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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     o

      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ          Accelerated filer o          Non-accelerated filer o

      Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes o          No þ

      As of the last business day of the most recently completed second fiscal quarter, the aggregate market value of the common stock of the registrant held by non-affiliates was approximately $3,272,968,478 based on the closing sale price of $37.60 as reported on the New York Stock Exchange.

      Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.     Yes þ          No o

      Indicate the number of shares outstanding of each of the registrant’s classes of common stock as of the latest practicable date.

Documents Incorporated by Reference:

Portions of the Proxy Statement for the 2006 Annual Meeting of Stockholders to be held on April 28, 2006

NRG ENERGY, INC. AND SUBSIDIARIES

INDEX

Glossary of Terms

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

PART I

Item 1 — Business

      For purposes of discussing our business in this Business Section of our Annual Report, “we,” “our,” “us,” the “combined company” and the “Company” refer to NRG and Texas Genco on a combined basis, together with their consolidated subsidiaries, after giving effect to the completion of the acquisition of Texas Genco, or the Acquisition. The terms “MW” and “MWh” refer to megawatts and megawatt-hours. The megawatt figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the combined company’s ownership position excluding capacity from inactive/mothballed units as of December 31, 2005. NRG has previously shown gross MWs when presenting its operations. Capacity is tested following standard industry practices. The combined company’s numbers denote saleable MWs net of internal/parasitic load. The term “expected annual baseload generation” refers to the net baseload capacity limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages).

General

      We are a leading wholesale power generation company with a significant presence in many of the major competitive power markets in the United States. We are primarily engaged in the ownership and operation of power generation facilities, purchasing fuel and transportation services to support our power plant operations, and marketing and trading energy, capacity and related products in the competitive markets in which we operate.

      On February 2, 2006, NRG acquired Texas Genco LLC by purchasing all of the outstanding equity interests in Texas Genco. The purchase price of approximately $6.1 billion consisted of approximately $4.4 billion in cash and the issuance of approximately 35.4 million shares of NRG’s common stock valued at approximately $1.7 billion, and we assumed a total of approximately $2.7 billion of Texas Genco’s outstanding debt. The purchase price is subject to adjustment due to acquisition costs. Texas Genco is now a wholly-owned subsidiary of NRG, and will be managed and accounted for as a new business segment to be referred to as NRG Texas.

      As of December 31, 2005, the combined company has a total global portfolio of 235 operating generation units at 61 power generation plants, with an aggregate generation capacity of approximately 24,580 MW. Within the United States, the combined company has a large and geographically diversified power generation portfolio with approximately 22,663 MW of generation capacity in 213 generating units at 53 plants. These power generation facilities are primarily located in our core regions in the ERCOT market (approximately 10,658 MW), and in the Northeast (approximately 7,099 MW), South Central (approximately 2,395 MW) and Western (approximately 1,044 MW) regions of the United States. Our facilities consist primarily of baseload, intermediate and peaking power generation facilities, and also include thermal energy production and energy resource recovery plants. The sale of capacity and power from baseload generation facilities accounts for the majority of our revenues and provides a stable source of cash flow. In addition, our diverse generation portfolio provides us with opportunities to capture additional revenues by selling power into our core regions during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.

      On December 27, 2005, we entered into a definitive agreement with Dynegy, Inc., to acquire Dynegy’s 50% of WCP. When completed this acquisition will give NRG sole ownership of WCP’s 1,800 MW of generation capacity in California. Our disclosures as to MWs and financial information do not include the remaining 50% interest in WCP.

Our Strategy

      Our strategy is to optimize the value of our generation assets while using that asset base as a platform for enhanced financial performance which can be sustained and expanded upon in years to come. We plan to maintain and enhance our position as a leading wholesale power generation company in the United States in a

cost effective and risk-mitigating manner in order to serve the bulk power requirements of our customer base and other entities that offer load, or otherwise consume wholesale electricity products and services in bulk. Our strategy includes the following elements:

      Increase value from our existing assets. We have a highly diversified portfolio of power generation assets in terms of region, fuel type and dispatch levels. We will continue to focus on extracting value from our portfolio by improving plant performance, reducing costs and harnessing our advantages of scale in the procurement of fuels: a strategy that we have branded “FORNRG,” or Focus on ROIC@NRG.

      Pursue intrinsic growth opportunities at existing sites in our core regions. We are favorably positioned to pursue growth opportunities through expansion of our existing generating capacity. We intend to invest in our existing assets through plant improvements, repowering and brownfield development to meet anticipated regional requirements for new capacity. We expect that these efforts will provide more efficient energy, lower our delivered cost, expand our electricity production capability and improve our ability to dispatch economically across sectors of the merit order, including baseload, intermediate and peaking generation.

      Maintain financial strength and flexibility. We remain focused on increasing cash flow and maintaining liquidity and balance sheet strength in order to ensure continued access to capital for growth; enhancing risk-adjusted returns; and providing flexibility in executing our business strategy. We will continue our focus on maintaining operational and financial controls designed to ensure that our financial position remains strong.

      Reduce the volatility of our cash flows through asset-based commodity hedging activities. We will continue to execute asset-based risk management, hedging, marketing and trading strategies within well-defined risk and liquidity guidelines in order to manage the value of our physical and contractual assets. Our marketing and hedging philosophy is centered on generating stable returns from our portfolio of power generation assets while preserving the ability to capitalize on strong spot market conditions and to capture the extrinsic value of our portfolio. We believe that we can successfully execute this strategy by taking advantage of our expertise in the trading and marketing of power and ancillary services, our knowledge of markets, our flexible financial structure and our diverse portfolio of power generation assets.

      Participate in continued industry consolidation. We will continue to pursue selective acquisitions, joint ventures and divestitures to enhance our asset mix and competitive position in our core regions to meet the fuel and dispatch requirements in these regions. We intend to concentrate on acquisition and joint venture opportunities that present attractive risk-adjusted returns. We will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures during the consolidation of the power generation industry in the United States.

Our Competitive Strengths

      Scale and diversity of assets. The combined company has one of the largest and most diversified power generation portfolios in the United States with approximately 22,663 MW of generation capacity in 213 generating units at 53 plants as of December 31, 2005. Our power generation assets are diversified by fuel type, dispatch level and region, which helps mitigate the risks associated with fuel price volatility and market demand cycles. The combined company’s U.S. baseload facilities consist of approximately 8,558 MW of generation capacity and provide the combined company with a significant source of stable cash flow, while the combined company’s intermediate and peaking facilities, with approximately 14,105 MW of generation capacity, provide the combined company with opportunities to capture the significant upside potential that can arise from time to time during periods of high demand. In addition, approximately 10% of the combined company’s domestic generation facilities have dual or multiple fuel capability, which allows most of these plants to dispatch with the lowest cost fuel option.

      The following chart demonstrates the diversification of the combined company’s generation assets:

     Stability of future cash flows. We have sold forward a significant amount of our expected baseload generation capacity for 2006 and 2007. As of December 31, 2005 the company has sold forward an average of 77% of its baseload generation in the Texas (ERCOT) market for 2006 through 2009. As of the same date, the combined company sold an average of 78% of its expected annual baseload generation in the SERC — Entergy market for 2006 through 2009, and approximately 76% of its expected annual baseload generation in the Northeast region for 2006. In addition, as of December 31, 2005, the combined company purchased forward under fixed price fuel contracts (with contractually-specified price escalators) to provide fuel for approximately 81% of its expected baseload coal generation output from 2006 to 2009.

      Favorable market dynamics for baseload power plants. As of December 31, 2005, approximately 39% of the company’s domestic generation capacity has been fueled by coal or nuclear fuel. In many of the competitive markets where we operate, the price of power typically is set by the marginal costs of natural gas-fired and oil-fired power plants. These oil and gas fired plants currently have substantially higher variable costs than our solid fuel baseload power plants. As a result of our lower marginal cost for baseload coal and nuclear generation assets, we expect such assets to generate power nearly 100% of the time they are available.

      Locational advantages. Many of our generation assets are located within densely populated areas that are characterized by significant constraints on the transmission of power from generators outside the region. Consequently, these assets are able to benefit from the higher prices that prevail for energy in these markets during periods of transmission constraints. The Company has generation assets located within New York City, southwestern Connecticut, Houston and the Los Angeles and San Diego load basins, all areas with constraints on the transmission of electricity. This allows us to capture additional revenues through offering capacity to retail electric providers and other entities serving load within the transmission constrained areas, selling power at prevailing market prices during periods of peak demand and providing ancillary services in support of system reliability.

Performance Metrics

      The following table contains a summary of NRG’s North American power generation revenues from majority-owned subsidiaries for the year 2005 (figures for our Texas facilities are not included):

     In understanding our business, we believe that certain performance metrics are particularly important. These are industry statistics defined by the North American Electric Reliability Council and are more fully described below:

      Annual Equivalent Availability Factor, or EAF: is the total available hours a unit is available in a year minus the sum of all partial outage events in a year converted to equivalent hours (EH), where EH is partial megawatts lost divided by unit net available capacity times hours of each event, and the net of these hours is divided by hours in a year to achieve EAF in percent.

      Average gross heat rate: We calculate the average heat rate for our fossil-fired power plants by dividing (a) fuel consumed in Btus by (b) KWh generated. The resultant heat rate is a measure of fuel efficiency.

      Net Capacity Factor: Net actual generation divided by net maximum capacity for the period hours.

      The tables below present the North American power generation performance metrics for owned assets discussed above for the years ended December 31, 2005 and December 31, 2004 (figures for our Texas facilities are not included):

     The tables below present the Australian power generation performance metrics discussed above for the years ended December 31, 2005 and December 31, 2004:

Generation Asset Overview

      We have a significant power generation presence in many of the major competitive power markets of the United States as set out below:

     Texas (ERCOT)

      As of December 31, 2005, Texas Genco’s generation assets in the ERCOT market consisted of approximately 5,178 MW of baseload generation assets and approximately 5,480 MW of intermediate, cyclic and peaking natural gas-fired assets. We expect that the combined company will realize a substantial majority of its revenue and cash flow from the sale of power from its three baseload power plants located in the ERCOT market that use solid fuel: W. A. Parish (coal), Limestone (lignite and PRB coal) and an undivided 44% interest in two nuclear generation units at STP (nuclear fuel). Because plants are generally dispatched in order of lowest operating cost, and approximately 73% of the net generation capacity in the ERCOT market was natural gas-fired, we expect these three baseload plants to operate nearly 100% of the time (subject to planned and forced outages) due to their low marginal costs relative to natural gas-fired plants.

      The following table summarizes the ERCOT baseload forward power sales and natural gas swap agreements that extend beyond December 31, 2005. The amounts summarized below reflect forward sales volumes and average prices as of December 31, 2005:

      As of December 31, 2005, approximately 7,099 MW of NRG’s generation capacity consisted of power plants in the Northeast region of the United States, including power plants within the control areas of the New York Independent System Operator, or NYISO, the ISO-New England, Inc., or ISO-NE, and the PJM Interconnection LLC., or PJM. Certain of these assets are located in transmission constrained areas, including approximately 1,394 MW of in-city New York City generation capacity and approximately 538 MW of southwest Connecticut generation capacity. As of December 31, 2005, NRG’s generation assets in the Northeast region consisted of approximately 1,876 MW of baseload generation assets and approximately 5,223 MW of intermediate and peaking assets.

      The following table summarizes Northeast’s baseload forward power sales that extend beyond December 31, 2005. The amounts summarized below reflect forward sales volumes and average prices as of December 31, 2005:

      As of December 31, 2005, NRG owned approximately 2,395 MW of generation capacity in the South Central region of the United States, making NRG the third largest generator in the Southeastern Electric Reliability Council/ Entergy, or SERC-Entergy, region. NRG’s generation assets in the South Central region consisted of approximately 1,489 MW of baseload generation assets and 906 MW of intermediate and peaking assets. NRG’s primary asset is the Big Cajun II coal-fired plant near Baton Rouge, where NRG has approximately 1,489 MW of generation capacity.

      The following table summarizes South Central’s baseload forward power sales that extend beyond December 31, 2005. The amounts summarized below reflect forward sales volumes and average prices as of December 31, 2005:

      As of December 31, 2005, NRG’s assets in the Western Electricity Coordinating Council, or WECC, the power market for the West Coast of the United States, included approximately 1,044 MW of generation

capacity, most of it in NRG’s 50% interest in WCP Holdings. NRG’s generation assets in the Western region consisted of approximately 1,044 MW of intermediate and peaking assets. As part of NRG’s strategy of optimizing NRG’s asset base, NRG retired approximately 265 MW of additional gross generation capacity at the Long Beach generating facility on January 1, 2005. On December 27, 2005, NRG entered into a purchase and sale agreement to acquire Dynegy’s 50% ownership interest in WCP Holdings to become the sole owner of power plants totaling approximately 1,800 MW of generation capacity in the Western region. On March 1, 2006, FERC issued an order authorizing the transaction, pursuant to section 203 of the Federal Power Act.

      As of December 31, 2005, NRG owned approximately 1,305 MW of coal fired, primarily base load generation plants in the Australian National Electricity Market (NEM) — 700 MW in the South Australian region (NRG Flinders) and 605 MW in the Queensland Region (Gladstone). NRG Flinders is a merchant generation business that derives revenue from bidding its output into the NEM, by trading the plant as a portfolio, selling derivative hedges that are not plant specific and supplying minor retail sales via contract. 180 MW of gas fired power contracted from Osborne under a long-term PPA is also traded as part of the portfolio. A hedge book is maintained such that the short to medium term revenue is secured via hedge levels up to and in the order of 75-80% of the plant output. The current book is underpinned by a medium term hedge with a major South Australian retailer. The Gladstone assets are owned through an unincorporated joint venture with other investors and NRG does not have unilateral control over management of the assets. Gladstone Power Station is fully contracted through 2029 via a PPA and a capacity purchase agreement with Boyne Smelter Limited and Enertrade, respectively. Enertrade is a state owned company that trades the excess power in the NEM.

      As of December 31, 2005, NRG had net ownership in approximately 1,467 MW of additional generating capacity in the United States. In addition to these traditional power generation facilities, NRG also owns thermal and chilled water businesses that generate approximately 1,225 MW thermal equivalents, as well as resource recovery facilities, as described below. NRG also owns interests in power plants having a generation capacity of approximately 611 MW from a hydro plant in Brazil and coal plants adjacent to our coal mines in Germany.

Power Marketing and Commercial Operations

      We seek 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 credits, fuel supplies and transportation-related services. Our principal objectives are the realization of the full market value of our asset base, including the capture of extrinsic value, the management and mitigation of commodity market risk, and the reduction of cash flow volatility over time.

      We enter into power sales and hedging arrangements via a wide range of products and contracts, including power purchase agreements, fuel supply contracts, capacity auctions, natural gas swap agreements and other financial instruments. The power purchase agreements we enter into require us to deliver MWh of power to our counterparties. Natural gas swap agreements and other financial instruments hedge the price we will receive for power to be delivered in the future.

      Before NRG acquired it, Texas Genco’s capital structure permitted the grant of second priority liens on its assets as security for Texas Genco’s obligations under certain long-term power sales agreements and related hedges. The Credit Agreement for NRG’s senior secured debt and the Indentures for NRG’s high yield notes, which became effective as of February 2, 2006, allow these arrangements to remain in place. In addition, the new debt instruments also permit us to grant second priority liens on our other assets in the United States in order to secure obligations under power sales agreements and related hedges, within certain limits. The seven trading counterparties of Texas Genco who held second priority liens on Texas Genco’s assets as of

February 2, 2006, have been offered a second priority lien on NRG’s other assets under the new structure, as additional collateral. Going forward, NRG anticipates that it will use the second lien structure to reduce the amount of cash collateral and letters of credit that it may otherwise be required to post from time to time to support its obligations under long term power sales and related hedges.

      As of February 28, 2006, our net mark-to-market exposure on the hedges that are subject to the second lien structure was $1.9 billion. The following table summarizes the utilization of the second lien structure as of December 31, 2005:

     Our largest customer under the second lien structure is J. Aron & Co., or J. Aron. The agreements with J. Aron extend through December 31, 2010, and account for approximately 26% of NRG’s baseload generation in Texas and approximately 16% of our total baseload capacity, as measured in MWh through 2010.

      In addition to the second lien described above, NRG also provides cash collateral and letters of credit to secure its obligations under hedge agreements and other power marketing contracts. As of December 31, 2005, the combined company, after giving effect to the Acquisition, had posted cash collateral (including letters of credit) to support commercial operations totaling $1.2 billion. The following table summarizes, as of December 31, 2005, the combined company collateral posted by credit rating.

Fuel Supply and Transportation

      Our fuel requirements consist primarily of nuclear fuel and various forms of fossil fuel including oil, natural gas and coal (including lignite). We obtain our oil, natural gas and coal from multiple sources. Although fossil fuels are generally available for purchase, localized shortages, transportation availability and supplier financial stability issues can and do occur. The prices of oil, natural gas and coal are subject to macro-and micro-economic forces that can change dramatically in both the short-term and the long-term. We are largely hedged for our domestic coal consumption over the next few years.

      We arrange for the purchase, transportation and delivery of coal for our coal plants via a range of coal purchase agreements, rail and barge transportation agreements and rail car lease arrangements. Coal consumption in 2006 for NRG is expected to be approximately 36 million tons, which would rank us as one of

the top five coal purchasers in the United States. In addition, approximately 92% of our coal-fired generation benefits from multiple sourcing and transportation alternatives. The Company has approximately 6,100 privately leased or owned rail cars in its transportation fleet. In addition, we intend to enter into contracts for delivery of approximately 2,700 additional rail cars within the next two years of which approximately 2,200 will replace existing rail cars. NRG has entered into rail transportation agreements that provide for substantially all of its rail transportation requirements through 2009.

      STP satisfies its fuel supply requirements by acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride, for enrichment of uranium hexafluoride and for fabrication of nuclear fuel assemblies. Through our subsidiary Texas Genco, we are party to a number of contracts covering a portion of the fuel requirements of STP for uranium, conversion and enrichment services and fuel fabrication. The table below summarizes the nuclear fuel situation at STP through the major processes:

Financial Information About Segments and Geographic Areas

      For financial information on NRG’s operations on a geographical and on a segment basis, see Item 15 — Note 21 to the Consolidated Financial Statements.

Dispositions of Non-Strategic Assets

      We continued to market our interest in our remaining non-core assets during 2005. Since 2003, we sold or made arrangements to sell a number of consolidated businesses and equity investments in an effort to reduce our debt, improve liquidity and rationalize our investments. Dispositions completed during 2005 are summarized in the following chart:

Reorganization

      We were formed in 1992 as the non-utility subsidiary of Northern States Power Company, or NSP, which was itself merged into New Century Energies, Inc. to form Xcel Energy, Inc., or Xcel Energy, in 2000. In 2002, a number of factors including the overall downturn in the power generation industry, triggered a series of credit rating downgrades which, in turn, precipitated a severe liquidity crisis at the Company. From May 14 to December 23, 2003, we and a number of our subsidiaries undertook a comprehensive reorganization and restructuring under chapter 11 of the United States Bankruptcy Code. All NRG entities have emerged from chapter 11 as of December 31, 2005. As part of our reorganization, Xcel Energy relinquished its ownership interest in us, and we became an independent public company. We no longer have any material affiliation or relationship with Xcel Energy.

Fresh Start Reporting

      As a result of our emergence from bankruptcy, we adopted Fresh Start Reporting, or Fresh Start. Under Fresh Start, our confirmed enterprise value was allocated to our assets and liabilities based on their respective fair values. See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operation — Reorganization and Emergence from Bankruptcy for additional information. 2004 was our first complete year following the adoption of Fresh Start.

Significant Customers

      For the year ended December 31, 2005 we derived approximately 50.2% of total revenues for majority owned operations from two customers: NYISO accounted for 35.6% and ISO-NE accounted for 14.6%. We account for the revenues attributable to these customers as part of our Northeast segment.

      For the year ended December 31, 2004, we derived approximately 37.8% of our total revenues from majority-owned operations from two customers. NYISO accounted for 28.6% and ISO New England accounted for 9.2%. We account for these revenues attributable to NYISO and ISO New England as part of our Northeast segment.

      For the period December 6, 2003 through December 31, 2003, we derived approximately 39.4% of our total revenues from majority-owned operations from two customers: NYISO accounted for 26.8% and ISO New England accounted for 12.6%. Revenues from NYISO and ISO New England are included in our Northeast segment.

      For the period from January 1, 2003 through December 5, 2003, sales to one customer, NYISO, accounted for 33.4% of our total revenues from majority-owned operations.

Seasonality and Price Volatility

      Annual and quarterly operating results can be significantly affected by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. We derive a majority of our annual revenues in the months of May through September, when demand for electricity is the highest in our North American markets. Further, power price volatility is generally higher in the summer months due to the effect of temperature variations. Our second most important season is winter when volatility and price spikes in underlying fuel prices have tended to drive seasonal electricity prices. Issues related to seasonality and price volatility are fairly uniform across our business segments.

Sources and Availability of Raw Materials

      Our raw material requirements primarily include various forms of fossil fuel, including oil, natural gas and coal. We obtain our oil, natural gas and coal from multiple suppliers and transportation sources and availability is generally not an issue, although localized shortages, transportation availability and supplier financial stability issues can and do occur. The prices of oil, natural gas and coal are subject to macro- and micro-economic forces that can change dramatically in both the short-term and the long-term. For example, the price of natural gas was particularly volatile in late 2005 due to infrastructure damage caused by Hurricanes Katrina and Rita. Additionally, throughout 2005, oil prices were extremely volatile due to hurricane damage, geo-political uncertainty in the Middle East and increased global oil demand. Issues related to the sources and availability of raw materials are fairly uniform across our business segments.

Plant Operations

      We provide overall support services to our generation facilities to ensure that high-level performance goals are developed, best practices are shared and resources are appropriately balanced and allocated to get the best results for us. Performance goals are set for equivalent forced outage rates, or EFOR, availability, procurement costs, operating costs and safety.

      The functional areas included in this organization include safety and security, engineering, project management, construction services, and purchasing. These services also include overall facilities management, operations strategic planning and the development and dissemination of consistent policies and practices relating to plant operations.

Environmental Controls

      Between 2002 and 2007, NRG has made, and will continue to make, investments that we believe will total approximately $125 million in its coal-fired plants in the Northeast region of the United States so that they can burn low sulfur coal from the Powder River Basin in Wyoming and Montana. These improvements have not only led to significant reductions in sulfur dioxide emissions, but have also improved the operational flexibility and financial performance of these plants. During the same period, NRG expects to invest approximately $32 million in its coal plants in the South Central region for NO_x burners and over fired air, which have led to reductions in NO_x. A significant portion of this investment may be recovered from NRG’s cooperative customers. Texas Genco and its predecessors invested over $700 million in NO_x reduction initiatives since 1999 to ensure both regulatory compliance and continued performance, and we estimate we will invest approximately $70 million in additional capital expenditures in these assets to meet pollution control requirements from 2006 to 2014.

      The following table summarizes the key existing and current forecasted plans as to environmental controls on our coal-fired units. Also see our discussion on Environmental Matters further within this Business Section:

Performance Improvement and Cost and Process Control Initiatives

      In May 2005, NRG announced FORNRG, a comprehensive cost and margin improvement program, consisting of a large number of asset, portfolio and headquarters-specific targeted initiatives. This effort has been branded as “FORNRG,” or Focus on ROIC@NRG. Projects are focused on improving plant performance, reducing purchasing and other costs and streamlining processes. A large number of initiatives are currently underway in plant operations including forced outage reductions and heat rate improvements at NRG’s major base load facilities. Additional initiatives are underway at our regional and headquarter offices as well. The ultimate objective is to produce $100 million of recurring benefits by 2008.

      There have been a number of parallel improvement programs underway at Texas Genco, which have focused on streamlining processes, right sizing the organization and running efficient operations. As part of the integration of Texas Genco into NRG, we are comparing best practices and results between NRG and Texas Genco, and we are combining purchasing programs and incorporating Texas Genco processes under the FORNRG program.

Regional Business Descriptions

      The combined company is organized into business units as described below, with each of our core regions operating as a separate unit.

      NRG’s largest business unit is located in the Texas (ERCOT) region of the United States and is comprised of investments in generation facilities located in the physical control areas of the ERCOT-ISO. These assets were acquired on February 2, 2006 as part of the Texas Genco Acquisition.

Operating Strategy

      Our business in the ERCOT region is comprised of two fundamental sets of assets: a regionally diverse set of three large solid-fuel baseload plants and a set of generally older gas-fired plants located in and around Houston. Our operating strategy to maximize value and opportunity across these two sets of assets is four pronged: (1) to ensure the availability of the baseload plants to fulfill their commercial obligations under long-term forward sales contracts already in place, (2) to manage the gas assets for profitability while ensuring the reliability and flexibility of power supply to the Houston market, (3) to take advantage of our skill sets and market/regulatory knowledge to grow the business through incremental capacity uprates and brownfield development of solid-fuel baseload units and (4) to play a leading role in the development of the ERCOT market by active membership and participation in market and regulatory issues.

      It is our strategy to sell forward up to 80% of our solid-fuel baseload capacity in ERCOT under long-term contracts. Accordingly, our primary focus will be to keep these solid-fuel baseload units running efficiently. The generation performance by fuel type for the recent three-year period is as shown below:

      On the gas-fired asset side, we will continue a dual path of contracting forward a significant portion of gas-fired capacity one to two years out while holding a portion for back-up in case there is an operational issue with one of the baseload units. For the gas-fired capacity sold forward, we offer a range of products including “virtual units” where the customer has the right to dispatch capacity as the customer needs in order to meet their physical load requirements. For the gas-fired capacity that we will continue to sell commercially into the market, we will focus on making this capacity available to the market whenever it is economic to run.

      Texas Genco’s growth efforts to date have been focused on adding incremental capacity to existing units — such as the 99 MW uprate at Limestone 2 in the spring of 2006. We will continue this effort with exploration of some additional potential opportunities at W. A. Parish as well as some scheduled uprates at STP. We have also launched a broader brownfield development initiative where we will evaluate opportunities to take advantage of our current power plant sites and other land we own as well as our deep market, regulatory, and environmental knowledge to consider the development of new solid fuel baseload units.

Facilities

      The following table describes Texas Genco’s electric power generation plants and generation capacity as of December 31, 2005:

     W.A. Parish. The W. A. Parish plant is one of the largest fossil-fired plants in the United States based on total MWs of generation capacity. The plant is located in the Houston ERCOT zone and was recognized by Platts’ Power Magazine as one of the top power plants in the United States for 2004. This plant’s power generation units include four coal-fired steam generation units with an aggregate generation capacity of 2,463 MW as of December 31, 2005. Two of these units are 649 MW steam units that were placed in commercial service in December 1977 and December 1978, respectively. The other two units are 555 MW and 610 MW steam units that were placed in commercial service in June 1980 and December 1982, respectively. All four units are serviced by two competing railroads that diversify Texas Genco’s coal transportation options at competitive prices. Texas Genco invested approximately $430 million in nitrogen oxide, or NO_x, control systems from 1999 to 2004. Each of the four coal-fired units has low- NO_x burners and selective catalytic reduction, or SCR, installed to reduce NO_x emissions. In addition, W. A. Parish Unit 8 has a scrubber installed to reduce sulfur dioxide, or SO₂, emissions. Plant efficiency projects to be completed by year end 2007 are expected to uprate the net generation capacity of W.A. Parish by 31 MW.

      Limestone. The Limestone plant is a lignite and coal-fired plant located approximately 140 miles northwest of Houston. This plant includes two steam generation units with an aggregate generation capacity of 1,614 MW as of December 31, 2005. The first unit is an 836 MW steam unit that was placed in commercial service in December 1985. The second unit is a 778 MW steam unit that was placed in commercial service in December 1986. Limestone primarily burns lignite from an on-site mine, but also burns low sulfur coal and petroleum coke. This serves to lower average fuel costs by eliminating fuel transportation costs, which can

represent up to two-thirds of delivered fuel costs for plants of this type. We own the mining equipment and facilities and a portion of the lignite reserves located at the mine. Mining operations are conducted by Texas Westmoreland Coal Co., a single purpose, wholly-owned subsidiary of Westmoreland Coal Company and the owner of a substantial portion of the remaining lignite reserves. Both units have installed low- NO_x burners to reduce NO_x emissions and scrubbers to reduce SO₂ emissions. In the second quarter of 2006 we plan to replace the high pressure and intermediate pressure turbines at Limestone Unit 2, rewinding the generator and replacing the main generator step-up transformer. This work is expected to cost approximately $33 million and to improve generation capacity by 99 MW.

      South Texas Project Electric Generating Station. STP is one of the newest and largest nuclear-powered generation plants in the United States based on total megawatts of generation capacity. This plant is located approximately 90 miles south of downtown Houston, near Bay City, Texas and consists of two generation units each representing approximately 1,250 MW of generation capacity. Plant efficiency projects to be completed by 2007 are expected to uprate the net generation capacity of STP by 73 MW (32 MW net to NRG). STP’s two generation units commenced operations in August 1988 and June 1989, respectively. For the year ended December 31, 2004, STP had a forced outage rate of 0.4% and a 97% capacity factor.

      STP is currently owned as a tenancy in common among NRG and two other co-owners. NRG owns a 44.0% (1,101 MW) interest in STP, the City of San Antonio owns a 40% interest and the City of Austin owns the remaining 16% interest. Each co-owner retains its undivided ownership interest in the two nuclear-fueled generation units and the electrical output from those units. In the event any owner desires to sell all or part of its ownership interest in STP, such sale is subject to a right of first refusal in favor of the other owners. Except for certain plant shutdown and decommissioning costs and NRC licensing liabilities, NRG is severally liable, but not jointly liable, for the expenses and liabilities of STP. The original co-owners of STP organized South Texas Project Nuclear Operating Company, or STPNOC, to operate and maintain STP. STPNOC is managed by a board of directors composed of one director appointed by each of the three co-owners, along with the chief executive officer of STPNOC. STPNOC is the NRC-licensed operator of STP. No single owner controls STPNOC and all decisions must be approved by two or more owners who collectively control more than 60% of the interests. Due to the fact that NRG owns 44% of STP, NRG effectively holds a veto right.

      In connection with the acquisition by Texas Genco of 13.2% of STP from AEP, Texas Genco, LP agreed with AEP that, for a period of ten years from May 19, 2005, Texas Genco, LP would maintain a minimum partners’ equity, determined in accordance with GAAP, of $300 million. This obligation remains in effect as an obligation of NRG.

      The two STP generation units operate under licenses granted by the NRC that expire in 2027 and 2028, respectively. These licenses may be extended for additional 20-year terms if the project satisfies NRC requirements. Adequate provisions exist for long-term on-site storage of spent nuclear fuel throughout the remaining life of the existing STP plant licenses.

Market Framework

      The ERCOT market is one of the nation’s largest and fastest growing power markets. It represents approximately 85% of the demand for power in Texas and covers the whole state, with the exception of the far west (El Paso), a large part of the Texas Panhandle and two small areas in the eastern part of the state. From 1994 through 2004, peak hourly demand in the ERCOT market grew at a compound annual rate of 3.0%, compared to a compound annual rate of growth of 2.1% in the United States for the same period. For 2004, hourly demand ranged from a low of 20,276 MW to a high of 58,506 MW. ERCOT has limited interconnections — currently limited to 856 MW of generation capacity — to other markets in the United States, and wholesale transactions within ERCOT are not subject to regulation by FERC. Any wholesale producer of power that qualifies as a power generation company under the Texas electric restructuring law and that can access the ERCOT electric power grid is allowed to sell power in the ERCOT market at unregulated rates.

      The ERCOT market has experienced significant construction of new generation plants in recent years, with over 20,000 MW of mostly natural gas-fired combined cycle generation capacity added to the market

since 2000. As of December 31, 2005, aggregate net generation capacity of approximately 81,000 MW existed in the ERCOT market, of which 73% was natural gas-fired. Approximately 20,000 MW, or 25%, was lower marginal cost generation capacity such as coal, lignite and nuclear plants. NRG’s coal and nuclear fuel baseload plants represent approximately 5,178 MW, or 26%, of the total solid fuel baseload net generation capacity in the ERCOT market. ERCOT has established a target equilibrium reserve margin level of approximately 12.5%; the reserve margin as of the latest known information on December 31, 2005 was 16.9%. Construction of new generation plants has been minimal since 2004, and we expect that reserve margins will decrease as demand gradually grows and surpasses recently added supply.

      In the ERCOT market, buyers and sellers enter into bilateral wholesale capacity, power and ancillary services contracts or may participate in the centralized ancillary services market, including balancing energy, which ERCOT administers. In the ERCOT market, a 2004 report by Henwood found that natural gas-fired plants have set the market price of wholesale power more than 90% of the time. As a result, NRG’s lower marginal cost solid-fuel baseload plants are expected to generate power nearly 100% of the time they are available.

      The ERCOT market is divided into five regions or congestion zones (Northeast, North, Houston, South and West), which reflect transmission constraints that limit the amount of power that can flow across zones. NRG’s W. A. Parish plant and all its natural gas-fired plants are located in the Houston zone, NRG’s Limestone plant is located in the North zone and STP is located in the South zone.

      The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council, or NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’ main interconnected power transmission grid. ERCOT is responsible for facilitating reliable operations of the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that power production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike power pools with independent operators in other regions of the country, the ERCOT market is not a centrally dispatched power pool and ERCOT does not procure power on behalf of its members other than to maintain the reliable operations of the transmission system. The ERCOT-ISO also serves as agent for procuring ancillary services for those who elect not to provide their own ancillary services.

      Power sales or purchases from one location to another may be constrained by the power transfer capability between locations. Under current ERCOT protocol, the commercially significant constraints and the transfer capabilities along these paths are reassessed every year and congestion costs are directly assigned to those parties causing the congestion. This has the potential to increase power generators’ exposure to the congestion costs associated with transferring power between zones.

      The PUCT has adopted a rule directing the ERCOT-ISO to develop and implement a wholesale market design that, among other things, includes a day ahead energy market and replaces the existing zonal wholesale market design with a nodal market design that is based on locational marginal prices for power. See “— Regulatory Developments — Regional Businesses — Market Developments — Texas (ERCOT) Region.” One of the stated purposes of the proposed market restructuring is to reduce local (intra-zonal) transmission congestion costs. The market redesign project is expected to take effect in 2009. We expect that implementation of any new market design will require modifications to our procedures and systems. Although we do not expect the combined company’s competitive position in the ERCOT market will be materially adversely affected by the proposed market restructuring, we do not know for certain how the planned market restructuring will affect our revenues, and some of the combined company’s plants in ERCOT may experience adverse pricing effects due to their location on the transmission grid.

PUCT Mandated Auctions

      PUCT regulation required firm entitlements to 15% of NRG’s operating installed generation capacity to be sold at auction through December 31, 2006, at opening bid prices well below NRG’s cost for 2006. On December 7, 2005, Texas Genco filed an application with the PUCT requesting the PUCT to determine that we were no longer required to conduct mandated auctions because 40% or more of the electric power

consumed by the residential and small commercial customers within the CenterPoint Energy Houston Electric, LLC certificated service area before the onset of customer choice is now provided by nonaffiliated retail electric providers. On February 6, 2006, the Staff of the PUCT reported that ERCOT had performed the analysis and calculations necessary to demonstrate that we have satisfied the 40% threshold. The Staff recommended that the petition be granted and that we be released from any further capacity auction requirements. The administrative law judge issued her proposal for decision, and a decision by the PUCT is expected in March.

      NRG’s second largest asset base is located in the Northeast region of the United States and is comprised of investments in generation facilities primarily located in the physical control areas of NYISO, the ISO-NE and PJM.

Operating Strategy

      The Northeast region strategy is focused on optimizing the value of our broad and varied generation portfolio in three interconnected and actively traded competitive markets: the NYISO, the ISO-NE and the PJM. In our Northeast markets, load serving entities generally lack their own generation capacity, much of the generation base is aging, and the current ownership of the generation is highly disaggregated. Thus, commodity prices are more volatile on an as-delivered basis than in other regions due to the distances and occasional physical constraints impacting delivery of fuels into the region. In this environment, we seek both to enhance our ability to be the low cost wholesale generator capable of delivering wholesale power to load centers within the region from multiple locations using multiple fuel sources, and to be properly compensated for delivering such wholesale power and related services. The generation performance by fuel type for the recent three-year period is as shown below:

      Several of our Connecticut assets are located in transmission-constrained load pockets and have been designated as required to be available to ISO-NE to ensure reliability. These assets are subject to reliability must-run, or RMR, agreements, which are contracts under which we agree to maintain our facilities to be available to run when needed, and are paid for providing these capability services based on our costs. We are focused on capturing the locational value of our plants that are located in or near load centers and inside chronic transmission constraints, in order to improve the economic rationale for repowering of those sites. We do this principally through the advocacy of capacity market reforms, e.g., locational installed capacity markets that generate adequate returns for wholesale power generators.

      We continue to evaluate opportunities to redevelop our existing sites as well as opportunities for acquisitions in the Northeast region. The redevelopment opportunities for our existing sites include expanding sites with high efficiency, intermediate and peaking units, converting coal or oil sites to cleaner technologies, redeveloping existing sites with projects using IGCC technology, as well as reconfiguring the existing sites to burn renewable fuel sources. Redevelopment opportunities have been identified for each site in the Northeast and we have established priorities based on expected financial returns and probability of success. To facilitate redevelopment opportunities, we are pursuing contractual arrangements to support significant redevelopment capital expenditures via direct negotiations with relevant agencies and potential power purchasers as well as through request for proposal processes. We also continue to pursue contractual arrangements to support the

construction costs of potential new facilities and acquisition opportunities through public auction processes as well as by initiating discussions with various parties on potential opportunities.

Facilities

      As of December 31, 2005, NRG’s facilities in the Northeast region consisted of approximately 7,099 MW of generation capacity, including assets located in transmission constrained areas, such as in-city New York City (1,394 MW) and southwest Connecticut (538 MW). The Northeast region power generation assets are summarized in the table below:

     The following are descriptions of our most significant revenue generating plants in the Northeast region:

      Arthur Kill. NRG’s Arthur Kill plant is a natural gas-fired power plant consisting of three units and is located on the west side of Staten Island, New York. The plant produces an aggregate generation capacity of 841 MW from two intermediate load units (Units 20 and 30) and one peak load unit (Unit GT-1). Unit 20 produces an aggregate generation capacity of 335 MW and was installed in 1959. Unit 30 produces an aggregate generation capacity of 491 MW and was installed in 1969, and both Units were converted from steam engines in the early 1990s. We may need to upgrade the plant in the future to comply with environmental regulations. If upgrades are needed it could cost several million dollars.

      Astoria Gas Turbines. Adjacent to LaGuardia airport in Queens, New York, Astoria provides power to the local New York City load pockets. The facility has an aggregate generation capacity of 553 MW from 19 operational combustion turbine engines. The turbine engines are peak gas-fired and/or oil-fired installed in the early 1970s. The engines are classified into three classes, which are then grouped into ten Astoria Gas Turbine units. These units consist of Buildings 2, 3 and 4, which have a total net generation capacity of 431 MW and will be retired in 2022. Units 5, 7 and 8, which are Class 2 turbine engines, have a net generation capacity totaling approximately 42 MW; and will be retired in 2015. Units 10, 11, 12 and 13, which are Class 3 turbine engines have a total net generation capacity of 80 MW, will be retired in 2015 as well.

      Dunkirk. NRG’s Dunkirk plant is a coal-fired plant located on Lake Erie in Dunkirk, New York. This plant produces an aggregate generation capacity of 522 MW from four baseload units. Units 1 and 2 produce up to 81 MW each and were put in service in 1950. Units 3 and 4 produce approximately 180 MW each and were put in service in 1959 and 1960, respectively. The plant is currently implementing changes to switch from eastern bituminous coal to low sulfur PRB coal in order to comply with various federal and state emissions standards, as well as the NYSDEC settlement referred to in the following paragraph. The conversion will be completed for all units by Spring 2006.

      Huntley. NRG’s Huntley plant is a coal-fired plant consisting of six units and is located in Tonawanda, New York, approximately three miles north of Buffalo. The plant has a generation capacity of 552 MW from two intermediate load units (Units 65 and 66) and two baseload units (Units 67 and 68). Units 67 and 68 generate a net capacity of approximately 190 MW each and were put in service in 1957 and 1958, respectively. Units 65 and 66 generate a net capacity of 86 MW each and were put in service between 1942 and 1954. Units 63 and 64 are currently inactive. At the end of 2005, NRG gave notice to the New York Public Service Commission, or NYPSC, of its intent to retire Units 63 and 64 in early 2006, subject to NYPSC approval. As part of a settlement reached with the New York Department of Environmental Conservation, or NYSDEC, in January 2005, NRG will reduce NOx and SOx emissions from its Huntley and Dunkirk plants through 2013 in the aggregate by over 80% and 86%, respectively. A portion of these reductions has been achieved through the switch to PRB coal and related projects completed at the plant that have already been expended or committed to.

Market Framework

      Although each of the three northeast ISOs and their respective energy markets are functionally, administratively and operationally independent, they all follow, to a certain extent, similar market designs. Each ISO dispatches power plants to meet system energy and reliability needs, and settles physical power deliveries at locational marginal prices, or LMPs, which reflect the value of energy at a specific location at the specific time it is delivered. This value is determined by an ISO-administered auction process, which evaluates and selects the least costly supplier offers or bids to create a reliable and least-cost dispatch. The ISO-sponsored LMP energy markets consist of two separate and characteristically distinct settlement time frames. The first is a security-constrained, financially firm, day-ahead unit commitment market. The second is a security-constrained, financially settled, real-time dispatch and balancing market. Prices paid in these LMP energy markets, however, are affected by, among other things, market mitigation measures which can result in lower prices associated with certain generating units that are mitigated because they are deemed to have locational market power, and by $1000/ MWh energy market price caps that are in place in all three northeast ISOs.

      In addition to energy delivery, the ISOs manage secondary markets for installed capacity, ancillary services and financial transmission rights. All of the three northeastern ISOs have realized, however, that they are not capable of supporting needed investment in new generation without well designed capacity and ancillary service markets. NYISO’s capacity market was the first to receive approval of its proposed demand curve and locational capacity reforms (which are intended to better reflect locational values of capacity resources). ISO-NE and PJM have both proposed their respective versions of reformed capacity markets, namely, a locational installed capacity market, or LICAP in ISO-NE, and a reliability pricing model, or RPM proposal in PJM. These proposals are currently pending before FERC. Also see further discussion in Item 15 — Note 26 Regulatory Matters.

      As of December 31, 2005, NRG owned approximately 2,395 MW of generating capacity in the South Central region of the United States. The region lacks an ISO and, therefore, remains a bilateral market, making it less transparent than a region with an ISO-administered energy market using large scale economic dispatch (such as the Northeast markets discussed above). Our plants in the South Central region operate as their own control area, the South Central control area. As a result, the South Central control area is capable of providing control area services, in addition to wholesale power, that enables NRG to provide full requirement

services to load serving utilities, thus making the South Central control area a competitive alternative to the integrated utilities operating in the region.

Operating Strategy

      Our South Central region seeks to capitalize on two factors: our position as a significant coal-fired generator in a market which is highly dependent on natural gas for power generation purposes; and our long-term contractual and historical service relationship with 11 rural cooperatives around Louisiana. We are working with our cooperative customers to improve contract administration, to expand their and our customer base on terms advantageous to all parties and, in some cases, to modify the terms of our contracts with respect to our current or new customers.

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

      As part of our strategy, we are examining all of our sites in the South Central region for possible brownfield development. In particular, we continue the development of the new 675 MW Big Cajun II Unit 4 super critical coal-fired generating unit. On August 22, 2005, NRG received the Title V Air Permit from the Louisiana Department of Environmental Quality. On October 14, 2005, Washington Group International was selected as the owner’s engineer. We continue to aggressively pursue equity partners and off-takers for the output of the unit. We continue to look for opportunities to acquire assets that will enhance our portfolio and long-term strategic goals.

Facilities

      NRG’s generating assets in the South Central region consist primarily of its net ownership of power generation facilities in New Roads, Louisiana, which we refer to as Big Cajun II, and also includes the Sterlington, Bayou Cove and Big Cajun peaking facilities. NRG’s power generation assets in the South Central region as of December 31, 2005 are summarized in the table below:

     Big Cajun II. Our most significant revenue generating plant in the South Central region is the Big Cajun II facility. Big Cajun II plant is a coal-fired, sub-critical heat baseload plant located along the banks of the Mississippi River, upstream from Baton Rouge. This plant includes three coal-fired generation units (Units 1, 2 and 3) with an aggregate generation capacity of 1,730 MW as of December 31, 2005, and generation capacity per unit of 580 MW, 575 MW and 575 MW, respectively. The plant uses coal supplied by the Powder River Basin and was commissioned between 1981 and 1983. NRG owns 100% of Units 1 and 2 and 58% of Unit 3 for an aggregate owned capacity of 1,489 MW (86.0%) of the plant. All three units have

been upgraded with low NOx burners and over fire air. The Unit 1 generator has recently been rewound and was optimized with a modern turbine/exciter control system. Units 2 and 3 are planned for generator rewinds, turbine/exciter control replacements and additional neural net systems in future years. These efficiency improvements are expected to cost approximately $30 million.

Market Framework

      NRG’s assets in the South Central region are located within the franchise territories of vertically integrated utilities, primarily Entergy Corp., or Entergy. Entergy performs the scheduling, reserve and reliability functions that are administered by the ISOs in certain other regions of the United States and Canada. Although the reliability functions performed are essentially the same, the primary differences between these markets lie in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counterparties. Transacting counterparties are required to reserve and purchase transmission services from the relevant transmission owners at their FERC-approved tariff rates. Included with these transmission services are the reserve and ancillary costs.

      As of December 31, 2005, NRG had long-term all-requirements contracts with 11 Louisiana distribution cooperatives. The agreements are standardized into three types, Forms A, B and C and have the terms, contract loads and customers as shown in the table below:

      NRG also has long-term contracts with the Municipal Agency of Mississippi, South Mississippi Electric Power Association, and Southwestern Electric Power Company, which collectively comprise an additional 13% of contract load.

      At peak demand periods, NRG’s Big Cajun II assets are insufficient to serve the requirements of the customers under these contracts, and at such times, NRG typically purchases power from other power producers in the region, frequently at higher prices than can be recovered under our contracts. As the loads of our customers grow, we can expect this imbalance to worsen, unless we are successful in renegotiating the terms of our long-term contracts.

      We are currently in negotiations with these customers to achieve contractual amendments that limit incremental load growth at contract rates for large industrial and municipal loads. To date, we have been successful in achieving such amendments with two of the eleven cooperative contracts.

      As a result of Hurricanes Katrina and Rita in August and September 2005, NRG recognized a loss of approximately $1.3 million for damaged assets. Four of the South Central region’s 11 cooperative customers suffered extensive losses to their distribution systems, and the region suffered a drop in contract sales during the ensuing power outages. By year-end, loads have largely returned to normal for three of the four hard-hit cooperatives, while the fourth cooperative continues to face challenges in rebuilding. The load loss and the transmission constraints had offsetting impacts on the South Central region’s margins resulting in gross margins that were $4 million below expectations. In addition, NRG created a reserve for a receivable from Entergy New Orleans of $1.9 million because of its hurricane-related bankruptcy.

      As of December 31, 2005, NRG owned approximately 1,044 MW of generating capacity in the Western region of the United States (California), of which approximately 904 MW is through a 50% interest in WCP Holdings. On December 27, 2005, NRG entered into a purchase and sale agreement to acquire Dynegy’s 50% ownership interest in West Coast Power to become the sole owner of power plants totaling approximately

1,800 MW of generation capacity in the Western region. The transaction, which is subject to regulatory approval, is expected to close in the first quarter of 2006.

Operating Strategy

      Our Western region strategy is focused on maximizing the cash flow and value associated with our generating plants while protecting and potentially realizing the commercial value of the underlying real estate in case our following initiatives do not generate value. There are three principal components to this strategy. First, we are focused on influencing market reforms in California to provide an energy market environment where our capacity can be offered into centrally administered competitive auctions, such as we see in the Northeast, and also provide for the negotiation of bilateral transactions for both energy and capacity. Second, we are preparing our sites for the construction of new capacity to meet increasing local area requirements. At El Segundo, NRG has a California Energy Commission, or CEC, permit to construct a new combined cycle plant to replace the retired units at the site. At the Long Beach site, NRG has land available to construct new peaking capacity. NRG is developing plans for site remediation and preparation in anticipation of a new request for new capacity from load serving entities. Third, we are engaged in the identification of collaborative value enhancing projects with communities and businesses located near our plants. West Coast Power’s plants are, for example, considered excellent candidates for the co-location of desalination plants. In case the said initiatives fail, we are taking active steps to assess the value of our property for non-power generation purposes. The real estate value from our plant locations is promising as two of West Coast Power’s plants are situated at choice locations on the Pacific coast.

      NRG’s assets in the Western region include three additional power plants, Red Bluff and Chowchilla (94 MW total), located in northern California that have some locational value and one plant in Henderson, Nevada (Saguaro), that is contracted to Nevada Power and two steam hosts. NRG has entered into a resource adequacy agreement with PG&E Corporation, or PG&E, for the capacity of the Red Bluff and Chowchilla units that expires December 31, 2007. The Saguaro plant in Nevada is contracted to Nevada Power through 2022, one steam host (Pioneer) whose contract expires in 2007 (with a negotiated renewal) and a steam off taker (Ocean Spray), whose contract runs through 2015. The Saguaro plant had a long-term gas supply agreement that expired in July 2005 and the plant is now exposed to the monthly spot gas market. At present, Saguaro cannot pass higher natural gas costs through to its customers, and the plant is currently experiencing negative cash flows. Consequently, during 2005, we wrote down our equity investment in Saguaro by approximately $27 million. NRG is currently researching a number of alternatives for its investment in Saguaro.

Facilities

      NRG’s power generation assets in the Western region as of December 31, 2005 are summarized in the table below:

     NRG’s assets in the Western region consist primarily of older, higher heat rate, gas-fired plants in southern California. These plants, while older and less efficient than newer combined cycle plants, possess locational advantages during peak hours when the newer, remotely located plants are unable to get through transmission congestion in southern California. As a result, the Cal ISO designated NRG’s El Segundo, Encina and Cabrillo II plants as RMR qualifying units in 2005, and therefore those plants are entitled to certain fixed-cost payments from the Cal ISO for the right to dispatch those units during periods of locational constraints. Initially, transmission upgrades by Southern California Edison and San Diego Gas and Electric in 2005 caused the Cal ISO to drop the RMR designation for both El Segundo and the Encina Unit 4 for 2006. However, Cal ISO designated Encina Unit 4 as an RMR unit in a letter to Cabrillo Power I dated December 22, 2005, and a filing requesting FERC approval of the requisite changes to Cabrillo Power I’s RMR agreement for 2006 was made on December 29, 2005. This change, if approved, will assure that Encina Units 4 and 5 will receive partial cost recovery under RMR and both units will be available in the market for 2006.

Market Framework

      The majority of NRG’s assets in the Western region are located within the control area of the Cal ISO. The Cal ISO operates a financially settled real time balancing market. There are currently no organized day ahead markets in the Western region and such forward markets in California currently operate similarly to those in the ERCOT market with all power sales and purchases consummated bilaterally between individual counterparties and scheduled for physical delivery with the Cal ISO. All plants are subject to the FERC “must offer” order, an order instituted during the energy crisis of 2000-2001 requiring any generator capable of operating and not subject to a bilateral agreement to make its capacity available to Cal ISO. The compensation paid by the Cal ISO for such service generally covers only variable costs. Additionally, California generators remain subject to a $250 per MWh price cap, another legacy of the energy crisis mentioned above. FERC approved an increase in the “softcap” from $250 per MWh to $400 per MWh, effective January 1, 2006. NRG is working with various industry groups and governmental authorities to put

market reforms in place in California that will encourage new investment and enable generators to earn acceptable returns on new and existing investments.

      WCP will continue to pursue repowering opportunities at the El Segundo, Encina and Long Beach plants where grid stability and in-load resource adequacy is needed. On December 23, 2004, the CEC approved NRG’s application for a permit to repower the existing El Segundo site and replace retired units 1 and 2 with 630 MW of new combined cycle generation. On January 19, 2005, the CEC voted unanimously to reconsider its December 23, 2004 decision to certify the repowering project. The reconsideration hearing took place on February 2, 2005 and the permit was approved by unanimous vote of the CEC. The reconsideration extended the 30-day period in which parties may petition for rehearing or seek judicial review to March 4, 2005. A petition seeking review of the CEC final order was filed with the California Supreme Court on March 14, 2005. On August 31, 2005, the California Supreme Court refused to hear the case, making that date the effective date of the permit. The El Segundo permit has as a condition the payment of $5 million by the project to the Santa Monica Bay Restoration Fund with the first $1 million being due in equally quarterly installments beginning 30 days following the disposition of all appeals. The initial quarterly payment has been made. Should we elect to repower the Long Beach site, we will do it outside of the CEC permitting process. We do not believe the CEC can legally assert jurisdiction over a Long Beach repowering project as the total anticipated megawatts added will be less than the number of megawatts retired. The California Court of Appeals, in a case involving the Los Angeles Department of Water and Power, held that the CEC jurisdiction is only required where the total megawatts added exceed the existing megawatts of capacity by over 50 megawatts.

      In California, the Cal ISO continues with its plan to move toward markets similar to PJM, NYISO and ISO-NE with its Market Redesign & Technology Upgrade, or MRTU — formerly MD02. These changes, once implemented, will re-establish a day-ahead time market and allow for multiple settlements. We view this as a vast improvement to the existing structure. In general, the Cal ISO is continuing along a path of small incremental changes rather than significant market restructuring. Although numerous stakeholder meetings have been held, the final market design remains unknown at this time. The effect of the new MRTU changes on us cannot be determined at this time. In addition to that activity, the California Public Utility Commission, or CPUC, recently issued their Resource Adequacy Order, which we believe will ultimately create greater opportunities for merchant generators in California. However, the final order did delay the implementation of local capacity requirements and allowed a liberalized phase out of firm liquidated damages contracts, which may act as a disincentive for load serving entities to contract for our capacity over the next two years. Assembly Bill 1576 which will promote and codify the recovery of costs from repowered facilities — thus making contracting from these sites more attractive to the in-state-utilities, was passed by the Senate on September 8, 2005, and signed by the Governor on September 29, 2005. This provides opportunities for the Western region, as WCP currently holds a permit for repowering up to 630 MW at the El Segundo facility and options for redevelopment at the Long Beach facility. Both facilities are positioned for possible long-term contracts as the market rules and structure fall into place in the near future.

      The CEC recently issued their 2005 Energy Report — Range of Need and Policy Recommendations To the California Public Utilities Commission, or CPUC. That study confirmed that the SCE franchise territory will require over 8,000 MW of new generation capacity by 2009; a dire prediction for a state with limited new resources coming on line and retirement of older facilities accelerating. There is some indication that the various regulatory agencies are responding to these warnings by moving to design a market that will provide the incentives to invest in new generation. The CPUC now requires that load-serving entities meet a 15-17% reserve margin by June 2006. This has prompted RFOs from load-serving entities, with the stated goal of engaging in bilateral contract negotiations with the merchant generators to secure their long-term capacity needs. Load-serving entities must demonstrate, by January 27, 2006 and by September 30 for each year thereafter that they have secured at least 90% of their capacity needs for the following year. The CPUC order requiring a demonstration of adequate capacity should present opportunities to enter into new bilateral agreements pursuant to competitive RFO processes. The Red Bluff and Chowchilla facilities have received capacity contracts for the period April 1, 2006 through December 31, 2007 from a major load serving entity.

The capacity for El Segundo Units 3 and 4 has been secured under a tolling agreement with a major load serving entity for the period May 2006 through April 2008.

      In September 2004, Governor Schwarzenegger vetoed AB2006, commonly referred to as the “re-regulation” initiative. A proposition (Proposition 80) that would amend legislation forever prohibiting “customer choice” in California was defeated in a November 2005 special election.

      As of December 31, 2005, NRG owned approximately 1,467 MW of generating capacity in other segments of the United States. NRG’s other North American power generation assets are summarized in the table below:

Australia and All Other Generation and Non-Generation Assets

      As of December 31, 2005, NRG, through certain foreign subsidiaries, had investments in power generation projects located in Australia, Germany and Brazil with approximately 1,916 MW of total generating capacity. In addition, NRG owns interests in coal mines located in Australia and Germany.

      NRG’s international power generation assets as of December 31, 2005 are summarized in the table below: