by the Internal Revenue Service for the years 2004 through 2006 is currently in Joint Committee review and is not considered effectively settled in accordance with ASC 740. The Company anticipates conclusion of the audit during 2011. Upon effective settlement of the audit, the result may be a reduction of the liability for uncertain tax benefits. The Company continues to be under examination for various state jurisdictions for multiple years.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

        NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See also Item 15 — Note 26, Guarantees, to the Consolidated Financial Statements for additional discussion.

Retained or Contingent Interests

        NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.

Derivative Instrument Obligations

        The Company's 3.625% Preferred Stock includes a feature which is considered an embedded derivative per ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of December 31, 2010, based on the Company's stock price, the embedded derivative was out-of-the-money and had no redemption value. See also Item 15 — Note 15, Capital Structure, to the Consolidated Financial Statements for additional discussion.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

        Variable interest in Equity investments — As of December 31, 2010, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Two of these investments, GenConn and Sherbino, are variable interest entities for which NRG is not the primary beneficiary.

        NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $187 million as of December 31, 2010. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Item 15 — Note 16, Investments Accounted for by the Equity Method, to the Consolidated Financial Statements for additional discussion.

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Contractual Obligations and Commercial Commitments

        NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs. The following tables summarize NRG's contractual obligations and contingent obligations for guarantee. See also Item 15 — Note 12, Debt and Capital Leases, Note 22, Commitments and Contingencies, and Note 26, Guarantees, to the Consolidated Financial Statements for additional discussion.

(a)

Excludes $582 million non-current payable relating to NRG's uncertain tax benefits under ASC 740 as the period of payment cannot be reasonably estimated. Also excludes $432 million of asset retirement obligations which are discussed in Item 15 — Note 13, Asset Retirement Obligations, to the Consolidated Financial Statements.

(b)

Includes only those coal transportation and lignite commitments for 2011 as no other nominations were made as of December 31, 2010. Natural gas nomination is through February 2012.

(c)

These amounts represent the Company's estimated minimum pension contributions required under the Pension Protection Act of 2006. These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2016 is currently not available.

(d)

These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2016 are currently not available.

(e)

Includes water right agreements, service and maintenance agreements, stadium naming rights and other contractual obligations.

Fair Value of Derivative Instruments

        NRG may enter into long-term power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements.

        NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

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        The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at December 31, 2010, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2010. NRG also acquired retail load and supply contracts as part of business combinations in 2010, and the tables below include the fair value of these contracts receiving mark-to-market accounting treatment as of the acquisition date. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 — Note 5, Fair Value of Financial Instruments, to the Consolidated Financial Statements.

 

        The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 7A — Commodity Price Risk, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using Value at Risk, or VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG's hedging activity. As of December 31, 2010, NRG's net derivative asset was $672 million, an increase to total fair value of $213 million as compared to December 31, 2009. This increase was primarily driven by the increase in fair value due to the decreases in gas and power prices partially offset by the roll-off of trades that settled during the period and the addition of out-of-the-money derivatives as part of the Green Mountain Energy acquisition.

        Based on a sensitivity analysis using simplified assumptions, the impact of a $1 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $183 million in the net value of derivatives as of December 31, 2010.

Critical Accounting Policies and Estimates

        NRG's discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S, or U.S. GAAP. The preparation of these financial statements and related disclosures in compliance with U.S. GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.

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        On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

        NRG's significant accounting policies are summarized in Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements. The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.

Derivative Instruments

        The Company follows the guidance of ASC 815 to account for derivative instruments. ASC 815 requires the Company to mark-to-market all derivative instruments on the balance sheet, and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings. In certain cases, NRG may apply hedge accounting to the Company's derivative instruments. The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the fair value of the derivative instrument and the underlying hedged item. Changes in the fair value of derivatives instruments accounted for as hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged item, or deferred and recorded as a component of OCI, and subsequently recognized in earnings when the hedged transactions occur.

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        For purposes of measuring the fair value of derivative instruments, NRG uses quoted exchange prices and broker quotes. When external prices are not available, NRG uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. In order to qualify derivative instruments for hedged transactions, NRG estimates the forecasted generation occurring within a specified time period. Judgments related to the probability of forecasted generation occurring are based on available baseload capacity, internal forecasts of sales and generation, and historical physical delivery on similar contracts. The probability that hedged forecasted generation will occur by the end of a specified time period could change the results of operations by requiring amounts currently classified in OCI to be reclassified into earnings, creating increased variability in the Company's earnings. These estimations are considered to be critical accounting estimates.

        Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered NPNS. The availability of this exception is based upon the assumption that NRG has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on available baseload capacity, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment, and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings.

Income Taxes and Valuation Allowance for Deferred Tax Assets

        As of December 31, 2010, NRG had a valuation allowance of $191 million. This amount is comprised of U.S. domestic capital loss carryforwards, certain state NOLs and non-depreciable property of $116 million, foreign net operating loss carryforwards of $74 million and foreign capital loss carryforwards of approximately $1 million. In assessing the recoverability of NRG's deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected capital gains and available tax planning strategies.

        NRG continues to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company's significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2004.

Evaluation of Assets for Impairment and Other Than Temporary Decline in Value

        In accordance with ASC-360, Property, Plant, and Equipment, or ASC 360, NRG evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events are:

•

Significant decrease in the market price of a long-lived asset;



•

Significant adverse change in the manner an asset is being used or its physical condition;



•

Adverse business climate;



•

Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;



•

Current-period loss combined with a history of losses or the projection of future losses; and



•

Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

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        Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available to the Company. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. NRG uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates, and the impact of such variations could be material.

        For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assets held-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value under ASC 360, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective. NRG considers quoted market prices in active markets to the extent they are available. In the absence of such information, the Company may consider prices of similar assets, consult with brokers, or employ other valuation techniques. NRG will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in the Company's estimates, and the impact of such variations could be material.

        NRG is also required to evaluate its equity-method and cost-method investments to determine whether or not they are impaired. ASC-323, Investments-Equity Method and Joint Ventures, or ASC 323, provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under ASC 323 is whether the value is considered an "other than a temporary" decline in value. The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with ASC 360. Similarly, the estimates that NRG makes with respect to its equity and cost-method investments are subjective, and the impact of variations in these estimates could be material. Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, NRG would record its proportionate share of that impairment loss and would evaluate its investment for an other than temporary decline in value under ASC 323.

Goodwill and Other Intangible Assets

        At December 31, 2010, NRG reported goodwill of $1.9 billion, consisting of $1.7 billion in its Texas operating segment, or NRG Texas, that is associated with the acquisition of Texas Genco in 2006, and $0.2 billion in its corporate operating segment that is associated with the acquisition of Green Mountain Energy in November 2010. The Company has also recorded intangible assets in connection with its business acquisitions, measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. See Item 15 — Note 3, Business Acquisitions, and Note 11 — Goodwill and Other Intangibles, to the Consolidated Financial Statements for further discussion.

        The Company applies ASC 805, Business Combinations, or ASC 805, and ASC 350, Intangibles — Goodwill and Other, or ASC 350, to account for its goodwill and intangible assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized. However, goodwill and all intangible assets not subject to amortization are tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components. If it is determined that the fair value of a reporting unit is below its carrying amount, where necessary, the Company's goodwill and/or intangible asset with indefinite lives will be impaired at that time.

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        The Company performed its annual goodwill impairment assessment as of December 31, 2010, for its Texas reporting unit, NRG Texas, which is at the operating segment level. The Company determined the fair value of this reporting unit using primarily an income approach and then applied an overall market approach reasonableness test to reconcile that fair value with NRG's overall market capitalization. Significant inputs to the determination of fair value were as follows:

•

For the three solid-fuel baseload plants that drive a majority of the value in the reporting unit, and for the region's Elbow Creek, Langford, Cedar Bayou and South Trent facilities that recently commenced operations, the Company applied a discounted cash flow methodology to their long-term budgets. This approach is consistent with that used to determine fair value in prior years. These budgets are based on the Company's views of power and fuel prices, which consider market prices in the near term and the Company's fundamental view for the longer term as some relevant market prices are illiquid beyond 24 months. Hedging is included to the extent of contracts already in place. Projected generation in the long-term budgets is based on management's estimate of supply and demand within the sub-markets for each plant and the physical and economic characteristics of each plant;



•

For the reporting unit's remaining gas plants, the Company applied a market-derived earnings multiple to the gas plants' aggregate estimated 2010 earnings before interest, taxes, depreciation and amortization. This approach is consistent with that used to determine fair values in prior years;



•

The intangible value to NRG Texas for synergies it provides to Reliant Energy was determined by capitalizing estimated annual collateral charge and supply cost savings; and



•

The potential impact of carbon legislation was estimated using a discounted cash flow methodology applied to the Company's view of the impact of potential legislation that is based on recent proposals to Congress.

        If fair value of a reporting unit exceeds its carrying value, goodwill of the reporting unit is not considered impaired. Under the income approach described above, the Company estimated the fair value of NRG Texas' invested capital to exceed its carrying value by approximately 23% at December 31, 2010. The Company also evaluated various market-derived data including market research forecasts, recent merger and acquisition activity and earnings multiples, and together with its estimate of fair value, concluded that NRG Texas's goodwill is not impaired at December 31, 2010.

        To reconcile the fair value determined under the income approach with NRG's market capitalization, the Company considered historical and future budgeted earnings measures to estimate the average percentage of total company value represented by NRG Texas, and applied this percentage to an adjusted business enterprise value of NRG. To derive this adjusted business enterprise value, the Company applied a range of control premiums based on recent market transactions to the business enterprise value of NRG on a non-controlling, marketable basis, and also made adjustments for some non-operating assets and for some of the significant factors that impact NRG differently from NRG Texas, such as environmental capital expenditures outside of the Texas region, and the impact of nuclear development efforts on NRG's stock price. The Company also qualitatively considered the impact on its stock price of shorter-term market views about forward natural gas prices. The Company was able to reconcile the proportional value of NRG Texas to NRG's market capitalization at a value that would not indicate an impairment.

        The Company's estimate of fair value under the income approach described above is affected by assumptions about projected power prices, generation, fuel costs, capital expenditure requirements and environmental regulations, and the Company believes that the most significant impact arises from future power prices. 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. Assuming all other factors are held constant, a hypothetical $1 drop in the Company's long-term natural gas price view would cause the fair value of NRG Texas to fall 4% below its carrying value at December 31, 2010. If long-term natural gas prices remain depressed for an extended period of time, the Company's goodwill may become impaired in the future, which would result in a non-cash charge, not to exceed $1.7 billion.

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Contingencies

        NRG records a loss contingency when management determines it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes in detail its contingencies in Item 15 — Note 22, Commitments and Contingencies, to the Consolidated Financial Statements.

Recent Accounting Developments

        See Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of recent accounting developments.

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Item 7A — Quantitative and Qualitative Disclosures About Market Risk

        NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. In order to manage these risks the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange, and swaps and options traded in the over-the-counter financial markets to:

•

Manage and hedge fixed-price purchase and sales commitments;



•

Manage and hedge exposure to variable rate debt obligations;



•

Reduce exposure to the volatility of cash market prices, and



•

Hedge fuel requirements for the Company's generating facilities.

Commodity Price Risk

        Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VaR. NRG uses a diversified VaR model to calculate an estimate of the potential loss in the fair value of the Company's energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions.

        NRG's portfolio consists of generation assets and full requirement load serving obligations. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales of electricity and purchases and fuel. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as New York Mercantile Exchange, or NYMEX, and Intercontinental Exchange, or ICE, as well as over-the-counter markets. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.

        While some of the contracts the Company uses to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. NRG uses the Company's best estimates to determine the fair value of those derivative contracts. However, it is likely that future market prices could vary from those used in recording mark-to-market derivative instrument valuation, and such variations could be material.

        NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and VaR. VaR is a statistical model that attempts to predict risk of loss based on market price and volatility. Currently, the company estimates VaR using a Monte Carlo simulation based methodology.

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        NRG uses a diversified VaR model to calculate an estimate of the potential loss in the fair value of the Company's energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions. The key assumptions for the Company's diversified model include: (i) a lognormal distribution of prices; (ii) one-day holding period; (iii) a 95% confidence interval; (iv) a rolling 36-month forward looking period; and (v) market implied volatilities and historical price correlations.

        As of December 31, 2010, the VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the diversified VaR model was $50 million.

        The following table summarizes average, maximum and minimum VaR for NRG for the years ended December 31, 2010, and 2009:

        Due to the inherent limitations of statistical measures such as VaR, the evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VaR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated VaR, and such changes could have a material impact on the Company's financial results.

        In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of December 31, 2010, for the entire term of these instruments entered into for both asset management and trading, was $15 million primarily driven by asset-backed transactions.

Interest Rate Risk

        NRG is exposed to fluctuations in interest rates through the Company's issuance of fixed rate and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.

        In May 2009, NRG entered into a series of forward-starting interest rate swaps. These interest rate swaps become effective on April 1, 2011, and are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, the Company will pay its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on a 1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which mature on February 1, 2013, is $900 million.

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        In 2006, the Company entered into a series of interest rate swaps which are intended to hedge the risk associated with floating interest rates. For each of the interest rate swaps, NRG pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the equivalent of a floating interest payment based on a 3-month LIBOR rate calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made quarterly, and the LIBOR is determined in advance of each interest period. While the notional value of each of the swaps does not vary over time, the swaps are designed to mature sequentially. The total notional amount of these swaps as of December 31, 2010, was $1.55 billion. The maturities and notional amounts of each tranche of these swaps in connection with the Senior Credit Facility are as follows:

        In addition to those discussed above, the Company had the following additional interest rate swaps outstanding as of December 31, 2010:

        If all of the above swaps had been discontinued on December 31, 2010, the Company would have owed the counterparties $91 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

        NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of December 31, 2010, a 1% change in interest rates would result in a $7 million change in interest expense on a rolling twelve month basis.

        As of December 31, 2010, the Company's debt fair value, including funded letter of credit, was $10.5 billion and the carrying amount was $10.4 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $599 million.

Liquidity Risk

        Liquidity risk arises from the general funding needs of NRG's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.

        Based on a sensitivity analysis for power and gas positions under marginable contracts, a $1 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $99 million as of December 31, 2010, and a 0.25 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $19 million as of December 31, 2010. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2010.

        Under the second lien, NRG is required to post certain letters of credit as credit support for changes in commodity prices. As of December 31, 2010, no letters of credit are outstanding to second lien counterparties. With changes in commodity prices, the letters of credit could grow to $64 million, the cap under the agreements.

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Counterparty Credit Risk

        Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk with a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.

        As of December 31, 2010, total credit exposure to a significant portion of the Company's counterparties was $1.4 billion and NRG held collateral (cash and letters of credit) against those positions of $414 million resulting in a net exposure of $976 million. Total credit exposure is discounted at the risk free rate. The following table highlights the credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit risk is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and Normal Purchase Normal Sale, or NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.

 

(a)

Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.

(b)

For non-rated counterparties, the majority are related to ISO and municipal public power entities, which are considered investment grade equivalent ratings based on NRG's internal credit ratings.

        NRG has credit risk exposure to certain wholesale counterparties representing more than 10% of the total net exposure discussed above and the aggregate of such counterparties was $251 million. Approximately 80% of NRG's positions relating to this credit risk roll-off by the end of 2012. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.

        Counterparty credit exposure described above excludes credit risk exposure under certain long term contracts, including California tolling agreements, South Central load obligations and a coal supply agreement. As external sources or observable market quotes are not available to estimate such exposure, the Company valued these contracts based on various techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of December 31, 2010, credit risk exposure to these counterparties is approximately $520 million for the next five years. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.

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Retail Customer Credit Risk

        NRG is exposed to retail credit risk through its retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.

        As of December 31, 2010, the Company's credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.

        NRG is also exposed to credit risk relating to its Mass customers, which may result in a write-off of bad debt. During 2010, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.

Credit Risk Related Contingent Features

        Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of December 31, 2010, was $34 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2010, was $11 million. The Company is also a party to certain marginable agreements where NRG has a net liability position but the counterparty has not called for the collateral due, which is approximately $20 million as of December 31, 2010.

Currency Exchange Risk

        NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure is limited.

Item 8 — Financial Statements and Supplementary Data

        The financial statements and schedules are listed in Part IV, Item 15 of this Form 10-K.

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

        None.

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Item 9A — Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Internal Control Over Financial Reporting

        Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this annual report on Form 10-K. Management's report on the Company's internal control over financial reporting and the report of the Company's independent registered public accounting firm are incorporated under the caption "Management's Report on Internal Control over Financial Reporting" and under the caption "Report of Independent Registered Public Accounting Firm," of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Changes in Internal Control over Financial Reporting

        There were no changes in the Company's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the fourth quarter of 2010 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Inherent Limitations over Internal Controls

        NRG's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. The Company's internal control over financial reporting includes those policies and procedures that:

1.

Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company's assets;



2.

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that the Company's receipts and expenditures are being made only in accordance with authorizations of its management and directors; and



3.

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the consolidated financial statements.

        Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Item 9B — Other Information

        None.

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PART III

Item 10 — Directors, Executive Officers and Corporate Governance

        NRG has adopted a code of ethics entitled "NRG Code of Conduct" that applies to directors, officers and employees, including the chief executive officer and senior financial officers of NRG. It may be accessed through the Corporate Governance section of the Company's website at http://www.nrgenergy.com/investor/corpgov.htm. NRG Energy,  Inc. also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website, and such information will remain available on this website for at least a 12-month period. A copy of the "NRG Energy, Inc. Code of Conduct" is available in print to any shareholder who requests it.

        Other information required by this Item will be incorporated by reference to the similarly named section of NRG's definitive Proxy Statement for its 2011 Annual Meeting of Stockholders.

Item 11 — Executive Compensation

        Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2011 Annual Meeting of Stockholders.

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

        Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2011 Annual Meeting of Stockholders.

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

        Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2011 Annual Meeting of Stockholders.

Item 14 — Principal Accounting Fees and Services

        Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2011 Annual Meeting of Stockholders.

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PART IV

Item 15 — Exhibits, Financial Statement Schedules

        (a)(1) Financial Statements

The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports thereon of KPMG LLP, are included herein:

Consolidated Statements of Operations — Years ended December 31, 2010, 2009, and 2008

Consolidated Balance Sheets — December 31, 2010 and 2009

Consolidated Statements of Cash Flows — Years ended December 31, 2010, 2009, and 2008

Consolidated Statement of Stockholders' Equity and Comprehensive Income — Years ended December 31, 2010, 2009, and 2008

Notes to Consolidated Financial Statements

        (a)(2) Financial Statement Schedule

The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 15(d) of this report and should be read in conjunction with the Consolidated Financial Statements.

Schedule II — Valuation and Qualifying Accounts

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.

        (a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.

        (b) Exhibits

See Exhibit Index submitted as a separate section of this report.

        (c) Not applicable

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

        NRG Energy Inc.'s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company's management, including its principal executive officer, principal financial officer and principal accounting officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company's evaluation under the framework in Internal Control — Integrated Framework, the Company's management concluded that its internal control over financial reporting was effective as of December 31, 2010.

        The effectiveness of the Company's internal control over financial reporting as of December 31, 2010, has been audited by KPMG LLP, the Company's independent registered public accounting firm, as stated in its report which is included in this Form 10-K.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
NRG Energy, Inc.:

        We have audited NRG Energy, Inc.'s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). NRG Energy, Inc.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, NRG Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 22, 2011 expressed an unqualified opinion on those consolidated financial statements.

Philadelphia, Pennsylvania
February 22, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
NRG Energy, Inc.:

        We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule "Schedule II Valuation and Qualifying Accounts." These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

        As discussed in Note 2 to the consolidated financial statements, the Company adopted Accounting Standards Update (ASU) 2009-17, "Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities" (incorporated into Accounting Standards Codification (ASC) Topic 810, "Consolidation"), effective January 1, 2010; the Company adopted Statement of Financial Accounting Standards (SFAS) 141R, "Business Combinations" (incorporated into Accounting Standards Codification (ASC) Topic 805, "Business Combinations"), SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, Consolidated Financial Statements" (incorporated into ASC Topic 810, "Consolidation"), Financial Accounting Standards Board Staff Position (FSP FAS) 141R-1, "Accounting for Assets and Liabilities Assumed in a Business Combination That Arise from Contingencies" (incorporated into ASC Topic 805, "Business Combinations"), and FSP Accounting Principles Board (APB) No. 14-1, "Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlements)" (incorporated into ASC Topic 825, "Financial Instruments"), effective January 1, 2009; and SFAS No. 157, "Fair Value Measurements" (incorporated into ASC Topic 820, "Fair Value Measurements and Disclosures"), effective January 1, 2008.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of NRG Energy, Inc and subsidiaries internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 22, 2011 expressed an unqualified opinion on the effective operation of internal control over financial reporting.

Philadelphia, Pennsylvania
February 22, 2011

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NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

See notes to Consolidated Financial Statements.

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NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See notes to Consolidated Financial Statements.

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NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Continued)

See notes to Consolidated Financial Statements.

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NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME

See notes to Consolidated Financial Statements.

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NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

See notes to Consolidated Financial Statements.

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NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Nature of Business

General

        NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company with a significant presence in major competitive power markets in the United States. 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, and approximately 265 MW under construction which includes partner interests of 120 MW. In addition to its fossil fuel plant ownership, NRG has ownership interests in operating renewable facilities with an aggregate generation capacity of 470 MW, consisting of four wind farms representing an aggregate generation capacity of 450 MW, a 20 MW solar facility and less than 5 MW of distributed solar. Within the United States, NRG has large and diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 23,565 MW of fossil fuel and nuclear generation capacity in 185 active generating units at 43 plants. The Company's power generation facilities are most heavily concentrated in Texas (approximately 10,745 MW, including 450 MW from four wind farms), the Northeast (approximately 6,900 MW), South Central (approximately 4,125 MW), and West (approximately 2,150 MW, including 20 MW from a solar facility) regions of the United States. Through certain foreign subsidiaries, NRG has investments in power generation projects located in Australia and Germany with approximately 1,005 MW of generation capacity. In addition, NRG has approximately 115 MW of additional generation capacity from the Company's thermal assets, as well as a district energy business that has a steam and chilled water capacity of approximately 1,140 megawatts thermal equivalent, or MWt.

        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.

        NRG was incorporated as a Delaware corporation on May 29, 1992. NRG's common stock is listed on the New York Stock Exchange under the symbol "NRG". The Company's headquarters and principal executive offices are located at 211 Carnegie Center, Princeton, New Jersey 08540. NRG's telephone number is (609) 524-4500. The address of the Company's website is www.nrgenergy.com. NRG's recent annual reports, quarterly reports, current reports, and other periodic filings are available free of charge through the Company's website.

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Note 2 — Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

        The Company's consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S., or U.S. GAAP. The FASB Accounting Standards Codification, or ASC, is the source of authoritative U.S. GAAP recognized by the Financial Accounting Standards Board, or FASB, to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.

        The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a variable interest entity or VIE, should be consolidated.

        Prior to January 1, 2010, ASC 810 required a quantitative analysis of the economic risk/rewards of a VIE to determine the party, referred to as the primary beneficiary, that is required to consolidate the VIE. Under this analysis, the primary beneficiary absorbed a majority of the expected losses of the VIE, received the majority of the expected residual returns of the VIE, or both. In December 2009, the FASB issued ASU No. 2009-17, Consolidations: Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities, or ASU 2009-17. This guidance, effective for NRG as of January 1, 2010, now specifies that a qualitative analysis be performed, requiring the primary beneficiary to have both the power to direct the activities of a VIE that most significantly impact the entities' economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. In determining the primary beneficiary, NRG thoroughly evaluates the VIE's design, capital structure, and relationships among variable interest holders. NRG will not consolidate a VIE in which it has a majority ownership interest when the Company is not considered the primary beneficiary. The Company's adoption of ASU 2009-17 on January 1, 2010, did not have an impact on its results of operations, financial position, or cash flows. NRG determined that one of its equity method investments, Sherbino I Wind Farm LLC, or Sherbino, was a VIE as of January 1, 2010, upon adoption of this new guidance. NRG owns a 50% interest in Sherbino but the Company is not the primary beneficiary under the amended guidance. Therefore, NRG will continue to account for its investment in Sherbino under the equity method. For further discussion see Note 16 — Investments Accounted for by the Equity Method.

        In February 2010, the FASB issued ASU No. 2010-10, Consolidation (Topic 810): Amendments for Certain Investment Funds, or ASU 2010-10. The amendments to ASC 810 clarify that related parties should be considered when evaluating the criteria for determining whether a decision maker's or service provider's fee represents a variable interest. In addition, the amendments clarify that a quantitative calculation should not be the sole basis for evaluating whether a decision maker's or service provider's fee represents a variable interest. The Company adopted the provisions of ASU 2010-10 effective January 1, 2010, with no impact on its results of operations, financial position or cash flows.

        Upon its emergence from bankruptcy on December 5, 2003, the Company qualified for and adopted fresh start reporting, or Fresh Start, under ASC 852, Reorganizations, or ASC 852.

Cash and Cash Equivalents

        Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.

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Funds Deposited by Counterparties

        Funds deposited by counterparties consist of cash held by NRG as a result of collateral posting obligations from the Company's counterparties with positions in NRG's hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of NRG's general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. Changes in funds deposited by counterparties are closely associated with the Company's operating activities, and are classified as an operating activity in the Company's consolidated statements of cash flows.

Restricted Cash

        Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments, per the restrictions of the debt agreements.

Trade Receivables and Allowance for Doubtful Accounts

        Trade receivables are reported in the balance sheet at outstanding principal adjusted for any write-offs and the allowance for doubtful accounts. For its Reliant Energy and Green Mountain Energy businesses, the Company accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. These businesses write-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.

Inventory

        Inventory is valued at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost will be recovered with a normal profit in the ordinary course of business, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at a weighted average cost, since the Company expects to recover these costs in the ordinary course of business. The Company removes these inventories when they are used for repairs, maintenance or capital projects. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.

Property, Plant and Equipment

        Property, plant and equipment are stated at cost; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in STP as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation other than nuclear fuel is computed using the straight-line method, while nuclear fuel is amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations.

Asset Impairments

        Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

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        Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, which requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value.

Discontinued Operations

        Long-lived assets or disposal groups are classified as discontinued operations when all of the required criteria specified in ASC 360 are met. These criteria include, among others, existence of a qualified plan to dispose of an asset or disposal group, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management. In addition, upon completion of the transaction, the operations and cash flows of the disposal group must be eliminated from ongoing operations of the Company, and the disposal group must not have any significant continuing involvement with the Company. Discontinued operations are reported at the lower of the asset's carrying amount or fair value less cost to sell.

Project Development Costs and Capitalized Interest

        Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset.

        Interest incurred on funds borrowed to finance capital projects is capitalized, until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2010, 2009, and 2008, was $36 million, $37 million, and $45 million, respectively.

        When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.

Debt Issuance Costs

        Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt.

Intangible Assets

        Intangible assets represent contractual rights held by NRG. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, NRG also established values for emission allowances and power contracts upon adoption of Fresh Start reporting. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis.

        Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives. NRG had no intangible assets with indefinite lives recorded as of December 31, 2010.

        Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.

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Goodwill

        In accordance with ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed.

        NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable. Goodwill impairment is determined using a two step process:

Income Taxes

        NRG accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

        NRG has two categories of income tax expense or benefit — current and deferred, as follows:

•

Current income tax expense or benefit consists solely of regular tax less applicable tax credits, and



•

Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income.

        NRG reports some of the Company's revenues and expenses differently for financial statement purposes than for income tax return purposes resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. NRG measures the Company's deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. A valuation allowance is recorded to reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized.

        The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.

        In accordance with ASC 805 and as discussed further in Note 19, Income Taxes, any reductions after January 1, 2009, to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, as they relate to Fresh Start or previously completed acquisitions, have been recorded to income tax expense rather than additional paid-in capital or goodwill.

Revenue Recognition

        Energy — Both physical and financial transactions are entered into to optimize the financial performance of NRG's generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815, Derivatives and Hedging, or ASC 815.

        Capacity — Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements.

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        Sale of Emission Allowances — NRG records the Company's bank of emission allowances as part of the Company's intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. NRG records the sale of emission allowances on a net basis within other revenue in the Company's consolidated statements of operations.

        Contract Amortization — Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes.

        Retail revenues — Gross revenues for energy sales and services to retail customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $158 million for the year ended December 31, 2010 and $251 million for the eight-month period ended December 31, 2009. These revenues represent a sale of excess supply to third parties in the market.

        As of December 31, 2010, and 2009, NRG recorded unbilled revenues of $282 million and $308 million, respectively, for retail energy sales and services. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.

Cost of Energy for Retail Operations

        The cost of energy for electricity sales and services to retail customers is based on estimated supply volumes for the applicable reporting period. A portion of the cost of energy ($61 million and $69 million as of December 31, 2010, and 2009, respectively) consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ERCOT ISO fees are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.

Derivative Financial Instruments

        NRG accounts for derivative financial instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges are either:

•

Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or



•

Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings.

        NRG's primary derivative instruments are power sales contracts, fuels purchase contracts, other energy related commodities, and interest rate instruments used to mitigate variability in earnings due to fluctuations in market prices and interest rates. On an ongoing basis, NRG assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such an energy contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. Hedge accounting will also be discontinued on contracts related to commodity price risk previously accounted for as cash flow hedges when it is probable that delivery will not be made against these contracts. In this case, the gain or loss previously deferred in accumulated OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative in accumulated OCI will be frozen until the underlying hedged item is delivered.

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        Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.

        NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

Foreign Currency Translation and Transaction Gains and Losses

        The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the determination of the Company's statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company's statements of operations. For the years ended December 31, 2010, 2009, and 2008, amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2010, 2009, and 2008 were $76 million, $79 million and $58 million, respectively.

Concentrations of Credit Risk

        Financial instruments which potentially subject NRG to concentrations of credit risk consist primarily of cash, trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Cash and cash equivalents and funds deposited by counterparties are predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, NRG believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of the Company's customer base. See Note 5, Fair Value of Financial Instruments, for a further discussion of derivative concentrations.

Fair Value of Financial Instruments

        The carrying amount of cash and cash equivalents, funds deposited by counterparties, trust funds, receivables, accounts payables, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. The carrying amounts of long-term receivables usually approximate fair value, as the effective rates for these instruments are comparable to market rates at year-end, including current portions. Any differences are disclosed in Note 5, Fair Value of Financial Instruments. The fair value of long-term debt is based on quoted market prices for those instruments that are publicly traded, or estimated based on the income approach valuation technique for non-publicly traded debt. For the years ended December 31, 2010, 2009, and 2008, the Company recorded an unrealized gain of $2 million, an unrealized gain of $3 million, and impairment charges of $23 million, respectively, related to an investment in commercial paper. In 2010, the Company recognized a $3 million gain on the sale of part of the investment. As of December 31, 2010, the net carrying value of the remaining investment was $8 million.

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Asset Retirement Obligations

        NRG accounts for its asset retirement obligations, or AROs, in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.

        Upon initial recognition of a liability for an ARO, NRG capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 13, Asset Retirement Obligations, for a further discussion of AROs.

Pensions

        NRG offers pension benefits through either a defined benefit pension plan or a cash balance plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. NRG accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits. NRG recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset to other comprehensive income. In addition, NRG also recognizes on an after-tax basis, as a component of other comprehensive income, gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost. The determination of NRG's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. NRG's actuarial consultants use assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company.

        NRG measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820.

Stock-Based Compensation

        NRG accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation. The fair value of the Company's non-qualified stock options and performance units are estimated on the date of grant using the Black-Scholes option-pricing model and the Monte Carlo valuation model, respectively. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's restricted stock units and deferred stock units. Forfeiture rates are estimated based on an analysis of NRG's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award.

Investments Accounted for by the Equity Method

        NRG has investments in various international and domestic energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NRG from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of international projects, are reflected as equity in earnings of unconsolidated affiliates.

Issuance of Subsidiary's Stock

        The Company accounts for issuance of its subsidiaries' stock in accordance with ASC 810, which requires an entity to account for a decrease in its ownership interest of a subsidiary that does not result in a change of control of the subsidiary as an equity transaction. In March 2008, NRG formed NINA, an NRG development stage subsidiary focused on developing, financing, and investing in nuclear projects in North America. TANE has partnered with NRG on the NINA venture, receiving a 12% equity ownership in NINA in exchange for $300 million to be invested in NINA in six annual installments of $50 million, the last three of which are subject to certain restrictions. NRG continues to control NINA through its voting interest. Any change in NRG's proportionate share of NINA's equity resulting from cash invested by TANE directly into NINA is accounted for by the Company as an equity transaction in consolidation, and not a gain on sale, as long as there is no change in control of NINA. Accordingly, receipt of TANE's installment contributions results in increases in additional paid-in capital and noncontrolling interest on the Company's consolidated balance sheet.

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Gross Receipts and Sales Taxes

        In connection with its retail businesses, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the year ended December 31, 2010 and the eight-month period ended December 31, 2009, NRG's revenues and cost of operations included gross receipts taxes of $67 million and $55 million, respectively. Additionally, Reliant Energy and Green Mountain Energy record sales taxes collected from their taxable customers and remitted to the various governmental entities on a net basis, thus, there is no impact on the Company's consolidated statement of operations.

Business Combinations

        The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805. For business combinations for which the acquisition date occurs after January 1, 2009, ASC 805 requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.

Use of Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

        In recording transactions and balances resulting from business operations, NRG uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, and the valuation of energy commodity contracts, environmental liabilities, and legal costs incurred in connection with recorded loss contingencies, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Reclassifications

        Certain prior-year amounts have been reclassified for comparative purposes.

Recent Accounting Developments

        ASU No. 2010-09 — In February 2010, the FASB issued ASU No. 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements, or ASU 2010-09. Under the amendments of ASU 2010-09, an entity that is an SEC filer is not required to disclose the date through which subsequent events have been evaluated. As this guidance provides only disclosure requirements, the adoption of ASU 2010-09 effective January 1, 2010, did not impact the Company's results of operations, financial position or cash flows.

        Other — The following accounting standards were adopted on January 1, 2010, with no impact on the Company's results of operations, financial position or cash flows:

•

ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, or ASU 2009-15.



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ASU No. 2010-02, Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary — a Scope Clarification, or ASU 2010-02.



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ASU No. 2010-06, Fair Value Measurement and Disclosures: Improving Disclosures about Fair Value Measurements, or ASU 2010-06.

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Note 3 — Business Acquisitions

2010 Acquisitions

        Green Mountain Energy — On November 5, 2010, NRG acquired Green Mountain Energy for $357 million in cash, net of $75 million cash acquired, funded from cash on hand. Austin-based Green Mountain Energy, the nation's leading competitive provider of cleaner energy and carbon offset products, 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 run as a standalone retail business within NRG. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to customer relationships of $158 million, trade names of $130 million, favorable commercial customer contracts of $54 million, net deferred tax liabilities of $78 million, net derivative liabilities of $60 million, and goodwill of $155 million. The initial accounting for the business combination is not complete because the evaluations necessary to assess the fair values of certain net assets acquired and the amount of goodwill to be recognized are still in process. The provisional amounts recognized are subject to revision until the evaluations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments will affect the acquisition-date fair value of goodwill. The factors that resulted in goodwill arising from the acquisition include the revenues associated with expanding the Green Mountain Energy business of providing renewable energy products and services to new customers in new regions and through new providers and the synergies associated with combining a renewable retail business with NRG's renewable generation assets.

        The provisional fair values of the intangible assets and liabilities at the acquisition date were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. Significant inputs were as follows:

•

Customer contracts — The fair values of the customer contracts, representing those with Green Mountain Energy's C&I customers, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on contract type, discounted utilizing a current market interest rate consistent with the overall credit quality of the portfolio. The above/below market cash flows were estimated by comparing the expected cash flows to be generated based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market costs, such as price of energy, transmission and distribution costs, and miscellaneous fees, plus a normal profit margin. The customer contracts are amortized to revenues, over a weighted average amortization period of five years, based on expected volumes to be delivered for the portfolio.



•

Customer relationships — The customer relationships, which reflect Green Mountain Energy's residential, commercial, utility partner and renewable emission credit customer base, were valued using a variation of the income approach. Under this approach, the present value of expected future cash flows resulting from the existing customer relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, software, workforce and trade names) utilized in the business were estimated and then discounted at an independent power producer peer group's weighted average cost of capital. The customer relationships are amortized to depreciation and amortization expense, over a weighted-average amortization period of ten years, based on the expected discounted future net cash flows by year.



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Trade names — The trade names were valued using a "relief from royalty" method, an approach under which fair value is estimated to be the present value of royalties saved because NRG owns the intangible asset and therefore does not have to pay a royalty for its use. The avoided royalty revenues were discounted at an independent power producer peer group's weighted average cost of capital. The remaining useful life of the trade names were determined by considering various factors, such as turnover and name changes in the independent power producer and utility industries, the current age of the Green Mountain Energy brand, management's intent to continue using the name at the current time, and feedback from external consultants regarding their experience with similar trade names. The trade names are amortized to depreciation and amortization expense, on a straight-line basis, over 15 years.



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Derivative contracts — The fair values of the derivative contracts were determined in accordance with ASC 820.

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        Cottonwood — On November 15, 2010, NRG acquired the Cottonwood Generating Station, a 1,265 MW combined cycle natural gas plant in the Entergy zone of east Texas, or Cottonwood, for $507 million in cash, funded from cash on hand. The acquisition of Cottonwood strengthened 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, one of the newest and most efficient plants in the region, to support current long-term contracts in Louisiana, Arkansas and East Texas. Owning Cottonwood now allows for future contracting opportunities and will enable NRG to provide additional balancing and ancillary services. The acquisition was recorded as a business combination under ASC 805 and the purchase price was allocated to the assets acquired and liabilities assumed, which were recorded at provisional fair value on the acquisition date. The purchase price was primarily allocated to fixed assets.

        The provisional fair values of the property, plant and equipment at the acquisition date were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. The fair value of property, plant and equipment was valued using a cost approach, which estimates value by determining the current cost of replacing an asset with another of equivalent economic utility. The cost to replace a given asset reflects the estimated reproduction or replacement cost for the property, less an allowance for loss in value due to depreciation.

        Northwind Phoenix — On June 22, 2010, NRG, through its wholly-owned subsidiary, NRG Thermal LLC, or NRG Thermal, acquired Northwind Phoenix, LLC, or Northwind Phoenix, for a total purchase price of $100 million in cash, plus a payment for acquired working capital true-ups. Northwind Phoenix owns and operates a district cooling system that provides chilled water to commercial buildings in the Phoenix central business district. In addition, Northwind Phoenix maintains and operates Combined Heat and Power plants that provide chilled water, steam and electricity in metropolitan Tucson and to portions of Arizona State University campuses in Tempe and Mesa. The acquisition was financed by the issuance of $100 million in notes by NRG Thermal. See Note 12, Debt and Capital Leases for information related to the notes issued.

        South Trent — On June 14, 2010, NRG acquired South Trent Wind LLC, owner of the South Trent wind farm, or South Trent, a 100 MW wind farm near Sweetwater, Texas, for a total purchase price of $111 million. South Trent commenced operations in January 2009 and consists of 44 turbines producing up to 2.3 MW of power each. The project has a 20-year PPA, which commenced January 2009, for all generation from the site. In connection with the acquisition, NRG paid $32 million in cash and South Trent entered into a financing arrangement that includes a $79 million term loan. See Note 12, Debt and Capital Leases for additional information related to this financing arrangement.

Acquisition of Reliant Energy in 2009

        As discussed more fully in Note 3 — Business Acquisitions, to the Company's 2009 Form 10-K, NRG acquired Reliant Energy on May 1, 2009, for total consideration of approximately $401 million. The acquisition of Reliant Energy was accounted for under the acquisition method of accounting in accordance with ASC 805. The following measurement period adjustments to the provisional amounts recorded as of December 31, 2009, attributable to refinement of the underlying appraisal assumptions, were recognized during the first quarter of 2010, the end of the measurement period: customer relationships increased by $6 million and current and non-current liabilities increased by $6 million, resulting in no change to net assets acquired. The accounting for this business combination was completed on March 31, 2010.

        NRG paid GenOn total cash consideration of approximately $370 million. NRG also recognized a $31 million non-cash gain on the settlement of a pre-existing relationship, representing the in-the-money value to NRG of an agreement that permits Reliant Energy to call on certain NRG gas plants when necessary for Reliant Energy to meet its load obligations. NRG recorded this gain within Operating Revenues in its consolidated statement of operations. This non-cash gain was considered a component of consideration in accordance with ASC 805, and together with cash consideration, brought the total consideration to approximately $401 million.

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Note 4 — Discontinued Operations and Dispositions

Discontinued Operations

        NRG classifies material business operations and gains/(losses) recognized on sales as discontinued operations for businesses that were sold or have met the required criteria for such classification. ASC 360 requires that discontinued operations be valued on an asset-by-asset basis at the lower of carrying amount or fair value, less costs to sell. In applying the provisions of ASC 360, the Company's management considers cash flow analyses, bids, and offers related to those assets and businesses. In accordance with the provisions of ASC 360, assets held by discontinued operations are not depreciated commencing with their classification as such.

        NRG's discontinued operations reflect the sale of ITISA in 2008, reported in the Company's international segment. In connection with the sale, NRG received $300 million of cash proceeds, and removed $163 million of assets, including $59 million of cash, $122 million of liabilities, including $63 million of debt, and $15 million in foreign currency translation adjustment from its 2008 consolidated balance sheet. The Company recorded a pre-tax gain on the disposal of ITISA of $273 million in the year ended December 31, 2008. Summarized results of ITISA, reflected within discontinued operations, were as follows:

Other Dispositions

        Padoma — On January 11, 2010, NRG sold its terrestrial wind development company, Padoma Wind Power LLC, or Padoma, to Enel North America, Inc., or Enel. NRG retained its existing ownership interest in its three Texas wind farms: Sherbino, Elbow Creek and Langford. In addition, NRG will maintain a strategic partnership with Enel to evaluate potential opportunities in renewable energy, including the opportunity to participate in wind projects currently in development. NRG recognized a gain on the sale of Padoma of $23 million, which was recorded as a component of operating income in the statement of operations.

        MIBRAG — On June 10, 2009, NRG completed the sale of its 50% ownership interest in MIBRAG, which owned and managed a coal mining operation, three lignite-fueled power generation facilities and other related businesses in Germany. For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40 U.S.$/EUR), net of transaction costs, and recognized an after-tax gain of $128 million for the year ended December 31, 2009. Prior to completion of the sale, NRG continued to record its share of MIBRAG's operations to Equity in earnings of unconsolidated affiliates. NRG provided certain indemnities in connection with its share of the transaction.

        In connection with the transaction, NRG entered into a foreign currency forward contract to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign currency forward contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200 million in exchange for $255 million on June 15, 2009. For the year ended December 31, 2009, NRG recorded an exchange loss of $24 million on the contract within Other (loss)/income, net.

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Note 5 — Fair Value of Financial Instruments

        The estimated carrying values and fair values of NRG's recorded financial instruments related to continuing operations are as follows:

        For cash and cash equivalents, funds deposited by counterparties, restricted cash, cash collateral paid and received in support of energy risk management activities, and restricted cash supporting the funded letter of credit facility, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of marketable securities is based on quoted market prices for those instruments. Trust fund investments are comprised of various U.S. debt and equity securities carried at fair market value.

        The fair value of notes receivable, debt securities and certain long-term debt are based on expected future cash flows discounted at market interest rates. The fair value of long-term debt and funded letter of credit is based on quoted market prices for these instruments that are publicly traded, or estimated based on the income approach valuation technique for non-publicly traded debt using current interest rates for similar instruments with equivalent credit quality.

Fair Value Accounting under ASC 820

        ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments.



•

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forwards.



•

Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models.

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        In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.

Recurring Fair Value Measurements

        The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:

 

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        There have been no transfers during the year ended December 31, 2010, between Levels 1 and 2. The following tables reconciles, for the years ended December 31, 2010, and 2009, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:

 

        Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in operating revenues and cost of operations.

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Non-derivative fair value measurements

        NRG's investment in debt securities are classified as Level 3 and consist of non-traded debt instruments that are valued based on third-party market value assessments.

        The trust fund investments are held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. In addition, U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. Commingled funds, which are analogous to mutual funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair value of commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See also Note 7, Nuclear Decommissioning Trust Fund.

Derivative fair value measurements

        A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 4% of the total fair value of all derivative contracts. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of December 31, 2010, the credit reserve resulted in a $2 million decrease in fair value which is composed of a $2 million loss in operating revenue and cost of operations.

        The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2010, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

        Under the guidance of ASC 815, entities may choose to offset cash collateral paid or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2010, the Company recorded $323 million of cash collateral paid and $408 million of cash collateral received on its balance sheet.

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Concentration of Credit Risk

        In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, the following item is a discussion of the concentration of credit risk for the Company's financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, credit derivatives, prepayment arrangements, or volumetric limits (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk with a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.

        As of December 31, 2010, counterparty credit exposure to a significant portion of the Company's counterparties was $1.4 billion and NRG held collateral (cash and letters of credit) against those positions of $414 million, resulting in a net exposure of $976 million. Counterparty credit exposure is discounted at the risk free rate. The following table highlights the counterparty credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.

 

        NRG has counterparty credit risk exposure to certain counterparties representing more than 10% of total net exposure discussed above and the aggregate of such counterparties was $251 million. Approximately 80% of NRG's positions relating to this credit risk roll-off by the end of 2012. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.

        Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and a coal supply agreement. As external sources or observable market quotes are not available to estimate such exposure, the Company valued these contracts based on various techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of December 31, 2010, credit risk exposure to these counterparties is approximately $520 million for the next five years. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.

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Retail Customer Credit Risk

        NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.

        As of December 31, 2010, the Company's retail customer credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.

        NRG is also exposed to retail customer credit risk relating to its Mass customers, which may result in a write-off of bad debt. During 2010, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.

Note 6 — Accounting for Derivative Instruments and Hedging Activities

        ASC 815 requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a Normal Purchase Normal Sale, or NPNS exception. If certain conditions are met, NRG may be able to designate certain derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.

        For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivative and the hedged transaction are recorded in current earnings.

        For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established per ASC 815, certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG's energy related commodity contracts, interest rate swaps, and foreign exchange contracts.

        As the Company engages principally in the trading and marketing of its generation assets and retail business, some of NRG's commercial activities qualify for hedge accounting under the requirements of ASC 815. In order for the generation assets to qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company's baseload plants. For this reason, many trades in support of NRG's baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG's peaking unit's asset optimization will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the supply contracts are recorded under mark-to-market accounting. All of NRG's hedging and trading activities are subject to limits within the Company's Risk Management Policy.

Energy-Related Commodities

        To manage the commodity price risk associated with the Company's competitive supply activities and the price risk associated with wholesale and retail power sales from the Company's electric generation facilities, NRG may enter into a variety of derivative and non-derivative hedging instruments, utilizing the following:

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Forward contracts, which commit NRG to purchase or sell energy commodities or purchase fuels in the future.



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Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument.



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Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity.



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Option contracts, which convey the right or obligation to purchase or sell a commodity.



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Weather and hurricane derivative products used to mitigate a portion of Reliant Energy's lost revenue due to weather.

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        The objectives for entering into derivative contracts designated as hedges include:

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Fixing the price for a portion of anticipated future electricity sales through the use of various derivative instruments including gas collars and swaps at a level that provides an acceptable return on the Company's electric generation operations.



•

Fixing the price of a portion of anticipated fuel purchases for the operation of NRG's power plants.



•

Fixing the price of a portion of anticipated power purchases for the Company's retail sales.

        As of December 31, 2010, NRG had cash flow hedge energy-related derivative financial instruments extending through December 2012.

        NRG's trading activities are subject to limits within the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

        As of December 31, 2010, NRG had hedge and non-hedge energy-related derivative financial instruments, and other energy-related contracts that did not qualify as derivative financial instruments extending through December 2029. As of December 31, 2010, NRG's derivative assets and liabilities consisted primarily of the following:

•

Forward and financial contracts for the purchase/sale of electricity and related products economically hedging NRG's generation assets' forecasted output or NRG's retail load obligations through 2016.



•

Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets into 2017.

        Also, as of December 31, 2010, NRG had other energy-related contracts that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment under the guidelines established by ASC 815 as follows:

•

Power sales and capacity contracts extending to 2025.

        Also, as of December 31, 2010, NRG had other energy-related contracts that did not qualify as derivatives under the guidelines established by ASC 815 as follows:

•

Load-following forward electric sale contracts extending through 2026;



•

Power Tolling contracts through 2029;



•

Lignite purchase contract through 2018;



•

Power transmission contracts through 2015;



•

Natural gas transportation contracts and storage agreements through 2018; and



•

Coal transportation contracts through 2016

Interest Rate Swaps

        NRG is exposed to changes in interest rates through the Company's issuance of variable and fixed rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of December 31, 2010, NRG had interest rate derivative instruments extending through June 2028, the majority of which had been designated as cash flow hedges.

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Volumetric Underlying Derivative Transactions

        The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2010, and December 31, 2009. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.

Fair Value of Derivative Instruments

        The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The Company has chosen not to offset positions as permitted in ASC 815. As of December 31, 2010, the Company recorded $323 million of cash collateral paid and $408 million of cash collateral received on its balance sheet.

        The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:

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Accumulated Other Comprehensive Income

        The following tables summarize the effects of ASC 815 on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:

 

 

        Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts.

        Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of July 31, 2008, the Company's regression analysis for natural gas prices to ERCOT power prices, while positively correlated, did not meet the required threshold for cash flow hedge accounting for calendar years 2012 and 2013. As a result, the Company de-designated its 2012 and 2013 ERCOT cash flow hedges as of July 31, 2008, and prospectively marked these derivatives to market. On April 1, 2009, the required correlation threshold for cash flow hedge accounting was achieved for these transactions, and accordingly, these hedges were re-designated as cash flow hedges.

        In connection with the May 1, 2009 acquisition of Reliant Energy as discussed in Note 3, Business Acquisitions, on October 5, 2009, the Company amended the CSRA with Merrill Lynch. In connection with the CSRA Amendment, NRG net settled certain in-the-money transactions with Morgan Stanley. As these transactions were net settled, $245 million in OCI was frozen and is recognized into income as the underlying power from the baseload plants is generated.

        The following table summarizes the amount of unrealized gain/(loss) resulting from fair value hedges reflected in interest income/(expense) for interest rate contracts:

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Impact of Derivative Instruments on the Statement of Operations

        In accordance with ASC 815, unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedge derivatives and ineffectiveness of hedge derivatives are reflected in current period earnings.

        The following table summarizes the pre-tax effects of economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges, and trading activity on NRG's statement of operations. These amounts are included within operating revenues and cost of operations.

 

        Reliant Energy's loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. Green Mountain Energy's loss positions were acquired as of November 5, 2010, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and are reflected in the cost of operations during the same period.

        For the year ended December 31, 2010, the $153 million loss from economic hedge positions was the result of a decrease in value of forward purchases and sales of natural gas, electricity and fuel due to a decrease in forward power and gas prices.

        For the year ended December 31, 2009, the $22 million gain from economic hedge positions includes a gain of $217 million recognized in earnings from previously deferred amounts in OCI as the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New York due to lower expected generation. This gain was partially offset by a loss of $29 million resulting from discontinued NPNS designated coal purchases due to expected lower coal consumption and accordingly could not assert taking physical delivery and a $166 million decrease in value of forward purchases and sales of natural gas, electricity and fuel due to decrease in forward power and gas prices.

Credit Risk Related Contingent Features

        Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that are in net liability positions as of December 31, 2010, was $34 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2010, was $11 million. The Company is also a party to certain marginable agreements where NRG has a net liability position, but the counterparty has not called for the collateral due, which is approximately $20 million as of December 31, 2010.

        See Note 5, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.

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Note 7 — Nuclear Decommissioning Trust Fund

        NRG's nuclear decommissioning trust fund assets, which are for the decommissioning of STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the PUCT to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rate base all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities.

        NRG accounts for the nuclear decommissioning trust fund in accordance with ASC 980 — Regulated Operations, or ASC 980 because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.

        The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities. The cost of securities sold is determined on the specific identification method.

        The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.

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Note 8 — Inventory

        Inventory consisted of:

Note 9 — Capital Leases and Notes Receivable

        Notes receivable primarily consisted of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. NRG's notes receivable and capital leases were as follows:

(a)

Saale Energie GmbH, or SEG, has sold 100% of its share of capacity from the Schkopau power plant to Vattenfall Europe Generation AG & Co. KG under a 25-year contract, which is more than 83% of the useful life of the plant. This direct financing lease receivable amount was calculated based on the present value of the income to be received over the life of the contract.

(b)

SEG entered into a note receivable with Kraftwerke Schkopau GBR, a partnership between SEG and E.On Kraftwerke GmbH. The note was used to fund SEG's initial capital contribution to the partnership and to cover project liquidity shortfalls during construction of the Schkopau power plant. The note is subject to repayment upon the disposition of the Schkopau plant.

(c)

NRG entered into a long-term $122 million note receivable facility with GCE Holding LLC to fund project liquidity needs in 2009. Per the terms of the facility, $56 million of the outstanding balance, including accrued interest was converted into equity in GenConn Energy LLC when the Devon project reached commercial operations. See Note 12, Debt and Capital Leases for further discussion.

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Note 10 — Property, Plant, and Equipment

        NRG's major classes of property, plant, and equipment were as follows:

Note 11 — Goodwill and Other Intangibles

        Goodwill — NRG's goodwill arose primarily in connection with the acquisition of Texas Genco in 2006. During 2010, the Company's goodwill balance increased by $155 million due to the acquisition of Green Mountain Energy, as discussed in Note 3, Business Acquisitions, and decreased by $5 million due to the sale of Padoma, as discussed in Note 4, Discontinued Operations and Dispositions. As of December 31, 2010, there was no impairment to goodwill. As of December 31, 2010 and 2009, NRG had approximately $660 million and $721 million, respectively, of goodwill that is deductible for U.S. income tax purposes in future periods.

        Intangible Assets — The Company's intangible assets as of December 31, 2010, primarily reflect intangible assets established with the acquisitions of various companies in 2010, 2009, and 2006, and are comprised of the following:

•

Emission Allowances — These intangibles primarily consist of SO₂ and NO_x emission allowances established with the 2006 Texas Genco acquisition and also include RGGI emission credits which NRG began purchasing in 2009. These emission allowances are held-for-use and are amortized to cost of operations, with NO_x allowances amortized on a straight-line basis and SO₂ allowances and RGGI credits amortized based on units of production.



•

Development rights — Arising primarily from the acquisition of a solar business in 2010, these intangibles are amortizable to depreciation and amortization expense on a straight-line basis over the estimated life of the related project portfolio.



•

Energy supply contracts — established with the acquisitions of Reliant Energy and Green Mountain Energy, these represent the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers. The contracts are amortized to cost of operations based on the expected delivery under the respective contracts.



•

In-market fuel (gas and nuclear) contracts — These intangibles were established with the Texas Genco acquisition in 2006. The power contracts are amortized to revenues based on contracted volumes over the life of each contract and the fuel contracts to cost of operations over expected volumes over the life of each contract.



•

Customer contracts — established with the acquisitions of Reliant Energy, Green Mountain Energy, and Northwind Phoenix as discussed further in Note 3, Business Acquisitions, these intangibles represent the fair value at the acquisition date of contracts to provide electricity, primarily to Reliant Energy's and Green Mountain Energy's C&I customers. These contracts are amortized to revenues based on expected volumes to be delivered for the portfolio.



•

Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base, primarily for Reliant Energy and Green Mountain Energy. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.

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•

Trade names — established with the Reliant Energy and Green Mountain Energy acquisitions, these intangibles are amortized to depreciation and amortization expense, on a straight-line basis.



•

Other — consists of renewable energy credits, wind intangible assets, costs to extend the operating license for STP Units 1 and 2, and the intangible asset related to a purchased ground lease.

        The following tables summarize the components of NRG's intangible assets subject to amortization:

 

(a)

Includes annual amortization expense as described in the table below; netting of fully amortized intangible assets of $19 million and $58 million for emission allowances and power contracts, respectively; and decrease of accumulated amortization expense of $88 million as a result of the reclassification of NPNS contract to derivatives in fuel contracts.

        The following table presents NRG's amortization of intangible assets for each of the past three years:

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        The following table presents estimated amortization of NRG's intangible assets for each of the next five years:

        The following table presents the weighted average remaining amortization period related to NRG's intangible assets purchased in 2010 business acquisitions:

        Intangible assets held for sale — From time to time, management may authorize the transfer from the Company's emission bank of emission allowances held-for-use to intangible assets held-for-sale. Emission allowances held-for-sale are included in other non current assets on the Company's consolidated balance sheet and are not amortized, but rather expensed as sold. As of December 31, 2010, the value of emission allowances held-for-sale is $13 million and is managed within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.

        Out-of-market contracts — Due to business acquisitions and upon the adoption of Fresh Start accounting, NRG acquired certain out-of-market contracts, which are classified as non-current liabilities on NRG's consolidated balance sheet. The power and customer contracts are amortized to revenues, while the energy supply contracts are amortized to cost of operations.

        The following table summarizes the estimated amortization related to NRG's out-of-market contracts:

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Note 12 — Debt and Capital Leases

        Long-term debt and capital leases consisted of the following:

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Senior Notes

        As of December 31, 2010, NRG had five outstanding issuances of senior notes, or Senior Notes, under an Indenture, dated February 2, 2006, or the Indenture, between NRG and Law Debenture Trust Company of New York, as trustee:

        (i)    7.25% senior notes, issued February 2, 2006 and due February 1, 2014, or the 2014 Senior Notes;

(ii)

7.375% senior notes, issued February 2, 2006 and due February 1, 2016, or the 2016 Senior Notes;



(iii)

7.375% senior notes, issued November 21, 2006 and due January 15, 2017, or the 2017 Senior Notes;



(iv)

8.5% senior notes, issued June 5, 2009 and due June 15, 2019, or the 2019 Senior Notes; and



(v)

8.25% senior notes, issued August 20, 2010 and due September 1, 2020, or the 2020 Senior Notes.

        The Company periodically enters into supplemental indentures for the purpose of adding entities under the senior notes as guarantors.

        The Indentures and the form of notes provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG. The Indentures also provide for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the Indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against NRG and its subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately.

        The terms of the Indentures, among other things, limit NRG's ability and certain of its subsidiaries' ability to return capital to shareholders, grant liens on assets to lenders and incur additional debt.

        Interest is payable semi-annually on the Senior Notes until their maturity dates. In addition, the Company entered into a fixed to floating interest rate swap in 2004 with a notional amount of $400 million and a maturity date of December 15, 2013. The swap was terminated on December 15, 2010, at the option of the counterparty. A premium of $5 million was received and will be amortized as a credit to interest expense over the remaining term of the underlying Senior Notes.

        NRG may redeem some or all of the 2014 Senior Notes at redemption prices expressed as percentages of principal amount as set forth below, plus accrued and unpaid interest on the notes redeemed to the applicable redemption date. On January 11, 2011, the Company announced a tender offer on the 2014 Senior Notes. Through February 9, 2011, the Company redeemed $945 million of the 2014 Senior Notes at an early redemption percentage of 102.063%, $2 million at a redemption percentage of 100.063%, and the remaining $253 million of 2014 Senior Notes will be called on February 25, 2011 at a redemption percentage of 101.813%.

        On or after February 1, 2011, NRG may redeem some or all of the 2016 Senior Notes at redemption prices expressed as percentages of principal amount as set forth below, plus accrued and unpaid interest on the notes redeemed to the applicable redemption date:

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        Prior to January 15, 2012, NRG may redeem up to 35% of the 2017 Senior Notes with net cash proceeds of certain equity offerings at a price of 107.375%, provided at least 65% of the aggregate principal amount of the notes issued remain outstanding after the redemption. Prior to January 15, 2012, NRG may redeem all or a portion of the Senior Notes at a price equal to 100% of the principal amount of the notes redeemed, plus a premium and any accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the note, or (ii) the excess of the principal amount of the note over the following: the present value of 103.688% of the note, plus interest payments due on the note from the date of redemption through January 15, 2012, discounted at a Treasury rate plus 0.50%. In addition, on or after January 15, 2012, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth below, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:

        Prior to June 15, 2012, NRG may redeem up to 35% of the aggregate principal amount of the 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.5% of the principal amount. Prior to June 15, 2014, NRG may redeem all or a portion of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 104.25% of the note, plus interest payments due on the note from the date of redemption through June 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after June 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:

        Prior to September 1, 2013, NRG may redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.25% of the principal amount. Prior to September 1, 2015, NRG may redeem all or a portion of the 2020 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note; or (ii) the excess of the principal amount of the note over the following: the present value of 104.125% of the note, plus interest payments due on the note from the date of redemption through September 1, 2015, discounted at a Treasury rate plus 0.50%. In addition, on or after September 1, 2015, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:

        On January 26, 2011, NRG issued $1.2 billion aggregate principal amount at par of 7.625% Senior Notes due 2018, or the 2018 Senior Notes. The 2018 Senior Notes were issued under the Indenture. The Indenture and the form of the notes provide, among other things, that the 2018 Senior Notes will be senior unsecured obligations of NRG. The net proceeds of $1.195 billion will be used primarily to complete the tender offer of the 2014 Senior Notes. Interest is payable semi-annually beginning on July 15, 2011, until their maturity date of January 15, 2018.

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        Prior to maturity, NRG may redeem all or a portion of the 2018 Senior Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note or (ii) the excess of the present value of the principal amount at maturity plus all required interest payments due on the note through the maturity date discounted at a Treasury rate plus 0.50%.

        In connection with the 2020 and 2018 Senior Notes, NRG entered into registration payment arrangements. For the 2020 and 2018 Senior Notes, for the first 90-day period immediately following a registration default, additional interest will be paid in an amount equal to 0.25% per annum of the principal amount of 2020 or 2018 Senior Notes outstanding, as applicable. The amount of interest paid will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all registration defaults are cured, up to a maximum amount of 1.0% per annum of the principal amount of the 2020 or 2018 Senior Notes outstanding, as applicable. Any additional interest is paid on the next scheduled interest payment date; following the cure of the registration default, the additional interest payment will cease.

Senior Credit Facility

        As of December 31, 2010, NRG has a Senior Credit Facility which is comprised of a senior first priority secured term loan, or the Term Loan Facility, a $875 million senior first priority secured revolving credit facility, or the Revolving Credit Facility, and a $1.3 billion senior first priority secured funded letter of credit facility, or the Funded Letter of Credit Facility. The pricing on the Company's Term Loan Facility and Funded Letter of Credit Facility is also subject to further reductions upon the achievement of certain financial ratios.

        As of December 31, 2010, NRG had issued $860 million of letters of credit under the Funded Letter of Credit Facility, leaving $440 million available for future issuances. Under the Company's Revolving Credit Facility as of December 31, 2010, NRG had issued letters of credit totaling $22 million, leaving $853 million available for borrowings or to issue additional letters of credit.

        On June 30, 2010, NRG completed an amendment and extension of the Senior Credit Facility, resulting in the following:

•

NRG extended the maturity date for $1.0 billion of its then $2.0 billion outstanding Term Loan Facility to August 31, 2015, with the remaining amount due on the original maturity date of February 1, 2013. The interest rate for the extended portion of the facility increased from LIBOR+1.75% to LIBOR+3.25%;



•

Borrowing capacity under the Revolving Credit Facility was reduced from $1.0 billion to $875 million and its maturity was extended to August 31, 2015. The interest rate for the amended Revolving Credit Facility is LIBOR+3.25%;



•

The existing off-balance sheet Synthetic Letter of Credit Facility was converted into a term loan-backed Funded Letter of Credit Facility, with the term loan reflected as a non-current liability and the proceeds of the term loan reflected as non-current restricted cash on NRG's balance sheet. Of the total $1.3 billion borrowed under the term loan, $500 million will mature on February 1, 2013 and bears interest at LIBOR+1.75%, while $800 million will mature August 31, 2015 and bears interest at LIBOR+3.25%.


    Restricted cash supporting funded letter of credit — Pursuant to the letter of credit reimbursement agreements entered into as of June 30, 2010, or the LC Agreements, and the Senior Credit Facility, as amended, NRG made capital contributions to NRG LC Facility Company, or LCFC, a separate, bankruptcy-remote entity that is a wholly-owned subsidiary of NRG. In addition, pursuant to reimbursement agreements related to the LC Agreements, NRG or its subsidiaries is liable for certain reimbursement obligations to LCFC. As of December 31, 2010, LCFC has cash invested in short-term certificates of deposit with an aggregate market value of $1.3 billion. Pursuant to the LC Agreements, which have a maximum committed amount of $1.3 billion, LCFC is liable on various letters of credit issued by Deutsche Bank AG, New York Branch, BNP Paribas, and Citibank, N.A. These letters of credit will be used to support the businesses of NRG and certain of its other subsidiaries and equity investments. LCFC has secured its reimbursement and other obligations under the LC Agreements with a pledge of the cash and cash equivalents that it owns. The LC Agreements require LCFC's assets to be used first and foremost to satisfy claims of creditors of LCFC. Although the cash and cash equivalents held by LCFC are included in the consolidated assets of NRG, such cash and cash equivalents are not available to creditors of NRG.

•

Expenses of $46 million, including fees to the lenders and other fees, were deferred and will be expensed in part over the original maturity through 2013 and in part over the amended maturity through 2015.

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        NRG must annually offer a portion of its excess cash flow (as defined in the Senior Credit Facility) to its first lien lenders under the Term Loan Facility. The percentage of the excess cash flow offered to these lenders is dependent upon the Company's consolidated leverage ratio (as defined in the Senior Credit Facility) at the end of the preceding year. Of the amount offered, the first lien lenders must accept 50%, while the remaining 50% may either be accepted or rejected at the lenders' option. The 2011 mandatory offer related to 2010 is expected to be $414 million, against which the Company made a prepayment of $200 million in November 2010. Based on current credit market conditions, the Company expects that its lenders will accept in full the 2011 mandatory offer related to 2010, and, as such, the Company has reclassified $214 million of Term Loan Facility maturity from a non-current to a current liability as of December 31, 2010. The 2010 mandatory offer related to 2009 was $429 million, against which the Company made a prepayment of $200 million in December 2009 and a payment of $229 million in March 2010.

        The Senior Credit Facility is guaranteed by substantially all of NRG's existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries, and certain other subsidiaries. The capital stock of substantially all of NRG's subsidiaries, with certain exceptions for unrestricted subsidiaries, foreign subsidiaries, and project subsidiaries, has been pledged for the benefit of the Senior Credit Facility's lenders.

        The Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interests in certain of NRG's project affiliates that have non-recourse debt financing, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of NRG's foreign subsidiaries.

        The Senior Credit Facility contains customary covenants, which, among other things, require NRG to meet certain financial tests, including minimum interest coverage ratio and a maximum leverage ratio on a consolidated basis, and limit NRG's ability to:

•

incur indebtedness and liens and enter into sale and lease-back transactions;



•

make investments, loans and advances; and



•

return capital to shareholders.

        Interest Rate Swaps — In May 2009, NRG entered into a series of forward-starting interest rate swaps. These interest rate swaps become effective on April 1, 2011, and are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, the Company will pay its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on a 1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which mature on February 1, 2013, is $900 million.

        In 2006, in connection with the Senior Credit Facility, NRG entered into another series of forward-setting interest rate swaps which are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, the Company pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives quarterly the equivalent of a floating interest payment based on a 3-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparties are made quarterly, and the LIBOR is determined in advance of each interest period. While the notional value of each of the swaps does not vary over time, the swaps are designed to mature sequentially. As of December 31, 2010, the $1.55 billion notional amount matures on March 31, 2011.

Indian River Power LLC Tax-Exempt Bonds

        On October 12, 2010, NRG executed a $190 million tax-exempt bond financing through its wholly-owned subsidiary, Indian River Power LLC. The bonds were issued by the Delaware Economic Development Authority and will be used for construction of emission control equipment on the Indian River Generating Station in Millsboro, DE, or Indian River. The bonds were issued at a rate of 5.375%, have a maturity date of October 1, 2045, and are supported by an NRG guarantee. The proceeds received through December 31, 2010, were $66 million, and the remaining balance will be received over time as construction costs are paid.

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        On December 10, 2010, NRG executed an additional $57 million tax-exempt bond financing through Indian River Power LLC. The bonds were issued by Sussex County, Delaware, and will be used for construction of emission control equipment on Indian River. The bonds were issued at a rate of 6.0%, have a maturity date of October 1, 2040, and are supported by an NRG guarantee. The proceeds received through December 31, 2010, were $1 million, and the remaining balance will be received over time as construction costs are paid.

Dunkirk Power LLC Tax-Exempt Bonds

        On April 15, 2009, NRG executed a $59 million tax-exempt bond financing, or the Dunkirk bonds, through its wholly-owned subsidiary, Dunkirk Power LLC, whereby all the proceeds were received as of December 31, 2010. The bonds were issued by the County of Chautauqua Industrial Development Agency and are being used for the construction of emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The bonds initially bore weekly interest based on the Securities Industry and Financial Markets Association, or SIFMA, rate, and on February 1, 2010, the Company fixed the rate on the bonds at 5.875%, with interest payable semiannually. The bonds have a maturity date of April 1, 2042. Initially, the bonds were enhanced by a letter of credit under the Company's Revolving Credit Facility covering amounts drawn on the facility, but on February 1, 2010, the letter of credit was cancelled and replaced with a parent guarantee.

NRG Non-Recourse Debt

Debt Related to Capital Allocation Program

        In 2006, the Company formed CSF I and II, two wholly-owned unrestricted subsidiaries that are both consolidated by NRG, and whose assets are not available to creditors of NRG or the Company's other subsidiaries. Their purpose was to repurchase an aggregate of $500 million in shares of NRG's common stock in the public markets or in privately negotiated transactions in connection with the Company's Capital Allocation Program, pursuant to which CSF I and CSF II repurchased 11,646,470 and 9,528,930 common shares, respectively. These subsidiaries were funded with a combination of cash from NRG, and a mix of notes and preferred interests issued to CS. The preferred interests were classified as a liability per ASC 480, Distinguishing Liabilities from Equity, or ASC 480, because they embodied a fixed unconditional obligation that CSF I and II must settle, and together with the notes are referred to as the CSF Debt in the aggregate and the CSF I Debt and CSF II Debt for each of the subsidiaries. The CSF Debt was non-recourse debt to NRG or any of its restricted subsidiaries and was collateralized by the NRG common stock held by CSF I and II.

        On November 24, 2009, the Company completed the unwinding of the CSF II Debt upon its scheduled maturity, remitting a $181 million cash payment to CS for $143 million of outstanding principal and $38 million of accrued interest, and CS released all 9,528,930 common shares held as collateral for the CSF II Debt.

        Pursuant to an extension amendment executed in March 2008, the CSF I Debt was to mature in June 2010. As part of this extension arrangement, the Company contributed 795,503 treasury shares to CSF I as additional collateral to maintain a blended interest rate in the CSF I facility of 7.5%, bringing the total common shares held by CSF I to 12,441,973. The amount due at the scheduled maturity in June 2010, including accrued interest, for the CSF I Debt was $249 million. On March 3, 2010, the Company completed an early unwinding of the CSF I Debt by remitting a cash payment to CS of $242 million to settle the outstanding principal and interest, and CS released all 12,441,973 shares of NRG common stock held as collateral.

        The CSF Debt for both CSF I and CSF II each contained a feature considered an embedded derivative, or CSF I CAGR and CSF II CAGR, which required NRG to pay to CS at maturity, either in cash or stock at NRG's option, the excess of NRG's then current stock price over a threshold price. Although these features were considered to be derivatives, they were exempt from derivative accounting under the guidance of ASC 815, and were only recognized upon settlement. In August 2008, the Company early settled the CSF I CAGR, making a cash payment of $45 million to CS for the benefit of CSF I, which was recorded to additional paid-in capital on the Company's consolidated balance sheet as of December 31, 2008. The CSF II CAGR expired in 2009 upon maturity of the CSF II Debt, with no payment due.

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Project Financings

        The following are descriptions of certain indebtedness of NRG's project subsidiaries that remain outstanding as of December 31, 2010. The indebtedness described below is non-recourse to NRG, unless otherwise noted.

Blythe Credit Agreement

        On June 24, 2010, NRG Solar Blythe LLC, or Blythe, entered into a credit agreement with a bank, or the Blythe Credit Agreement, for a $30 million term loan which has an interest rate of LIBOR plus an applicable margin which escalates 0.25% every three years and ranges from 2.5% at closing to 3.75% in year fifteen. The term loan matures in June 2028, amortizes based upon a predetermined schedule, and is secured by all of the assets of Blythe. The bank has also issued two letters of credit on behalf of Blythe, totaling $6.4 million. Blythe pays an availability fee of 100% of the applicable margin on these issued letters of credit. As of December 31, 2010, $29 million was outstanding under the term loan and $6 million in letters of credit were issued.

        Also related to the Blythe Credit Agreement, on June 25, 2010, Blythe entered into a fixed for floating interest rate swap for 75% of the outstanding term loan amount, intended to hedge the risks associated with floating interest rates. Blythe will pay its counterparty the equivalent of a 3.563% fixed interest payment on a predetermined notional value, and Blythe will receive quarterly the equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by Blythe and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. The original notional amount of the swap, which matures on June 25, 2028, is $22 million and amortizes in proportion to the loan. The outstanding notional amount as of December 31, 2010, is $21 million.

South Trent Financing Agreement

        On June 14, 2010, NRG completed the acquisition of South Trent, as discussed in Note 3, Business Acquisitions. As part of the purchase price consideration, South Trent entered into a financing agreement, or South Trent Financing Agreement, with a group of lenders, which matures on June 14, 2020. The South Trent Financing Agreement includes a $79 million term loan, as well as a $10 million letter of credit facility in support of the PPA, for which the full amount had been issued as of December 31, 2010. The South Trent Financing Agreement also provides for up to $8 million in additional letter of credit facilities, none of which are utilized as of December 31, 2010. The term loan accrues interest at LIBOR plus a margin based upon a grid, which is initially 2.50% and increases every two years by 12.5 basis points. The term loan amortizes quarterly based upon a predetermined schedule with the unamortized portion due at maturity. As of December 31, 2010, $78 million was outstanding under the term loan and $10 million was issued under the letter of credit facility.

        Under the terms of the South Trent Financing Agreement, South Trent was required to enter into interest rate protection agreements that would fix the interest rate for a minimum of 75% of the outstanding principal amount. Accordingly, on June 14, 2010, South Trent entered into five interest rate swaps, intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, South Trent will pay its counterparty the equivalent of a 3.265% fixed interest payment on a predetermined notional value, and South Trent will receive the quarterly equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by South Trent and its counterparties are made quarterly and the LIBOR is determined in advance of each interest period. The original total notional amount of these swaps, which mature on June 14, 2020, is $59 million. The swaps amortize in proportion to the loan. The outstanding notional amount as of December 31, 2010, was $58 million.

        South Trent also entered into a series of forward-starting interest rate swaps that will become effective June 14, 2020, and are effective for eight years. The swaps are intended to hedge the risks associated with floating interest rates. For each of the interest rate swaps, South Trent will pay its counterparty the equivalent of a 4.95% fixed interest payment on a predetermined notional value, and receive the quarterly equivalent of a floating interest payment based on a three month LIBOR calculated on the same notional value. All interest rate swap payments by South Trent and its counterparties will be made quarterly and the LIBOR is determined in advance of each interest period. The total notional amount of these swaps, which will mature on June 14, 2028, is $21 million.

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GenConn Energy LLC related financings

        On April 27, 2009, NRG Connecticut Peaking Development LLC, or NRG Connecticut Peaking, a wholly-owned subsidiary of NRG, closed on an equity bridge loan facility, or EBL, in the amount of $122 million from a syndicate of banks. The purpose of the EBL is to fund the Company's proportionate share of the project construction costs required to be contributed into GenConn Energy LLC, or GenConn, a 50% equity method investment of the Company. The EBL, which bears interest at a rate of LIBOR +2% on drawn amounts, is backed by a letter of credit issued by NRG under its Funded Letter of Credit Facility equal to at least 104% of amounts outstanding under the EBL. On September 29, 2010, GenConn's Devon project reached its commercial operations date, or COD, as defined in the financing documents. Accordingly, NRG Connecticut Peaking repaid the $55 million portion of the EBL used to fund the Devon project, and converted $56 million of a promissory note from GenConn into equity. As of December 31, 2010, $61 million was outstanding under the EBL for the Middletown project and NRG will continue to draw down to cover its interest portion of the loan. The EBL will mature on the earlier of Middletown's commercial operations date or July 26, 2011.

NRG Repowering Holdings LLC

        NRG Repowering Holdings LLC, or NRG Repowering, has a $20 million revolving credit facility to provide working capital which permits NRG Repowering to make cash draws or issue letters of credit. The facility matures on August 12, 2011. The facility provides for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the facility; the rendering of judgments to pay certain amounts of money against NRG Repowering and its subsidiaries; and certain events of bankruptcy or insolvency. Borrowings under the facility accrue interest at LIBOR or a base rate, plus a spread, and are supported by a letter of credit issued by NRG. As of December 31, 2010, NRG Repowering had borrowed $20 million.

NINA Financing Arrangements

        TANE Facility — On February 24, 2009, NINA executed an EPC agreement with TANE, which specifies the terms under which STP Units 3 and 4 will be constructed. Concurrent with the execution of the EPC agreement, NINA and TANE entered into a credit facility, or the TANE Facility, wherein TANE has committed up to $500 million to finance purchases of long-lead materials and equipment for the construction of STP Units 3 and 4. The TANE Facility matures on February 24, 2012, subject to two renewal periods, and provides for customary events of default, which include, among others: nonpayment of principal or interest; default under other indebtedness; the rendering of judgments; and certain events of bankruptcy or insolvency. Outstanding borrowings will accrue interest at LIBOR plus 2%, subject to a ratings grid, and are secured by substantially all of the assets of and membership interests in NINA and its subsidiaries. On November 29, 2010, NINA awarded the EPC contract for STP 3 and 4 to the Consortium formed by TANE and Shaw. Both the EPC agreement and the TANE Facility were amended in conjunction with the establishment of the Consortium. The changes to the TANE Facility allow for additional indebtedness as well as other technical amendments to facilitate the changes in the EPC agreement. As of December 31, 2010, $144 million has been borrowed under the TANE Facility.

        Shaw Facility — On November 29, 1010, under the amended EPC agreement, NINA also entered into a credit facility with Shaw, or the Shaw Facility, wherein Shaw has committed up to $100 million 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. The amended EPC agreement establishes Stone and Webster, Inc., a Shaw subsidiary, as co-contractor for STP Units 3 and 4. The Shaw Facility matures in November 2013, and provides for customary events of default, which include, among others: nonpayment of principal or interest; default under other indebtedness; the rendering of judgments; and certain events of bankruptcy or insolvency. The credit facility will convert to equity in NINA upon the satisfaction of certain conditions including the STP 3 and 4 Project receiving Full Notice to Proceed. Outstanding borrowings will accrue interest at LIBOR plus 6.0%, subject to a ratings grid, and are secured by substantially all of the assets and membership interest of NINA and its subsidiaries. As of December 31, 2010, $23 million was outstanding under the facility.

        Revolving Credit Facility — In 2008, NINA obtained a $20 million revolving credit facility to provide working capital which permitted NINA to make cash draws or issue letters of credit. As of December 31, 2009, NINA had borrowed $20 million. On June 1, 2010, NINA repaid the $20 million outstanding under its revolving credit facility, and the facility was terminated.

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Peakers

        In June 2002, NRG Peaker Finance Company LLC, or Peakers, an indirect wholly-owned subsidiary, issued $325 million in floating rate bonds due June 2019. Peakers subsequently swapped such floating rate debt for fixed rate debt at an all-in cost of 6.67% per annum. Principal, interest, and swap payments were originally guaranteed by Syncora Guarantee Inc., successor in interest to XL Capital Assurance, through a financial guaranty insurance policy. In 2009, Assured Guaranty Mutual Corp assumed the responsibility as the bond insurer and controlling party. Syncora Guarantee Inc. continues to be the swap insurer. These notes are also secured by, among other things, substantially all of the assets of and membership interests in Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC, and NRG Rockford Equipment LLC. As of December 31, 2010, $231 million in principal remained outstanding on these bonds. Upon emergence from bankruptcy, NRG issued a $36 million letter of credit to the Peakers' collateral agent. The letter of credit may be drawn if the project is unable to meet principal or interest payments. There are no provisions requiring NRG to replenish the letter of credit if it is drawn. On December 10, 2010, the collateral agent drew $14 million on the letter of credit to meet the debt service requirements and as of December 31, 2010, $22 million remains available for additional letters of credit issuances.

NRG Thermal

        NRG owns and operates its thermal business through a wholly-owned subsidiary holding company, NRG Thermal LLC, or NRG Thermal. In 1993, the predecessor entity to NRG Thermal's largest subsidiary, NRG Energy Center Minneapolis LLC, or NRG Thermal Minneapolis, issued $84 million of 7.31% senior secured notes due June 2013, of which $18 million remained outstanding as of December 31, 2010. In 2002, NRG Thermal Minneapolis issued an additional $55 million of 7.25% Series A notes due August 2017, of which $32 million remained outstanding as of December 31, 2010, and $20 million of 7.12% Series B notes due August 2017, of which $12 million remained outstanding as of December 31, 2010. In 2010, NRG Thermal Minneapolis issued $100 million of 5.95% Series C notes due June 23, 2025, of which $100 million remained outstanding as of December 31, 2010. The proceeds of these Series C notes were used to finance the acquisition of Northwind Phoenix, as discussed in Note 3, Business Acquisitions.

        The indebtedness under these notes is secured by substantially all of the assets of NRG Thermal Minneapolis. NRG Thermal has guaranteed the indebtedness, and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal's subsidiaries.

Capital Leases

Saale Energie GmbH

        Saale Energie GmbH, or SEG, an NRG wholly-owned subsidiary, has a 41.9% participation in Schkopau through NRG's interest in the Kraftwerke Schkopau GbR, or KSGbR, partnership. Under the terms of a Use and Benefit Fee Agreement, SEG and the other partner to the project, E.ON Kraftwerke GmbH, are required to fund debt service and certain other costs resulting from the construction and financing of Schkopau. The Use and Benefit Fee Agreement is treated as a capital lease under U.S. GAAP. Calls for funds are made to the partners based on their participation interest as cash is needed. As of December 31, 2010, the capital lease obligation at SEG was $107 million.

        The KSGbR issued debt to fund Schkopau pursuant to multiple facilities totaling €785 million. As of December 31, 2010, €123 million (approximately $165 million) remained outstanding at Schkopau. Interest accrues on the individual loans at fixed rates averaging 6.56% per annum, with maturities occurring between 2011 and 2020. SEG remains liable to the lenders as a partner in KSGbR, but there is no recourse to NRG.

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Consolidated Annual Maturities and Future Minimum Lease Payments

        Annual payments based on the maturities of NRG's debt and capital leases, including the funded letter of credit, for the years ending after December 31, 2010 are as follows:

        NRG's future minimum lease payments for capital leases included above as of December 31, 2010, are as follows:

Note 13 — Asset Retirement Obligations

        NRG's AROs are primarily related to the future dismantlement of equipment on leased property and environmental obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities. In addition, NRG has also identified conditional AROs for asbestos removal and disposal, which are specific to certain power generation operations.

        See Note 7, Nuclear Decommissioning Trust Fund, for a further discussion of NRG's nuclear decommissioning obligations. Consequently, accretion for the nuclear decommissioning ARO and amortization of the related ARO asset are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income, consistent with regulatory treatment.

        The following table represents the balance of ARO obligations as of December 31, 2010, and 2009, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2010:

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Note 14 — Benefit Plans and Other Postretirement Benefits

        NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation by eligible Texas based employees. NRG expects to contribute $19 million to the Company's three pension plans in 2011.

        NRG Plans for Bargained and Non-bargained Employees — Substantially all employees hired prior to December 5, 2003, were eligible to participate in NRG's legacy defined benefit pension plans. The Company initiated a noncontributory, defined benefit pension plan effective January 1, 2004, with credit for service from December 5, 2003. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. Generally, these are groups that were acquired prior to 2004 and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements.

        Texas Genco Retirement Plan — The Texas region's pension plan is a noncontributory defined benefit pension plan that provides a final average pay benefit or cash balance benefit, where the participant receives the more favorable of the two formulas, based on all years of service. In addition, employees who were hired prior to 1999 are also eligible for grandfathered benefits under a final average pay formula. In most cases, the benefits under the grandfathered formula were frozen on December 31, 2008. NRG's Texas region employees are also covered under an unfunded postretirement health and welfare plan. Each year, employees receive a fixed credit of $750 to their account plus interest. Certain grandfathered employees will receive additional credits through 2008. At retirement, the employees may use their accounts to purchase retiree medical and dental benefits from NRG. NRG's costs are limited to the amounts earned in the employee's account; all other costs are paid by the participant.

NRG Defined Benefit Plans

        The net annual periodic pension cost related to NRG domestic pension and other postretirement benefit plans include the following components:

 

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        A comparison of the pension benefit obligation, other postretirement benefit obligations, and related plan assets for NRG's plans on a combined basis is as follows:

        Amounts recognized in NRG's balance sheets were as follows:

        Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows:

        Other changes in plan assets and benefit obligations recognized in other comprehensive income were as follows:

        The Company's estimated net loss for NRG's domestic pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is minimal.

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        The following table presents the balances of significant components of NRG's domestic pension plan:

        NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy are as follows:

 

        In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the U.S. and international equity investments and the corporate bond investment is based on quoted prices in active markets, and is categorized as Level 1. All equity investments are valued at the net asset value of shares held at year end. The fair value of the corporate bond investment is based on the closing price reported on the active market on which the individual securities are traded. The fair value of the common/collective trusts is valued at fair value which is equal to the sum of the market value of all of the fund's underlying investments, and is categorized as Level 2. There are no investments categorized as Level 3.

        The following table presents the significant assumptions used to calculate NRG's benefit obligations:

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        The following table presents the significant assumptions used to calculate NRG's benefit expense:

        NRG uses December 31 of each respective year as the measurement date for the Company's pension and other postretirement benefit plans. The Company sets the discount rate assumptions on an annual basis for each of NRG's retirement related benefit plans at their respective measurement date. This rate is determined by NRG's Investment Committee based on information provided by the Company's actuary. The discount rate assumptions reflect the current rate at which the associated liabilities could be effectively settled at the end of the year. The discount rate assumptions used to determine future pension obligations as of December 31, 2010, 2009, and 2008 were based on the Hewitt Yield Curve, or HYC, which was designed by Hewitt Associates to provide a means for plan sponsors to value the liabilities of their postretirement benefit plans. The HYC is a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the HYC is required to have a rating of Aa or better by Moody's Investor Service, Inc. or a rating of AA or better by Standard & Poor's.

        NRG employs a total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The target allocation of plan assets is 47% to 63% invested in equity securities of which 33.5% to 50.5% is invested in U.S. equity securities, with the remainder invested in fixed income securities. The Investment Committee reviews the asset mix periodically and as the plan assets increase in future years, the Investment Committee may examine other asset classes such as real estate or private equity. NRG employs a building block approach to determining the long-term rate of return for plan assets, with proper consideration given to diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed income are preserved, consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

        Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. equities, as well as among growth, value, small and large capitalization stocks.

        NRG's pension plan assets weighted average allocations were as follows:

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        NRG's expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter, are as follows:

        Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:

STP Defined Benefit Plans

        NRG has a 44% undivided ownership interest in STP, as discussed further in Note 27, Jointly Owned Plants. STPNOC, who operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. For the years ending December 31, 2010, and 2009 NRG reimbursed STPNOC approximately $4 million and $5 million, respectively, towards its defined benefit plans. In 2011, NRG expects to reimburse STPNOC $8 million for its contributions towards the plans.

        The Company has recognized the following in its statement of financial position, statement of operations and accumulated OCI related to its 44% interest in STP:

Defined Contribution Plans

        NRG's employees have also been eligible to participate in defined contribution 401(k) plans. The Company's contributions to these plans were as follows:

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Note 15 — Capital Structure

        For the period from December 31, 2007, to December 31, 2010, the Company had 10,000,000 shares of preferred stock authorized and 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's preferred and common shares issued and outstanding for each period presented:

Common Stock

        The following table summarizes NRG's common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long-term incentive plan as of December 31, 2010.

        Capital Allocation Plan — As part of the Company's Capital Allocation Program, the Company returns capital to shareholders through NRG common stock repurchases under the Capital Allocation Plan. Shares repurchased are included in treasury stock.

        Employee Stock Purchase Plan — Under the NRG Energy, Inc. Employee Stock Purchase Plan, or ESPP, eligible employees may elect to withhold up to 10% of their eligible compensation to purchase shares of NRG common stock at 85% of its fair market value on the exercise date. An exercise date occurs each June 30 and December 31. As of December 31, 2010, there remained 297,478 shares of treasury stock reserved for issuance under the ESPP, and in the first quarter of 2011, 65,716 shares of common stock were issued to employee accounts from treasury stock.

        Share Lending Agreements — On February 20, 2009, CSF I and II entered into Share Lending Agreements, or SLAs, with affiliates of CS relating to the shares of NRG common stock held by CSF I and II in connection with the CSF Debt, discussed in Note 12, Debt and Capital Leases, under Debt Related to Capital Allocation Program. The Company entered into the SLAs due to a lack of liquidity in the stock-borrow market for NRG shares that existed at that time and in order to maintain the intended economic benefits of the CSF Debt agreements. CSF I and CSF II loaned 12,000,000 shares of NRG common stock to affiliates of CS in the first quarter 2009. Shares borrowed by affiliates of CS under the SLAs were used to replace shares borrowed by affiliates of CS from third parties in connection with CS hedging activities related to the financing agreements. The shares were treated as outstanding for corporate law purposes, but were not considered outstanding for the purpose of computing and reporting the Company's basic or diluted earnings per share, because the CS affiliates were required to return all borrowed shares (or identical shares).

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        In the fourth quarter 2009, CS returned 5,400,000 of these shares in connection with the maturity of the CSF II Debt, and 6,600,000 common shares, with a fair value of $156 million, remained outstanding at December 31, 2009. CS returned these 6,600,000 shares of NRG as part of the CSF I Debt unwind on March 2, 2010. The 12,000,000 shares of NRG common stock were returned to treasury stock and are no longer be treated as outstanding for corporate law purposes.

Preferred Stock

5.75% Preferred Stock

        On February 2, 2006, NRG completed the issuance of 2,000,000 shares of 5.75% Mandatory Convertible Preferred Stock, or 5.75% Preferred Stock, for net proceeds of $486 million, reflecting an offering price of $250 per share and the deduction of offering expenses and discounts of $14 million. Dividends on the 5.75% Preferred Stock were $14.375 per share per year, and were due and payable on a quarterly basis beginning on March 15, 2006. The 5.75% Preferred Stock agreement provided for automatic conversion into common stock on March 16, 2009, and for earlier conversion under certain circumstances.

4% Preferred Stock

        The Company's 4% Convertible Perpetual Preferred Stock, or 4% Preferred Stock, had a liquidation preference of $1,000 per share, and its holders were entitled to receive cash dividends at the rate of 4% per annum, or $40.00 per share per year, payable quarterly in arrears commencing on March 15, 2005. The 4% Preferred Stock was convertible, at the option of the holder, at any time into shares of NRG's common stock at an initial conversion price of $20.00 per share. In addition, NRG had the ability to redeem, on or after December 20, 2009, and subject to certain limitations, some or all of the 4% Preferred Stock with cash at a redemption price equal to 100% of the liquidation preference, plus accumulated but unpaid dividends, including liquidated damages, if any, to the redemption date. In the fourth quarter of 2009, NRG notified the holders of the Company's intention to redeem the 4% Preferred Stock, and the majority of the holders elected to convert their shares in response to this notification. All conversions and redemptions were completed by January 21, 2010.

Redeemable Preferred Stock

3.625% Preferred Stock

        On August 11, 2005, NRG issued 250,000 shares of 3.625% Convertible Perpetual Preferred Stock, or 3.625% Preferred Stock, which is treated as Redeemable Preferred Stock, to CS in a private placement. The 3.625% Preferred Stock amount is located after the liabilities but before the stockholders' equity section on the balance sheet, due to the fact that the preferred shares can be redeemed in cash by the shareholder. The 3.625% Preferred Stock has a liquidation preference of $1,000 per share. Holders of the 3.625% Preferred Stock are entitled to receive, out of legally available funds, cash dividends at the rate of 3.625% per annum, or $36.25 per share per year, payable in cash quarterly in arrears commencing on December 15, 2005.

        Each share of the 3.625% Preferred Stock is convertible during the 90-day period beginning August 11, 2015, at the option of NRG or the holder. Holders tendering the 3.625% Preferred Stock for conversion shall be entitled to receive, for each share of 3.625% Preferred Stock converted, $1,000 in cash and a number of shares of NRG common stock equal in value to the product of (a) the greater of (i) the difference between the average closing share price of NRG common stock on each of the twenty consecutive scheduled trading days starting on the date thirty exchange business days immediately prior to the conversion date, or the Market Price, and $29.54 and (ii) zero, times (b) 50.77. The number of NRG common stock to be delivered under the conversion feature is limited to 16,000,000 shares. If upon conversion, the Market Price is less than $19.69, then the Holder will deliver to NRG cash or a number of shares of NRG common stock equal in value to the product of (i) $19.69 minus the Market Price, times (ii) 50.77. NRG may elect to make a cash payment in lieu of delivering shares of NRG common stock in connection with such conversion, and NRG may elect to receive cash in lieu of shares of common stock, if any, from the Holder in connection with such conversion. The conversion feature is considered an embedded derivative per ASC 815 that is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815.

        If a fundamental change occurs, the holders will have the right to require NRG to repurchase all or a portion of the 3.625% Preferred Stock for a period of time after the fundamental change at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends. The 3.625% Preferred Stock is senior to all classes of common stock, and junior to all of the Company's existing and future debt obligations and all of NRG subsidiaries' existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries.

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Note 16 — Investments Accounted for by the Equity Method

        NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates, as well as other adjustments.

        The following table summarizes NRG's equity method investments, as of December 31, 2010:

 

Variable Interest Entities, or VIEs

        NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, but NRG is not the primary beneficiary, under the equity method.

        Sherbino I Wind Farm LLC — NRG owns a 50% interest in Sherbino, a joint venture with BP Wind Energy North America Inc. Sherbino is a 150MW wind farm, which commenced commercial operations in October 2008. In December 2008, Sherbino entered into a 15-year term loan facility which is non-recourse to NRG. As of December 31, 2010, the outstanding principal balance of the term loan facility was $129 million, and is secured by substantially all of Sherbino's assets and membership interests. NRG's maximum exposure to loss is limited to its equity investment, which is $101 million as of December 31, 2010.

        GenConn Energy LLC — Through its subsidiary, NRG Connecticut Peaking, NRG owns a 50% interest in GenConn, a limited liability company 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 reached commercial operation in 2010 and were released to the ISO-NE by July 2010. The Middletown project is in the advanced stages of construction, with a target commercial operation date of June 1, 2011.

        The project is expected to be funded through equity contributions from the owners and non-recourse, project level debt. As of December 31, 2010, and 2009, NRG Connecticut Peaking had $61 million and $108 million, respectively, of outstanding borrowings under an EBL, as described in Note 12 — Debt and Capital Leases. NRG Connecticut Peaking also had a note receivable due from GenConn for $62 million and $108 million as of December 31, 2010 and 2009, respectively, as discussed in Note 9, Capital Leases and Notes Receivable. When the Devon project reached its commercial operations date, NRG Connecticut Peaking repaid the $55 million portion of the EBL used to fund the Devon project, and converted $56 million of the note receivable from GenConn into equity. As of December 31, 2010, NRG had a $63 million equity investment in GenConn. NRG's maximum exposure to loss is limited to its equity investments and note receivable.

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        In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a seven-year term loan facility, and also entered into a five-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the revolving facility. GenConn began to draw under the GenConn Facility to cover costs related to the Devon project in August 2009, and the Middletown project in June 2010. As of December 31, 2010, $199 million had been drawn.

        As discussed in Note 21, Related Party Transactions, NRG earns revenues from construction management agreements with Devon and Middletown and interest income from the note receivable with GenConn.

Other Equity Investments

        Gladstone — Through a joint venture, NRG owns a 37.5% interest in Gladstone, a 1,613 megawatt coal-fueled power generation facility in Queensland, Australia. The power generation facility is managed by the joint venture participants and the facility is operated by NRG. Operating expenses incurred in connection with the operation of the facility are funded by each of the participants in proportion to their ownership interests. Coal is sourced from local mines in Queensland. NRG and the joint venture participants receive their respective share of revenues directly from the off takers in proportion to the ownership interests in the joint venture. Power generated by the facility is primarily sold to an adjacent aluminum smelter, with excess power sold to the Queensland Government owned utility under long term supply contracts.

        Avenal — On April 23, 2010, NRG, through its subsidiary NRG Solar PV LLC, acquired a 50% investment in Avenal Solar Holdings LLC, an entity created to develop three solar energy projects in Kings County, California totaling approximately 45 MW. Commercial operations for the three projects are expected in mid-2011.

Note 17 — Earnings Per Share

        Basic earnings per common share is computed by dividing net income less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. Share borrowed under the SLA (see Note 15, Capital Structure — Share Lending Agreements) were not treated as outstanding for earnings per share purposes.

        Dilutive effect for equity compensation — The outstanding non-qualified stock options, non-vested restricted stock units, deferred stock units and performance units are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator for purposes of computing diluted earnings per share under the treasury stock method.

        Dilutive effect for other equity instruments — Prior to their conversion, NRG's 4% and 5.75% Preferred Stock were not considered outstanding for purposes of computing basic earnings per share. However, these instruments were considered for inclusion in the denominator for purposes of computing diluted earnings per share under the if-converted method. The if-converted method is also used to determine the dilutive effect of embedded derivatives in the Company's 3.625% Preferred Stock.

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        The reconciliation of NRG's basic earnings per share to diluted earnings per share is shown in the following table:

        The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted earnings per share:

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Note 18 — Segment Reporting

        NRG's segment structure reflects core areas of operation which are primarily segregated based on the Company's wholesale power generation, retail, thermal and chilled water business, and corporate activities. In May 2009, NRG's segment structure changed to reflect the Company's acquisition of Reliant Energy and has been incorporated as a separate reporting segment as per ASC 280, Segment Reporting. Within NRG's wholesale power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, Northeast, South Central, West and International. The Company's corporate activities include wind, solar and nuclear development, as well as Green Mountain Energy. Intersegment supply sales between Texas, Reliant Energy and Green Mountain Energy are accounted for at market.

        For the years ended December 31, 2010, and 2009, there were no customers from whom the Company derived more than 10% of the Company's consolidated revenues. The following table summarizes customers from whom NRG derived more than 10% of the Company's consolidated revenues in 2008:

 

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Note 19 — Income Taxes

        The income tax provision from continuing operations consisted of the following amounts:

        The following represents the domestic and foreign components of income from continuing operations before income tax expense:

        A reconciliation of the U.S. federal statutory rate of 35% to NRG's effective rate from continuing operations were as follows:

        The effective tax rate for the year ended December 31, 2010 differs from the statutory rate of 35% primarily due to the impact of state and local income taxes and interest on uncertain tax positions, which were partially offset by the reduction in the valuation allowance resulting from realized capital gains, as well as federal and state tax credits generated during the current year.

        The effective income tax rate for the years ended December 31, 2009, and 2008 differ from the U.S. statutory rate of 35% due to changes in the valuation allowance as a result of capital gain or losses generated during the period. In addition, the current earnings in foreign jurisdictions are taxed at rates lower than the U.S. statutory rate, including the sale of the MIBRAG facility in 2009 which resulted in minimal tax due to the local jurisdiction.

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        For the year ended December 31, 2009, NRG's state effective income tax rate has been reduced to 3%, which is lower than its 2008 rate of 6%, due to increased operational activities within the state of Texas during the year. This decrease was primarily due to the acquisition of Reliant Energy which operates in the state of Texas.

        The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:

        The following table summarizes NRG's net deferred tax position:

Tax Receivable and Payable

        As of December 31, 2010, NRG recorded a current tax payable of $35 million that represents a tax liability due for domestic state taxes of $27 million, as well as foreign taxes payable of $8 million. In addition, NRG has a domestic tax receivable of $77 million, of which $68 million is related to property tax refunds primarily due to the New York State Empire Zone program. On October 15, 2010, the Empire Zone Designation Board upheld the previous decertification of the Company's Oswego facility from participating in the Empire Zone program. This decertification is effective from January 1, 2008, and prevents the facility from further participation in certain tax benefits provided by this program and associated with property taxes paid. The Company is considering its avenues of appeal, but believes it has adequately reserved for the outcome of this decision.

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Deferred tax assets and valuation allowance

        Net deferred tax balance — As of December 31, 2010, and 2009, NRG recorded a net deferred tax liability of $1,906 million and $1,747 million, respectively. However, due to an assessment of positive and negative evidence, including projected capital gains and available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $191 million and $233 million of tax assets, thus a valuation allowance has remained, resulting in a net deferred tax liability of $2,097 million and $1,980 million as of December 31, 2010, and 2009, respectively. NRG believes it is more likely than not that future earnings will be sufficient to utilize the Company's deferred tax assets, net of the existing valuation allowances at December 31, 2010.

        NOL carryforwards — At December 31, 2010, and 2009, the Company had cumulative state net operating losses, or NOLs, of $23 million. In addition, as of December 31, 2010, NRG has cumulative foreign NOL carryforwards of $74 million of which $22 million will expire starting 2011 through 2018 and of which $52 million do not have an expiration date.

        Valuation allowance — As of December 31, 2010, the Company's valuation allowance was reduced by $42 million.

Uncertain tax benefits

        NRG has identified uncertain tax benefits whose after-tax value was $663 million that if recognized, would impact the Company's income tax expense.

        As of December 31, 2010, and 2009, NRG has recorded a non-current tax liability of $582 and $347 million, respectively, for uncertain tax benefits resulting from taxable earnings for the period for which there are no NOLs available to offset for financial statement purposes. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. During the years ended December 31, 2010, and 2009, the Company recognized $25 million, and $9 million, respectively, in interest and penalties. As of December 31, 2010, and 2009, NRG had accrued interest and penalties related to these uncertain tax benefits of $42 and $17 million, respectively.

        Tax jurisdictions — NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including major operations located in Germany and Australia. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company's significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2004.

        The examination by the Internal Revenue Service for the years 2004 through 2006 is currently in Joint Committee review and is not considered effectively settled in accordance with ASC 740. The Company anticipates conclusion of the audit during 2011. Upon effective settlement of the audit, the result may be a reduction of the liability for uncertain tax benefits. The Company continues to be under examination for various state jurisdictions for multiple years.

        The following table reconciles the total amounts of uncertain tax benefits:

        Included in the balance at December 31, 2010, are $34 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash or use of net operating loss carryforwards to an earlier period.

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Note 20 — Stock-Based Compensation

Long-Term Incentive Plan, or LTIP

        As of December 31, 2010, and 2009, a total of 22,000,000 and 16,000,000 shares, respectively, of NRG common stock were authorized for issuance under the LTIP, subject to adjustments in the event of reorganization, recapitalization, stock split, reverse stock split, stock dividend, and a combination of shares, merger or similar change in NRG's structure or outstanding shares of common stock. There were 10,141,819 and 5,129,593 shares of common stock remaining available for grants under NRG's LTIP as of December 31, 2010, and 2009, respectively.

Non-Qualified Stock Options, or NQSOs

        NQSOs granted under the LTIP typically have three or five-year graded vesting schedules beginning on the grant date and become exercisable at the end of the requisite service period. NRG recognizes compensation costs for NQSOs on a straight-line basis over the requisite service period for the entire award. The maximum contractual term is ten years for 2.0 million of NRG's outstanding NQSOs, and six years for the remaining 3.1 million NQSOs.

        The following table summarizes the Company's NQSO activity and changes during the year:

        The following table summarizes the weighted average grant date fair value of options granted, the total intrinsic value of options exercised, and the cash received from the exercises of options:

        The fair value of the Company's NQSOs is estimated on the date of grant using the Black-Scholes option-pricing model. Significant assumptions used in the fair value model with respect to the Company's NQSOs are summarized below:

        For the years ended December 31 2010, 2009, and 2008, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the stock option. Typically, the expected term for the Company's NQSOs is based on the simple average of the contractual term and vesting term. The Company uses this simplified method as it does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate the expected term.

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Restricted Stock Units, or RSUs

        Typically, RSUs granted under the Company's LTIP fully vest three years from the date of issuance. Fair value of the RSUs is based on the closing price of NRG common stock on the date of grant. The following table summarizes the Company's non-vested RSU awards and changes during the year:

        The total fair value of RSUs vested during the years ended December 31, 2010, 2009, and 2008, was $9 million, $8 million and $22 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2010, 2009 and 2008 was $22.78, $26.13 and $39.84, respectively.

Deferred Stock Units, or DSUs

        DSUs represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period established under the terms of the award. DSUs granted under the Company's LTIP are fully vested at the date of issuance. Fair value of the DSUs, which is based on the closing price of NRG common stock on the date of grant, is recorded as compensation expense in the period of grant.

        The following table summarizes the Company's outstanding DSU awards and changes during the year:

        The aggregate intrinsic values for DSUs outstanding as of December 31, 2010, 2009, and 2008 were approximately $7 million, $7 million, and $6 million respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2010, 2009, and 2008 were $0.7 million, $0.5 million and $1.5 million, respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2010, 2009, and 2008 was $22.18, $22.77 and $35.12, respectively.

Performance Units, or PUs

        PUs granted under the Company's LTIP fully vest three years from the date of issuance. PUs granted prior to January 1, 2009, are paid out upon vesting if the closing price of NRG's common stock on the vesting date, or the Measurement Price, is equal to or greater than the Target Price. PUs granted after January 1, 2009, are paid out upon vesting if the Measurement Price is equal to or greater than Threshold Price. The Threshold Price, Target Price and Maximum Price are determined on the date of issuance. The payout for each PU will be equal to: (i) a pro-rata amount between 0.5 and 1 share of common stock, if the Measurement Price is equal to or greater than the target Threshold Price but less than the Target Price, for grants made after January 1, 2009; (ii) one share of common stock, if the Measurement Price equals the Target Price; (iii) a pro-rata amount between one and two shares of common stock, if the Measurement Price is greater than the Target Price but less than the Maximum Price; and (iv) two shares of common stock, if the Measurement Price is equal to, or greater than, the Maximum Price.

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        The following table summarizes the Company's non-vested PU awards and changes during the year:

        The weighted average grant date fair value of PUs granted during the years ended December 31, 2010, 2009, and 2008 was $22.70, $22.91 and $26.99, respectively.

        The fair value of PUs is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service period, which equals the vesting period. Significant assumptions used in the fair value model with respect to the Company's PUs are summarized below:

        For the years ended December 31 2010, 2009, and 2008, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the PU, which equals the vesting period.

Supplemental Information

        The following table summarizes NRG's total compensation expense recognized for the years presented as well as total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of December 31, 2010, for each of the four types of awards issued under the Company's LTIP. Minimum tax withholdings of $4 million, $3 million, and $10 million during 2010, 2009, and 2008, respectively, are reflected as a reduction to Additional Paid-in Capital on the Company's statement of financial position, and are reflected as operating activities on the Company's statement of cash flows.

Other Compensation Arrangements

        NRG also sponsored certain cash-settled equity award programs, under which employees are eligible to receive future cash compensation upon fulfillment of the vesting criteria for the particular program. The aggregate compensation expense for these arrangements was $1 million, $2 million and $1 million for the years ended December 31, 2010, 2009, and 2008, respectively.

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Note 21 — Related Party Transactions

        The following table summarizes NRG's material related party transactions with affiliates that are included in the Company's operating revenues, operating costs and other income and expense:

        Gladstone — NRG provides services to Gladstone, an equity method investment, under an operation and maintenance, or O&M, agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant as approved in the annual budget, as well as a base monthly fee.

        GenConn and Sherbino — Under construction management agreements, or CMAs, with GenConn and Sherbino, NRG has received fees for management, design and construction services. The construction at Sherbino was completed during 2008. In addition, NRG entered into a loan agreement with GenConn during 2009, pursuant to which it receives interest income. See further discussion in Note 16, Investments Accounted for by the Equity Method.

        MIBRAG — Prior to NRG's sale of its 50% ownership in MIBRAG on June 10, 2009, NRG rendered technical consulting services to MIBRAG under a consulting agreement and had entered into long-term coal purchase agreements with MIBRAG to supply coal to Schkopau. Subsequent to the sale, MIBRAG is no longer a related party. See further discussion in Note 4, Discontinued Operations and Dispositions.

        Kraftwerke Schkopau GBR — A subsidiary of NRG, Saale Energie GmbH, has entered into a loan agreement with Kraftwerke Schkopau GBR, a partnership between Saale and E.ON Kraftwerke GmbH, pursuant to which NRG receives interest income. See further discussion in Note 9, Capital Leases and Notes Receivable.

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Note 22 — Commitments and Contingencies

Operating Lease Commitments

        NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2040. NRG also has certain tolling arrangements to purchase power which qualifies as operating leases. Certain operating lease agreements over their lease term include provisions such as scheduled rent increases, leasehold incentives, and rent concessions. The Company recognizes the effects of these scheduled rent increases, leasehold incentives, and rent concessions on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Lease expense under operating leases was $111 million, $102 million, and $54 million for the years ended December 31, 2010, 2009, and 2008, respectively.

        Future minimum lease commitments under operating leases for the years ending after December 31, 2010, are as follows:

Coal, Gas and Transportation Commitments

        NRG has entered into long-term contractual arrangements to procure fuel and transportation services for the Company's generation assets and for the years ended December 31, 2010, 2009, and 2008, the Company purchased $1.5 billion, $1.4 billion, and $2.0 billion, respectively, under such arrangements.

        As of December 31, 2010, the Company's commitments under such outstanding agreements are estimated as follows:

Purchased Power Commitments

        NRG has purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities and do not qualify as operating leases. These contracts are not included in the consolidated balance sheet as of December 31, 2010. Minimum purchase commitment obligations are as follows as of December 31, 2010:

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Lignite Contract with Texas Westmoreland Coal Co.

        The lignite used to fuel the Texas region's Limestone facility is obtained from a surface mine, or the Jewett mine, adjacent to the Limestone facility under a long-term contract with Texas Westmoreland Coal Co., or TWCC. The contract is based on a cost-plus arrangement with incentives and penalties to ensure proper management of the mine. NRG has the flexibility to increase or decrease lignite purchases from the mine within certain ranges, including the ability to suspend or terminate lignite purchases with adequate notice. The mining period extends through 2018 with an option to further extend the mining period by two five-year intervals.

        TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, NRG will be responsible for final mine reclamation obligations. The Railroad Commission of Texas has imposed a bond obligation of $108 million on TWCC for the reclamation of this lignite mine. Pursuant to the contract with TWCC, NRG supports this obligation as follows: $50 million is guaranteed by NRG Energy, Inc., $32 million is supported by letters of credit posted by NRG, and NRG pays the cost of TWCC bonding the remaining $26 million. Additionally, NRG is required to provide additional performance assurance over TWCC's current bond obligations if required by the Railroad Commission of Texas.

First and Second Lien Structure

        NRG has granted first and second liens to certain counterparties on substantially all of the Company's assets to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of December 31, 2010, all hedges under the first and second liens were in-the-money on a counterparty aggregate basis.

Nuclear Innovation North America, LLC

        NINA, a majority-owned subsidiary of NRG established in May 2008, 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. TANE, a wholly-owned subsidiary of Toshiba Corporation, is the minority owner of NINA. 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.

        U.S. DOE Loan Guarantee — The STP Units 3 and 4 Project is currently in the final stages of the 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.

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        CPS Settlement — On March 1, 2010, an agreement was reached with CPS for NINA to acquire a controlling interest in the STP Units 3 and 4 Project through a settlement of litigation between the parties. As part of the agreement, NINA increased its ownership in the STP Units 3 and 4 Project from 50% to 92.375% and assumed full management control of the project. NRG also will pay $80 million to CPS, subject to the U.S. DOE's approval of a fully executed term sheet for a conditional U.S. DOE loan guarantee. The first $40 million would be promptly paid after acceptance of the guarantee with the remaining $40 million paid six months later. NRG also agreed to donate an additional $10 million, unconditionally, over four years in annual payments of $2.5 million to the Residential Energy Assistance Partnership, or REAP, in San Antonio. The first $2.5 million payment to REAP was made on March 17, 2010. In connection with the agreement, the Company capitalized $90 million to construction in progress within property, plant and equipment, and as of December 31, 2010, $87.5 million in liabilities remains on the condensed consolidated balance sheet for the obligations to CPS and REAP. As part of the agreement with CPS, all litigation was dismissed with prejudice.

        NINA Investment and Option Agreement — On May 10, 2010, NINA and TEPCO signed an Investment and Option Agreement whereby TEPCO agreed to acquire up to a 20% interest in NINA Investments Holdings LLC, or Holdings, a wholly-owned subsidiary of NINA, which indirectly holds NINA's ownership interest in the STP Units 3 and 4 Project. TEPCO will initially invest $155 million for a 10% share of Holdings, which includes a $30 million option premium payment to Holdings. This option, which expires approximately one year from the date of signing the Investment and Option Agreement, will enable TEPCO to buy an additional 10% of Holdings for another payment of $125 million. Pursuant to the terms of the Agreement, the closing is contingent upon NINA's acceptance of a fully executed term sheet for a conditional U.S. DOE loan guarantee. Upon its initial investment, TEPCO will hold a 9.238% interest in the STP Units 3 and 4 Project, diluting NINA's investment to 83.137% (75.2% for NRG). If TEPCO exercises its option to increase its ownership of Holdings another 10%, it will own 18.475% of the STP Units 3 and 4 Project, diluting NINA's investment to 73.90% (66.8% for NRG).

Contingencies

        Set forth below is a description of the Company's material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. Pursuant to the requirements of ASC 450 and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.

        In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

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California Department of Water Resources

        This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the Federal Energy Regulatory Commission, or FERC, abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC's review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP's appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller's market-based rate authority; (ii) that the public interest "bar" required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit's decision agreeing that the case should be remanded to the FERC to clarify the FERC's 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008, decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court's June 26, 2008, decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their reply. At this time, 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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Louisiana Generating, LLC

        On February 11, 2009, the U.S. Department of Justice, or U.S. DOJ, acting at the request of the U.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC, or LaGen, in federal district court in the Middle District of Louisiana alleging violations of the Clean Air Act, or CAA, at the Big Cajun II power plant. This is the same matter for which Notices of Violation, or NOVs, were issued to LaGen on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990's, several years prior to NRG's acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the best available control technology, or BACT, to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint includes a request for an injunction to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA's Prevention of Significant Deterioration program; (vi) award to the Department of Justice its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.

        On April 27, 2009, LaGen made several filings. 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 Prevention of Significant Deterioration, or PSD, regulations and Louisiana's Title V operating permit program. LDEQ seeks substantially similar relief to that requested by the U.S. DOJ. On February 19, 2010, the district court granted LDEQ's motion to intervene. On April 26, 2010, LaGen filed a motion to dismiss 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 RRI, totaled $385 million for RERS's "Price to Beat" Customers. It is unclear what the actual number may be. "Price to Beat" was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT's order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment with the Court of Appeals for the Third District of Texas with the first such appeal filed on the same date as the state district court judgment and the last such appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District reversed the lower court's decision ruling that CenterPoint Energy's stranded cost recovery should exclude only EMCs credited to RERS for its "Price to Beat" customers. On June 2, 2008, CenterPoint Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Court agreed to consider the CenterPoint Energy appeal as well as two related petitions for review filed by other entities. Oral argument occurred on October 6, 2009.

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

Note 23 — Regulatory Matters

        NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.

        In addition to the regulatory proceedings noted below, NRG and its subsidiaries are a party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

        California — On May 4, 2010, in Southern California Edison Company v. FERC, the U.S. Court of Appeals for the D.C. Circuit vacated FERC's acceptance of station power rules for the CAISO market, and remanded the case for further proceedings at FERC. On August 30, 2010, FERC issued an Order on Remand effectively disclaiming jurisdiction over how the states impose retail station power charges. Due to reservation-of-rights language in the California utilities' state-jurisdictional station power tariffs, FERC's ruling arguably requires California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISO's station period program (February 1, 2009, for the Company's Encina and El Segundo facilities; March 1, 2009, for the Company's Long Beach facility). Although requests for rehearing have been submitted, the Company has established an appropriate reserve.

        PJM — On June 18, 2009, FERC denied rehearing of its order dated September 19, 2008, dismissing a complaint filed by the Maryland Public Service Commission, or MDPSC, together with other load interests, against PJM challenging the results of the Reliability Pricing Model, or RPM, transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008. The complaint had sought to replace the auction-determined results for installed capacity for the 2008/2009, 2009/2010, and 2010/2011 delivery years with administratively-determined prices. On August 14, 2009, the MDPSC and the New Jersey Board of Public Utilities filed an appeal of FERC's orders. On February 8, 2011, the U.S. Court of Appeals for the D.C. Circuit denied the requested appeals.

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        Midwest ISO v. PJM — On March 8, 2010, Midwest ISO filed a complaint against PJM seeking payments from PJM related to inter-market operations and settlements for congestion costs between the systems for the period from April 2005 to the present. After exchanging allegations of amounts owed, on January 4, 2011, the Midwest ISO and PJM submitted a settlement agreement jointly releasing the other for past claims related to their joint operating agreement. The Company has reversed its immaterial accrual.

        Retail (Replacement Reserve) — On November 14, 2006, Constellation Energy Commodities Group, or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through September 27, 2006. Specifically, Constellation disputed approximately $4 million in under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong protocol. REPS, other market participants, ERCOT, and PUCT staff opposed Constellation's complaint. On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation's complaint. On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other. On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the trial court's decision. If all appeals are unsuccessful, on remand to the PUCT, it would determine the appropriate methodology for giving effect to the trial court's decision. It is not known at this time whether only Constellation's under-scheduling charges, the under-scheduling charges of all other QSEs that disputed REPS charges for the same time frame, the entire market, or some other approach would be used for any resettlement. On October 6, 2010, the parties argued the appeal before the Court of Appeals for the Third District in Austin, Texas.

        Under the PUCT ordered formula, Qualified Scheduling Entities, or QSEs, who under-scheduled capacity within any of ERCOT's four congestion zones were assessed under-scheduling charges which defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving QSEs. Under the Court's decision, all RPRS costs would be assigned to all load-serving QSEs based upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled capacity. If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS costs, REPS's share of the total RPRS costs allocated to QSEs would increase.

        Retail (Midwest ISO SECA) — Green Mountain Energy previously provided competitive retail energy supply in the Midwest ISO region during the relevant period of January 1, 2002, to December 31, 2005. By order dated November 18, 2004, FERC eliminated certain regional through-and-out transmission rates charged by transmission owners in the regional electric grids operated by the Midwest Independent Transmission Systems Operator, Inc. and PJM Interconnection, L.L.C., respectively. In order to temporarily compensate the transmission owners for revenue lost as a result of the elimination of the through-and-out transmission rates, FERC also ordered MISO, PJM and their respective transmission owners to provide for the recovery of certain Seams Elimination Charge/Cost Adjustments/Assignments, or SECA, charges effective December 1, 2004, through March 31, 2006, based on usage during 2002 and 2003. The tariff amendments filed by MISO and the MISO transmission owners allocated certain SECA charges to various zones and sub-zones within MISO, including a sub-zone called the Green Mountain Energy Company Sub-zone. Over the last several years, there has been extensive litigation before FERC relating to these charges seeking, among other things, to recover monies from Green Mountain Energy, and before the federal appellate courts. Green Mountain Energy has not paid any asserted SECA charges.

        On May 21, 2010, FERC issued two significant orders. In its Order on Rehearing, FERC denied all requests for rehearing of its past orders directing and accepting the SECA compliance filings of MISO, PJM, and the transmission owners. In its Order on Initial Decision, FERC: (1) affirmed an order by the Administrative Law Judge granting Green Mountain Energy partial summary judgment and holding Green Mountain Energy not liable for SECA charges for January — March 2006; and (2) reversed an August 2006 determination by the Administrative Law Judge that Green Mountain Energy could be held directly liable for some amount of SECA charges. Requests for rehearing are pending of the Order on Initial Decision. Several parties have filed notices of appeal of the Order on Rehearing, which are being held in abeyance pending resolution of the requests for rehearing before FERC.

        With regard to the SECA charges that had been invoiced to Green Mountain Energy, FERC determined that most of those charges, approximately $22 million plus interest, were owed not by Green Mountain Energy but rather by BP Energy — one of Green Mountain Energy's suppliers during the period at issue. On August 19, 2010, the transmission owners and MISO made compliance filings in accordance with FERC's Orders allocating SECA charges to a BP Energy Sub-zone, and making no allocation to a Green Mountain Energy sub-zone. BP Energy has not asserted any contractual claims against Green Mountain Energy. The Company has established an appropriate reserve.

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Note 24 — Environmental Matters

        The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG's facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. In general, the effect of such future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the Company's operations.

Environmental Capital Expenditures

        Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2011 through 2015 to meet NRG's environmental commitments will be approximately $721 million and are primarily associated with controls on the Company's Big Cajun and Indian River facilities. These capital expenditures, in general, are related to installation of particulate, SO₂, NO_x, and 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. This estimate reflects anticipated schedules and controls related to CAIR, the proposed CATR, MACT for mercury and the Phase II 316(b) Rule, all of which are either in development or under remand to the U.S. EPA, and, as such, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined at this time.

        NRG's current contracts with the Company's rural electrical customers in the South Central region allow for recovery of a portion of the regions' capital costs once in operation, along with a capital return incurred by complying with any change in law, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital project and the remaining duration of the contracts.

Northeast Region

        In January 2006, NRG's Indian River Operations, Inc. received a letter of informal notification from Delaware Department of Natural Resources and Environmental Control, or DNREC, stating that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study is completed, the Company is unable to predict the impact of any required remediation. On May 29, 2008, DNREC requested that NRG's Indian River Operations, Inc. participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment phase.

        Pursuant to a consent order dated September 25, 2007, between NRG and DNREC, NRG agreed to operate the four units at the Indian River plant in a manner that would limit the emissions of NO_x and SO₂, and to mothball Units 1 and 2 on May 1, 2011, and May 1, 2010, respectively. In addition, Units 3 and 4, with a combined generating capacity of approximately 565 MW, could not operate beyond December 31, 2011, unless appropriate control technology was installed on each unit. Unit 2 was mothballed as planned on May 1, 2010. On July 21, 2010, the court approved an amended consent order, pursuant to which NRG will retire Unit 3 (155 MW) by December 31, 2013, thereby extending the operable period of the unit by two years without installing additional control technology. Units 1, 2 and 4 are not affected by the amended consent order.

South Central Region

        On February 11, 2009, the U.S. DOJ, acting at the request of the U.S. EPA, commenced a lawsuit against LaGen in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to LaGen on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be found in Note 22, Commitments and Contingencies, Louisiana Generating, LLC.

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Note 25 — Cash Flow Information

        Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:

Note 26 — Guarantees

        NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company's business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is also obligated with respect to customer deposits associated with Reliant Energy and Green Mountain Energy. In some cases, NRG's maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability. In accordance with ASC 460, NRG has estimated that the current fair value for issuing these guarantees was $5.4 million as of December 31, 2010, and the liability in this amount is included in the Company's non-current liabilities.

        The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities, and other contingent liabilities by maturity:

        Letters of credit and surety bonds — As of December 31, 2010, NRG and its consolidated subsidiaries were contingently obligated for a total of $887 million under letters of credit and surety bonds. Most of these letters of credit and surety bonds are issued in support of the Company's obligations to perform under commodity agreements, financing or other arrangements. A majority of these letters of credit and surety bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms.

        Commercial sales arrangements — In connection with the purchase and sale of fuel, emission allowances and power generation products to and from third parties with respect to the operation of some of NRG's generation facilities in the United States, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments.

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        Other guarantees — NRG has issued guarantees of obligations that its subsidiaries may incur as a provision for environmental site remediation, payment of debt obligations, rail car leases, performance under purchase, EPC and operating and maintenance agreements. NRG has executed guarantees with related parties for one of its subsidiary's obligations as construction manager under EPC contracts for the construction of the two peaking power plants at GenConn's Devon and Middletown sites. See Note 16, Investments Accounted for by the Equity Method, for more information on this equity investment. The Company does not believe that it will be required to perform under these guarantees.

        In connection with the October 5, 2009, amendment of the CSRA, NRG signed guarantee agreements on behalf of its subsidiary NRG Retail, LLC guaranteeing performance under power purchase and sales contracts.

        The material indemnities, within the scope of ASC 460, are as follows:

        Asset purchases and divestitures — The purchase and sale agreements which govern NRG's asset or share investments and divestitures customarily contain indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or estimate at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.

        Other indemnities — Other indemnifications NRG has provided cover operational, tax, litigation and breaches of representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to the Company. NRG's maximum potential exposure under these indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. NRG does not have any reason to believe that the Company will be required to make any material payments under these indemnity provisions.

        Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the Company's liability exposure, it may not be able to estimate what the Company's liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.

Note 27 — Jointly Owned Plants

        Certain NRG subsidiaries own undivided interests in jointly-owned plants, described below. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. NRG is responsible for its subsidiaries' share of operating costs and direct expense and includes its proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Company's consolidated financial statements.

        The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities:

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Note 28 — Unaudited Quarterly Financial Data

        Summarized unaudited quarterly financial data is as follows:

 

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Note 29 — Condensed Consolidating Financial Information

        As of December 31, 2010, the Company had $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 8.50% Senior Notes due 2019, and $1.1 billion of 8.25% Senior Notes due 2020. These notes are guaranteed by certain of NRG's current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.

        On October 5, 2009, RERH became a guarantor subsidiary as a result of the CSRA Amendment. The consolidating financial statements hereinafter have been recast to reflect RERH as a guarantor subsidiary for the period ended December 31, 2009. RERH's cash balance on the date it became a guarantor subsidiary was $734 million.

        Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2010:

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        The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Company's Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries.

        The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commission's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.

        In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.

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NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2010

(a)

All significant intercompany transactions have been eliminated in consolidation.

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NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2010

(a)

All significant intercompany transactions have been eliminated in consolidation.

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NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2010

(a)

All significant intercompany transactions have been eliminated in consolidation.

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NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2009

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NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2009

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NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2009

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NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2008

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NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2008

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NRG ENERGY, INC.

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2010, 2009, and 2008

(a)

Significant increase reflects acquisition of Green Mountain Energy in November 2010 and Reliant Energy in May 2009.

(b)

Represents principally net amounts charged as uncollectable.

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: February 22, 2011

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POWER OF ATTORNEY

        Each person whose signature appears below constitutes and appoints David W. Crane, Michael R. Bramnick, Tanuja M. Dehne and Brian Curci, each or any of them, such person's true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person's name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

        In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 22, 2011.

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EXHIBIT INDEX

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193

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195

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196

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