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Filed Pursuant to Rule 424(b)(5)
Registration No. 333-130549

A filing fee of $125,103.00, calculated in accordance with Rule 457(r), has been transmitted to the SEC in connection with the securities offered by means of this prospectus supplement. This fee includes the common stock issuable upon the exercise of the underwriters' over-allotment option.
PROSPECTUS SUPPLEMENT
(To Prospectus dated December 21, 2005)
20,855,057 Shares

NRG Energy, Inc.
Common Stock
 
We are offering 20,855,057 shares of our common stock. The closing of this offering is not conditioned on the consummation of our acquisition of Texas Genco LLC described elsewhere in this prospectus supplement. Concurrently with this offering, we are offering senior notes and shares of our mandatory convertible preferred stock. This offering is not conditioned on the consummation of these concurrent offerings.
Our common stock is listed on The New York Stock Exchange under the symbol “NRG.” The last reported sale price of our common stock on The New York Stock Exchange on January 25, 2006, was $49.25 per share.
Investing in our common stock involves risks. See “Risk Factors” on page S-12 of this prospectus supplement.
 	 	 	 	 	 	 	 	 	
 	 	Per Share	 	 	Total	 	
 	 	 	 	 	 	 	
Public offering price	 	$	48.7500	 	 	$	1,016,684,029	 	
Underwriting discount	 	$	1.4625	 	 	$	30,500,521	 	
Proceeds, before expenses, to NRG Energy, Inc.	 	$	47.2875	 	 	$	986,183,508	 	
The underwriters may also purchase up to an additional 3,128,259 shares from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus supplement to cover any overallotments. If the overallotment option is exercised in full, we will receive additional proceeds, before expenses, of $147,927,547.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the prospectus to which it relates is truthful or complete. Any representation to the contrary is a criminal offense.
The shares will be taken for delivery on or about January 31, 2006.
 
Joint Book-Running Managers
 	 	
MORGAN STANLEY	CITIGROUP	
 
LEHMAN BROTHERS
 	 	
 	BANC OF AMERICA SECURITIES LLC	
 	 	
 	DEUTSCHE BANK SECURITIES	
 	 	
 	GOLDMAN, SACHS & CO.	
 	 	
 	MERRILL LYNCH & CO.	
The date of this prospectus supplement is January 26, 2006.

 
TABLE OF CONTENTS
Prospectus Supplement
 	 	 	 	 	
 	 	Page	 	
 	 	 	 	
 About This Prospectus Supplement	 	 	ii	 	
 Where You Can Find More Information	 	 	ii	 	
 Incorporation of Certain Documents by Reference	 	 	ii	 	
 Disclosure Regarding Forward-Looking Statements	 	 	iii	 	
 Market and Industry Data	 	 	iv	 	
 Summary	 	 	S-1	 	
 Risk Factors	 	 	S-12	 	
 The Acquisition	 	 	S-30	 	
 Use of Proceeds	 	 	S-33	 	
 Capitalization	 	 	S-35	 	
 Price Range of Common Stock and Dividend Policy	 	 	S-37	 	
 Selected Consolidated Financial Information of NRG	 	 	S-38	 	
 Selected Consolidated Financial Information of Texas Genco	 	 	S-41	 	
 Liquidity and Capital Resources Discussion	 	 	S-44	 	
 Business	 	 	S-49	 	
 Management	 	 	S-97	 	
 Certain Relationships and Related Party Transactions	 	 	S-103	 	
 Description of Capital Stock	 	 	S-104	 	
 Description of Certain Indebtedness	 	 	S-108	 	
 Material U.S. Federal Tax Considerations For Non-U.S. Holders of Our Common Stock	 	 	S-114	 	
 Underwriting	 	 	S-117	 	
 Legal Matters	 	 	S-120	 	
Prospectus
 	 	 	 	 	 	
 	 	Page	 	
 	 	 	 	
 Where You Can Find More Information	 	 	ii	 	
 Incorporation of Certain Documents by Reference	 	 	ii	 	
 Disclosure Regarding Forward-Looking Statements	 	 	iii	 	
 NRG Energy, Inc. 	 	 	1	 	
 Description of Securities We May Offer	 	 	2	 	
 	 Debt Securities and Guarantees	 	 	2	 	
 	 Preferred Stock	 	 	4	 	
 	 Common Stock	 	 	6	 	
 Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preference Dividends	 	 	7	 	
 Use of Proceeds	 	 	8	 	
 Validity of the Securities	 	 	8	 	
 Experts	 	 	8	 	

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About This Prospectus Supplement
      This document consists of two parts. The first part is this prospectus supplement, which describes the specific terms of this offering. The second part is the accompanying prospectus, which describes more general information, some of which may not apply to this offering. You should read both this prospectus supplement and the accompanying prospectus, together with additional information described below under the headings “Where You Can Find More Information” and “Incorporation of Certain Documents by Reference.”
      If the description of the offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.
      Any statement made in this prospectus supplement or in a document incorporated or deemed to be incorporated by reference in this prospectus supplement will be deemed to be modified or superseded for purposes of this prospectus supplement to the extent that a statement contained in this prospectus supplement or in any other subsequently filed document that is also incorporated or deemed to be incorporated by reference in this prospectus supplement modifies or supersedes that statement. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to constitute a part of this prospectus supplement. See “Incorporation of Certain Documents By Reference.”
Where You Can Find More Information
      NRG files annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission, or the SEC. You can inspect and copy these reports, proxy statements and other information at the Public Reference Room of the SEC, 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. NRG’s SEC filings will also be available to you on the SEC’s website at http://www.sec.gov and through the New York Stock Exchange, 20 Broad Street, New York, NY 10005, on which NRG’s common stock is listed.
      This prospectus supplement and the accompanying prospectus, which forms a part of the registration statement, do not contain all the information that is included in the registration statement. You will find additional information about us in the registration statement. Any statements made in this prospectus supplement or the accompanying prospectus concerning the provisions of legal documents are not necessarily complete and you should read the documents that are filed as exhibits to the registration statement or otherwise filed with the SEC for a more complete understanding of the document or matter.
Incorporation of Certain Documents by Reference
      The SEC allows the “incorporation by reference” of the information filed by NRG with the SEC into this prospectus supplement, which means that important information can be disclosed to you by referring you to those documents and those documents will be considered part of this prospectus supplement. Information that NRG files later with the SEC will automatically update and supersede the previously filed information. The documents listed below and any future filings NRG makes with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, are incorporated by reference herein, after the date of this prospectus supplement but before the end of any offering made under this prospectus supplement:
 	 	 	
 	1.	NRG’s annual report on Form 10-K for the year ended December 31, 2004 filed on March 30, 2005 as amended by the current report on Form 8-K filed on December 20, 2005.	
 	 	 	
 	2.	NRG’s Definitive Proxy Statement on Schedule 14A filed on April 12, 2005.	
 	 	 	
 	3.	NRG’s quarterly reports on Form 10-Q for the quarters ended March 31, 2005 (filed on May 10, 2005), June 30, 2005 (filed on August 9, 2005) and September 30, 2005 (filed on November 7, 2005).	
 	 	 	
 	4.	NRG’s current reports on Form 8-K filed on February 24, 2005, Form 8-K filed on March 3, 2005, two Forms 8-K filed on March 30, 2005 (which do not include information deemed “furnished”), Form 8-K filed on May 24, 2005, Form 8-K/ A filed on May 24, 2005, Form 8-K/ A filed on May 25, 2005, Form 8-K filed on June 15, 2005, Form 8-K/ A filed on June 15, 2005, Form 8-K filed on	
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 	 	June 17, 2005, Form 8-K filed on July 18, 2005, Form 8-K filed on August 1, 2005, Form 8-K filed on August 3, 2005, Form 8-K filed on August 9, 2005 (which does not include information deemed “furnished”), Form 8-K filed on August 11, 2005, Form 8-K filed on September 1, 2005, Form 8-K filed on September 7, 2005 (which does not include information deemed “furnished”), Form 8-K filed on October 3, 2005, Form 8-K filed on October 12, 2005, Form 8-K filed on November 7, 2005 (which does not include information deemed “furnished”), Form 8-K filed on December 20, 2005, Form 8-K filed on December 21, 2005, Form 8-K filed on December 28, 2005 (which does not include information deemed “furnished”), Form 8-K filed on January 4, 2006, Form 8-K filed on January 5, 2006, Form 8-K/A filed on January 5, 2006, Form 8-K filed on January 13, 2006, Form 8-K filed on January 23, 2006, Form 8-K/A filed on January 23, 2006 and Form 8-K/A filed on January 26, 2006.	
 	 	 	
 	5.	The description of NRG’s common stock contained in the Registration Statement on Form 8-A dated March 22, 2004 filed with the SEC to register such securities under the Securities and Exchange Act of 1934, as amended, including any amendment or report filed for the purpose of updating such description.	
      If you make a request for such information in writing or by telephone, NRG will provide you, without charge, a copy of any or all of the information incorporated by reference in this prospectus. Any such request should be directed to:
NRG Energy, Inc.
211 Carnegie Center
Princeton, New Jersey 08540
(609) 524-4500
Attention: General Counsel
      You should rely only on the information contained in this prospectus supplement, the attached prospectus, the documents incorporated by reference and any written communication from us or the underwriters specifying the final terms of the offering. NRG has not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. NRG is not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should assume that the information appearing in this prospectus supplement is accurate as of the date on the front cover of this prospectus supplement only. NRG’s business, financial condition, results of operations and prospects may have changed since that date.
Disclosure Regarding Forward-Looking Statements
      This prospectus supplement contains, and the documents incorporated by reference herein may contain, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements are subject to certain risks, uncertainties and assumptions that include, but are not limited to, expected earnings and cash flows, future growth and financial performance and the expected benefits and other benefits of the acquisition of Texas Genco LLC described herein and typically can be identified by the use of words such as “will,” “expect,” “estimate,” “anticipate,” “forecast,” “plan,” “believe” and similar terms. Although we believe that our expectations are reasonable, we can give no assurance that these expectations will prove to have been correct, and actual results may vary materially. Factors that could cause actual results to differ materially from those contemplated above include, among others:
 	 	 	
 	•	Risks and uncertainties related to the capital markets generally, including increases in interest rates and the availability of financing for the acquisition of Texas Genco LLC;	
 	 	 	
 	•	NRG’s indebtedness and the additional indebtedness that it will incur in connection with the acquisition of Texas Genco LLC;	
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 	•	NRG’s ability to successfully complete the acquisition of Texas Genco LLC, regulatory or other limitations that may be imposed as a result of the acquisition of Texas Genco LLC, and the success of the business following the acquisition of Texas Genco LLC;	
 	 	 	
 	•	General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel or other raw materials;	
 	 	 	
 	•	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 fossil 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 we may not have adequate insurance to cover losses as a result of such hazards;	
 	 	 	
 	•	NRG’s potential inability to enter into contracts to sell power and procure fuel on terms and prices acceptable to it;	
 	 	 	
 	•	The liquidity and competitiveness of wholesale markets for energy commodities;	
 	 	 	
 	•	Changes in government regulation, including possible changes of market rules, market structures and design, rates, tariffs, environmental laws and regulations and regulatory compliance requirements;	
 	 	 	
 	•	Price mitigation strategies and other market structures or designs employed by independent system operators, or ISOs, or regional transmission organizations, or RTOs, that result in a failure to adequately compensate our generation units for all of their costs;	
 	 	 	
 	•	NRG’s ability to realize its significant deferred tax assets, including loss carry forwards;	
 	 	 	
 	•	The effectiveness of NRG’s risk management policies and procedures, and the ability of NRG’s counterparties to satisfy their financial commitments;	
 	 	 	
 	•	Counterparties’ collateral demands and other factors affecting NRG’s liquidity position and financial condition;	
 	 	 	
 	•	NRG’s ability to operate its businesses efficiently, manage capital expenditures and costs tightly (including general and administrative expenses), and generate earnings and cash flow from its asset-based businesses in relation to its debt and other obligations; and	
 	 	 	
 	•	Significant operating and financial restrictions which may be placed on NRG as a result of the financing transactions described elsewhere in this prospectus supplement.	
Market and Industry Data
      Certain market and industry data included or incorporated by reference in this prospectus supplement and in the accompanying prospectus has been obtained from third party sources that we believe to be reliable. We have not independently verified such third party information and cannot assure you of its accuracy or completeness. While we are not aware of any misstatements regarding any market, industry or similar data presented herein, such data involves risks and uncertainties and is subject to change based on various factors, including those discussed under the headings “Disclosure Regarding Forward-Looking Statements” and “Risk Factors” in this prospectus supplement.

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SUMMARY
      This summary may not contain all the information that may be important to you. You should read this entire prospectus supplement, the accompanying prospectus and those documents incorporated by reference into this prospectus supplement and the accompanying prospectus, including the risk factors and the financial data and related notes, before making an investment decision.
      In this prospectus supplement, unless otherwise indicated herein or the context otherwise indicates:
 	 	 	
 	•	the term “NRG” refers to NRG Energy, Inc., together with its consolidated subsidiaries;	
 	 	 	
 	•	the term “Texas Genco” refers to Texas Genco LLC, together with its consolidated subsidiaries;	
 	 	 	
 	•	the term “Acquisition” refers to the purchase by NRG of all the outstanding equity interests of Texas Genco, pursuant to the acquisition agreement, dated as of September 30, 2005, between NRG, Texas Genco and the sellers named therein;	
 	 	 	
 	•	the term “Financing Transactions” refers to this offering, the concurrent offering by NRG of its mandatory convertible preferred stock and its fixed rate senior notes due 2014, or the 2014 fixed rate notes, and fixed rate senior notes due 2016, or the 2016 fixed rate notes, together, the senior notes, and the application of the net proceeds therefrom, and the execution of NRG’s new senior secured credit facility and the application of the initial borrowings thereunder, each as described elsewhere in this prospectus supplement;	
 	 	 	
 	•	the term “Transactions” refers to the Acquisition, the Financing Transactions, the pending sale of Audrain Generating LLC, the pending acquisition of 50% interest in WCP (Generation) Holdings LLC and the pending sale of our 50% ownership interest in Rocky Road Power LLC, or Rocky Road;	
 	 	 	
 	•	the terms “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 pro forma effect to the completion of the Acquisition and the Financing Transactions;	
 	 	 	
 	•	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 September 30, 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 MW and MWh figures and other operational figures related to the combined company only give pro forma effect to the Acquisition and the Financing Transactions; and	
 	 	 	
 	•	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).	
Our Business
      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 the marketing of energy, capacity and related products in the competitive markets in which we operate. As of September 30, 2005, the combined company would have had a total global portfolio of 235 operating generation units at 62 power generation plants, with an aggregate generation capacity of approximately 25,041 MW. Within the United States, the combined company will have one of the largest and most diversified power generation portfolios with approximately 23,124 MW of generation capacity in 213 generating units at 54 plants as of September 30, 2005. These power generation facilities are primarily located in our core regions in the Electric Reliability Council of Texas, or ERCOT, market (approximately 11,119 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, which we refer to as the merit order, and also include thermal energy production and energy

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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.
The Texas Genco Acquisition
      On September 30, 2005, NRG entered into an acquisition agreement, or the Acquisition Agreement, with Texas Genco and each of the direct and indirect owners of equity interests in Texas Genco, or the Sellers. Pursuant to the Acquisition Agreement, NRG agreed to purchase all of the outstanding equity interests in Texas Genco for a total pro forma purchase price of approximately $6.121 billion that includes the assumption of approximately $2.7 billion of indebtedness. The purchase price is subject to adjustment, and includes an equity component valued at approximately $2.0 billion based on a price per share of $45.37 of NRG’s common stock issued to the Sellers, and an average price per share of $40.73 for the consideration with a fair value of $368 million, or the Other Consideration. As a result of the Acquisition, Texas Genco will become a wholly-owned subsidiary of NRG. Each of NRG’s and the Sellers’ obligation to consummate the Acquisition is subject to certain customary conditions, including the receipt of required regulatory consents and approvals. See “The Acquisition” for a discussion of the Acquisition.
      The closing of this offering is not conditioned on the consummation of the Acquisition. While we expect that the Acquisition will be consummated in or about the first week of February 2006, no assurance can be given that the Acquisition will be completed in accordance with the anticipated timing or at all. See “Risk Factors— Risks Related to the Offering— There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not consummated, NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.”
Our Strategy
      Our strategy is to increase the value of, and extract value from, 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 who offer load, or otherwise consume wholesale electricity products and services in bulk. Our strategy includes the following elements:
      Increase value from our existing assets. Following the Acquisition, we believe that we will 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 “ FOR NRG,” or Focus on ROIC@NRG.
      Pursue intrinsic growth opportunities at existing sites in our core regions. We believe that 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 the merit order.
      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 intend to continue our focus on maintaining operational and financial controls designed to ensure that our financial position remains strong.

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      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 leveraging our expertise in marketing 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 will have one of the largest and most diversified power generation portfolios in the United States with approximately 23,124 MW of generation capacity in 213 generating units at 54 plants as of September 30, 2005. Our power generation assets will be diversified by fuel type, dispatch level and region, which will help mitigate the risks associated with fuel price volatility and market demand cycles. The combined company’s U.S. baseload facilities, which will consist of approximately 8,558 MW of generation capacity measured as of September 30, 2005, will provide the combined company with a significant source of stable cash flow, while the combined company’s intermediate and peaking facilities, with approximately 14,566 MW of generation capacity as of September 30, 2005, will 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 will have dual or multiple fuel capability, which will allow most of these plants to dispatch with the lowest cost fuel option.
      Reliability of future cash flows. We have sold forward a significant amount of our expected baseload generation capacity for 2006 and 2007. As of September 30, 2005 the combined company would have sold forward 68% of its baseload generation in the Texas (ERCOT) market for 2006 through 2009. As of the same date, the combined company would have sold approximately 83% of its expected annual baseload generation in the Southeastern Electric Reliability Council/ Entergy, or SERC— Entergy, market for 2006 through 2009, and approximately 70% of its expected annual baseload generation in the Northeast region for 2006. In addition, as of September 30, 2005, the combined company would have purchased forward under fixed price 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 September 30, 2005, approximately 38% of the combined company’s domestic generation capacity would have 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 that currently have substantially higher variable costs than our solid fuel baseload power plants. For example, in the ERCOT market, a 2004 report by Henwood Energy Services, Inc., or Henwood, found that natural gas-fired power plants set the market price of power more than 90% of the time. 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 combined company will have generation assets located within New York City, southwestern Connecticut, Houston and the Los Angeles and San Diego load basins, all areas

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with constraints on the transmission of electricity. This allows us to capture additional revenues through offering capacity to retail electric providers and others, selling power at prevailing market prices during periods of peak demand and providing ancillary services in support of system reliability.
Summary of Risk Factors
      We are subject to a variety of risks related to our competitive position and business strategies. Some of the more significant challenges and risks include those associated with the operation of our power generation plants, volatility in power prices and fuel costs, our leveraged capital structure and extensive governmental regulation. See “Risk Factors” beginning on page S-12 for a discussion of the factors you should consider before investing in our securities.
The Financing Transactions
      The offering of common stock forms part of a larger financing plan for the Acquisition described elsewhere in this prospectus supplement. See “The Acquisition.” Concurrently with this offering, NRG intends to offer, by means of separate prospectus supplements (i) $500 million of its mandatory convertible preferred stock and (ii) $3.6 billion of its senior notes, or the New Senior Notes. See “Description of Capital Stock— Mandatory Convertible Preferred Stock” and “Description of Certain Indebtedness—New Senior Notes.” This offering, the mandatory convertible preferred stock offering and the New Senior Notes offering are expected to be consummated at or prior to the completion of the Acquisition. The closing of this offering will not necessarily be contemporaneous with the closing of the New Senior Notes offering and/or the closing of the mandatory convertible preferred stock offering. The net proceeds of the offering of the New Senior Notes will be placed into an escrow account held by the escrow agent until the consummation of the Acquisition.
      In addition, NRG intends to enter into a new senior secured credit facility at or prior to the closing of the Acquisition that will replace its existing senior secured credit facility. See “Description of Certain Indebtedness— New Senior Secured Credit Facility.” Concurrently with this offering, NRG is conducting a cash tender offer and consent solicitation with respect to (i) all of its outstanding 8% Second Priority Senior Secured Notes due 2013, or the Second Priority Notes, and (ii) all of Texas Genco’s outstanding 6.875% Senior Notes due 2014, or the Unsecured Senior Notes. The completion of the Acquisition is not conditioned on the completion of the tender offer or receipt of the consents for either the Second Priority Notes or Texas Genco’s Unsecured Senior Notes. The completion of the tender offer for the Second Priority Notes and Texas Genco’s Unsecured Senior Notes is conditioned on the completion of the Acquisition. However, NRG can waive this condition in the case of the tender offer and consent solicitation for the Second Priority Notes.
      NRG intends to use initial borrowings under its new senior secured credit facility, together with the net proceeds from this offering, the offerings of mandatory convertible preferred stock and New Senior Notes and cash on hand (i) to finance the Acquisition, (ii) to repurchase NRG’s outstanding Second Priority Notes, (iii) to repurchase Texas Genco’s outstanding Unsecured Senior Notes, (iv) to repay amounts outstanding under NRG’s existing senior secured credit facility and Texas Genco’s existing senior secured credit facility, (v) for ongoing credit needs of the combined company, including replacement of existing letters of credit and (vi) to pay related premiums, fees and expenses. In the event that NRG does not consummate the Acquisition, NRG intends to use the net proceeds from this offering for general corporate purposes. See “Use of Proceeds.”
      The closing of this offering is not contingent on the closing of the mandatory convertible preferred stock offering, the closing of the New Senior Notes offering, the effectiveness of the new senior secured credit facility, the completion of the tender offers and receipt of the consents in connection with the outstanding tender offers for NRG’s and Texas Genco’s notes or the consummation of the Acquisition. See “Risk Factors— Risks Related to the Offering— There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on

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the consummation of the Acquisition. If the Acquisition is not consummated, NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.” NRG’s obligations under the Acquisition Agreement are not conditioned upon the consummation of any or all of the Financing Transactions.
      NRG has entered into an amended and restated commitment letter, or the commitment letter, with Morgan Stanley Senior Funding, Inc., Citigroup Global Markets Inc., Lehman Commercial Paper Inc., Lehman Brothers Inc., Banc of America Bridge LLC, Deutsche Bank AG Cayman Islands Branch, Merrill Lynch Capital Corporation and Goldman Sachs Credit Partners L.P., or the bridge lenders. Under the commitment letter, the bridge lenders have committed to fund NRG’s new senior secured credit facility and provide, subject to certain conditions, the additional financing required for the Acquisition through a $5.1 billion bridge loan facility in the event that sufficient funds are not raised from this offering, the mandatory convertible preferred stock offering and/or the New Senior Notes offering. See “Description of Certain Indebtedness— Bridge Loan Facility.” In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the mandatory convertible preferred stock offering and/or the New Senior Notes offering, NRG may draw down on the bridge loan facility, in whole or in part, in order to finance the Acquisition. In the event that NRG does not consummate the mandatory convertible preferred stock offering and the New Senior Notes offering as currently contemplated and elects not to consummate the financing under the bridge loan facility, it could seek alternative sources of financing for the Acquisition, which may include, among other alternatives, the issuance in part of senior secured debt securities or borrowing in part on a senior secured basis.
Sources and Uses of Funds
      The following table sets forth the expected sources and uses of funds in connection with the Acquisition on a pro forma basis giving effect to the Transactions as if they had occurred on September 30, 2005. No assurances can be given that the information in the following table will not change depending on the nature of our financings and/or whether the Acquisition will be consummated in accordance with the anticipated timing or at all. See “Risk Factors— Risks Related to the Acquisition— Because the historical and pro forma financial information incorporated by reference or included elsewhere in this prospectus supplement may not be representative of our results as a combined company or capital structure after the Acquisition, and NRG’s and Texas Genco’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate us, NRG, Texas Genco and your investment decision,” “Risk Factors— Risks Related to the Offering— If NRG is unable to raise sufficient proceeds through other Financing Transactions described elsewhere in this prospectus supplement, NRG may draw down on a bridge loan facility in order to close the Acquisition which would significantly increase our indebtedness. If NRG elects not to consummate the financing under the bridge loan facility, NRG may seek alternative sources of financing for the Acquisition, the terms of which are unknown to us and could limit our ability to operate our business” and “Risk Factors— Risks Related to the Offering— There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not

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consummated, NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.”
 	 	 	 	 	 	 	 	 	 	
 	 	Amount	 	
Sources(1)	 	(in millions)	 	
 	 	 	 	
Gross proceeds of common stock offering	 	 	 	 	 	$	1,016	 	
New senior secured term loan facility	 	 	 	 	 	 	3,575	 	
Cash released from canceling existing funded letter of credit facility(3)	 	 	 	 	 	 	350	 	
Gross proceeds of mandatory convertible preferred stock offering	 	 	 	 	 	 	500	 	
Common stock consideration to be issued to Sellers	 	 	 	 	 	 	1,606 (2	)	
Gross proceeds of 2014 fixed rate notes offering	 	 	 	 	 	 	1,200	 	
Gross proceeds of 2016 fixed rate notes offering	 	 	 	 	 	 	2,400	 	
NRG’s cash on hand	 	 	 	 	 	 	373	 	
 	 	 	
 	Total	 	 	 	 	 	$	11,020	 	

 	 	Amount	 	
Uses	 	(in millions)	 	
 	 	 	 	
Purchase price less acquisition costs(2)	 	 	 	$	6,005	 	
Texas Genco’s cash on hand to reduce consideration	 	 	 	 	(222	)	
Refinancing:	 	 	 	 	 	 	
 	Repayment of NRG’s existing credit facilities(3)	 	877	 	 	 	 	
 	Repayment of Texas Genco’s existing credit facilities (4)	 	1,614	 	 	 	 	
 	 	 	 	 	 	
 	 	Total repayment of existing credit facilities	 	 	 	 	2,491	 	
Repurchase of NRG’s Second Priority Notes(5)	 	 	 	 	1,080	 	
Repurchase of Texas Genco’s Unsecured Senior Notes(6)	 	 	 	 	1,125	 	
Accrued interest for NRG and Texas Genco outstanding debt	 	 	 	 	52	 	
Estimated underwriting commissions, tender offer premiums, fees and expenses	 	 	 	 	489	 	
 	 	 	
 	 	Total	 	 	 	$	11,020	 	

 	 	
(1) 	NRG has entered into the commitment letter with the bridge lenders pursuant to which the bridge lenders have committed to fund NRG’s new senior secured credit facility and provide, subject to certain conditions, the additional financing required for the Acquisition through a $5.1 billion bridge loan facility in the event that this offering, the mandatory convertible preferred stock offering and/or the New Senior Notes offering are not consummated. In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the mandatory convertible preferred stock offering and the New Senior Notes offering, NRG may draw down on the bridge loan facility, in whole or in part, in order to finance the Acquisition. In the event that NRG does not consummate the mandatory convertible preferred stock offering and the New Senior Notes offering as currently contemplated and elects not to consummate the financing under the bridge loan facility, it could seek alternative sources of financing for the Acquisition, which may include, among other alternatives, the issuance in part of senior secured debt securities or borrowing in part on a senior secured basis.	
 	 	
(2) 	The common stock component of the consideration for the Acquisition is based on a fair value of $45.37 per share of NRG’s common stock and consideration with a fair value of $368 million, or the Other Consideration, which may be comprised either of an additional 9,038,125 shares of common stock, additional cash, shares of a new series of NRG’s Cumulative Preferred Stock or a combination of the foregoing. This fair value is based on an average stock price of $40.73, as prescribed by the Acquisition Agreement. The Company has elected to pay this amount in cash. This is because the foregoing table is based on a pro forma closing date of the Acquisition of September 30, 2005. To the extent the fair value of NRG’s common stock price for purposes of the equity component, and Texas Genco’s cash on hand, is different at closing of the Acquisition, this amount and the purchase price for the Acquisition will be adjusted accordingly.	
 	 	
(3) 	Before giving effect to the Acquisition and the Financing Transactions, as of September 30, 2005, NRG had $876.6 million of outstanding indebtedness under its amended and restated credit facility, which consisted of (a) $446.6 million in term loans outstanding, which term loans provide for interest at a rate of LIBOR (4.02% at September 30, 2005) plus 187.5 basis points payable quarterly and mature on December 24, 2011, (b) $80.0 million in principal amount outstanding under the revolving credit facility, which provides for interest at a rate of LIBOR (3.83% at September 30, 2005) plus 2.5% and matures on December 24, 2007 and (c) $350.0 million outstanding under the funded letter of credit facility, which provide for a participation fee of 1.875%, a deposit fee of 0.10%, and an issuance fee of 0.25%, and matures on December 24, 2011.	
 	 	
(4) 	Before giving effect to the Acquisition and Financing Transactions, as of September 30, 2005, Texas Genco had $1,614 million in term loans outstanding under its existing senior secured credit facility, which term loans provide for interest at a rate of 5.94% (as of September 30, 2005) payable at least quarterly and mature in December 2011.	
 	 	
(5) 	Before giving effect to the Acquisition and Financing Transactions, as of September 30, 2005, NRG had $1.08 billion of Second Priority Notes outstanding, which provide for cash interest at 8.0% per annum payable semiannually.	
 	 	
(6) 	Before giving effect to the Acquisition and Financing Transactions, as of September 30, 2005, Texas Genco had $1.125 billion of Unsecured Senior Notes outstanding, which provide for cash interest at 6.875% per annum payable semiannually.	
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Recent Developments
 	 	
 	Acquisitions and Dispositions	
      We anticipate that the following transactions will be consummated after the Acquisition and Financing Transactions.
      On December 8, 2005, NRG entered into an asset purchase and sale agreement to sell NRG Audrain Generating LLC, or Audrain, a gas fired 577 MW peaking facility in Vandalia, Missouri to AmerenUE, a subsidiary of Ameren Corporation. The purchase price is $115 million, subject to customary purchase price adjustments, plus the assumption of $240 million of non-recourse capital lease obligations and assignment of a $240 million note receivable. Of the $115 million in cash proceeds, approximately $93 million of the proceeds will be paid to the project lenders with the balance of approximately $22 million paid to NRG. This transaction, which is subject to regulatory approval, is expected to close during the first half of 2006.
      On December 27, 2005, NRG entered into two purchase and sale agreements with Dynegy Inc., or Dynegy, through which the companies will each simultaneously purchase the other’s interest in two jointly held entities that own power generation facilities in the states of California and Illinois, respectively. Under the purchase and sale agreement for the California interests, NRG will acquire Dynegy’s 50% interest in WCP (Generation) Holdings LLC, or WCP Holdings, for a purchase price of $205 million. As a result of this transaction, NRG will become the sole owner of power plants totaling approximately 1,800 MW in southern California. Pursuant to the terms of the purchase and sale agreement for the Illinois interests, NRG will sell to Dynegy its 50% ownership interest in the jointly held entity that owns the Rocky Road power plant, a 330 MW natural gas-fired peaking facility near Chicago, for a purchase price of $45 million. NRG will effectively fund the net purchase price of $160 million with cash held by West Coast Power LLC, or WCP. The transactions, which are conditioned upon each other and subject to regulatory approval, are expected to close in the first quarter of 2006.
      These transactions have been reflected in our pro forma financial statements as filed on our amended Current Report on Form 8-K/A filed on January 23, 2006 and our amended Current Report on Form 8-K/A filed on January 26, 2006 and incorporated herein by reference.
 	 	
 	Tender Offers and Consent Solicitations	
      On January 24, 2006, NRG announced that it had received valid tenders and consents from holders of approximately $1,078,141,353 in aggregate principal amount of Second Priority Notes and $1,125,000,000 in aggregate principal amount of Unsecured Senior Notes, representing approximately 99.78% and 100% of the outstanding Second Priority Notes and Unsecured Senior Notes, respectively, in connection with the cash tender offer and consent solicitation for the Second Priority Notes and the Unsecured Senior Notes. Consummation of the tenders offers are conditioned upon the satisfaction of certain conditions.
 
      NRG Energy, Inc. is a Delaware corporation. Our principal executive office is located at 211 Carnegie Center, Princeton, New Jersey 08540, and our telephone number at that address is (609) 524-4500. Our website is located at www.nrgenergy.com. The information on, or linked to, our website is not part of this prospectus supplement.

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The Offering
 	 	 	
Issuer	 	NRG Energy, Inc.	
 	 	 	
Securities Offered	 	20,855,057 shares of common stock.	
 	 	 	
Initial Price	 	$48.75 for each share of common stock.	
 	 	 	
Common Stock to be Outstanding After this Offering, Not Including the Option to Purchase Additional Shares, as of January 3, 2006	 	101,556,945 million shares.	
 	 	 	
Option to Purchase Additional Shares	 	To the extent that the underwriters sell more than 20,855,057 shares of common stock, the underwriters have the option to purchase up to 3,128,259 additional shares of common stock from us at the initial public offering price, less underwriting discount, within 30 days from the date of the prospectus supplement. If the underwriters exercise their option in full, we will offer an aggregate of 23,983,316 shares and we will have 104,685,204 shares of common stock outstanding.	
 	 	 	
Use of Proceeds	 	We estimate that the net proceeds of this offering, after giving effect to underwriting discounts and estimated expenses payable by us, will be approximately $985.1 million. We intend to use the net proceeds from this offering and the offerings of New Senior Notes and the mandatory convertible preferred stock, together with initial borrowings under our new senior secured credit facility and cash on hand, (i) to finance the Acquisition, (ii) to repurchase NRG’s outstanding Second Priority Notes, (iii) to repurchase Texas Genco’s outstanding Unsecured Senior Notes, (iv) to repay amounts outstanding under NRG’s existing senior secured credit facility and Texas Genco’s existing senior secured credit facility, (v) for ongoing credit needs of the combined company, including replacement of existing letters of credit and (vi) to pay related fees, premiums and expenses. See “Use of Proceeds.”	
 	 	 	
Dividends	 	NRG has not declared or paid dividends on its common stock in the past, although, subject to certain restrictions, we may do so in the future. See “Price Range of Common Stock and Dividend Policy.”	
 	 	 	
The New York Stock Exchange
Symbol	 	NRG	
      The total number of shares of common stock to be outstanding as of January 3, 2006 after this offering excludes:
 	 	 	
 	•	approximately 3,135,897 shares issuable upon the exercise of currently outstanding stock options or upon the conversion of stock units issued pursuant to our incentive plans;	
 	 	 	
 	•	13,075,986 shares reserved for future issuance upon conversion of NRG’s 4% Convertible Perpetual Preferred Stock and 8,670,000 shares reserved for future issuance upon conversion of NRG’s 3.625% Convertible Perpetual Preferred Stock; and	
 	 	 	
 	•	between approximately 8,271,200 and 10,256,400 million shares issuable upon conversion of our mandatory convertible preferred stock offered concurrently with this offering (or between approximately 1,240,680 and 1,538,460 shares of common stock if the underwriters exercise their over-allotment option in full), depending upon the price of our common stock at the time of conversion.	
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Summary Historical and Pro Forma Financial Information
      The following table presents summary historical consolidated financial information of (i) NRG as of and for the year ended December 31, 2004 and as of and for the nine months ended September 30, 2005, (ii) Texas Genco as of and for the year ended December 31, 2004 and as of and for the nine months ended September 30, 2005, and (iii) the combined company on a pro forma basis for the year ended December 31, 2004 and as of and for the nine months ended September 30, 2005, giving effect to (a) the reclassification of Audrain as a discontinued operation; see “—Recent Developments”; (b) the inclusion of the results pursuant to the ROFR (as described below); (c) the refinancing of NRG’s old debt structure; (d) the remaining Financing Transactions and subsequent Acquisition; and (e) the acquisition of the remaining 50% ownership interest in WCP Holdings and the sale of our 50% ownership interest in Rocky Road; see “—Recent Developments”.
      The summary historical consolidated financial information of NRG as of and for the year ended December 31, 2004 were derived from the audited consolidated financial information contained in the audited consolidated financial statements of NRG incorporated by reference in this prospectus supplement. The summary unaudited historical consolidated financial information for NRG as of and for the nine months ended September 30, 2005 (i) were derived from NRG’s unaudited consolidated financial statements which are incorporated by reference into this prospectus supplement, (ii) have been prepared on a similar basis to that used in the preparation of the audited financial statements of NRG and (iii) in the opinion of NRG’s management, include all adjustments necessary for a fair statement of the results for the unaudited interim period. The results for periods for less than a full year are not necessarily indicative of the results to be expected for any interim period.
      The summary historical consolidated financial information of Texas Genco as of and for the year ended December 31, 2004 were derived from the audited consolidated financial information contained in the audited consolidated financial statements of Texas Genco incorporated by reference into this prospectus supplement. The summary unaudited historical consolidated financial information for Texas Genco as of and for the nine months ended September 30, 2005 (i) were derived from Texas Genco’s unaudited financial statements which are incorporated by reference into this prospectus supplement, (ii) have been prepared on a similar basis to that used in the preparation of the audited financial statements of Texas Genco, and (iii) in the opinion of Texas Genco’s management, include all adjustments necessary for a fair statement of the results for the unaudited interim period. The results for periods for less than a full year are not necessarily indicative of the results to be expected for any interim period.
      The historical financial information for WCP as of and for the year ended December 31, 2004 were derived from the audited financial statements of WCP as of and for the year ended December 31, 2004 contained as Exhibit 99.1 in NRG’s Form 10-K filed on March 30, 2005. The unaudited historical consolidated financial information as of and for the nine months ended September 30, 2005 (i) have been derived from WCP’s unaudited condensed consolidated financial statements that are included as Exhibit 99.06 to the current report on Form 8-K/A filed on January 5, 2006, (ii) have been prepared on a similar basis to that used in the preparation of the audited financial statements and (iii) in the opinion of WCP’s management, include all adjustments necessary for a fair statement of the results for the unaudited interim period.
      The unaudited pro forma combined income statement data and other financial data for the combined company for the year ended December 31, 2004 and for the nine months ended September 30, 2005 give effect to (a) the reclassification of Audrain as a discontinued operation; (b) the inclusion of the results pursuant to the ROFR; (c) the refinancing of NRG’s old debt structure; (d) the remaining Financing Transactions and subsequent Acquisition; and (e) the acquisition of the remaining 50% ownership interest in WCP Holdings and the sale of our 50% ownership interest in Rocky Road, as if they had occurred on January 1, 2004. The unaudited pro forma combined balance sheet data as of September 30, 2005 gives effect to (a) the sale of Audrain as of September 30, 2005; (b) the refinancing of NRG’s old debt structure; (c) the remaining Financing Transactions and subsequent Acquisition; and (d) the acquisition of the remaining 50% ownership interest in WCP Holdings and the sale of our 50% ownership interest in Rocky Road as if they had occurred on September 30, 2005. The adjustments reflected in the unaudited pro forma financial data are

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based on available information and assumptions management believes are reasonable. However, due to the lack of asset appraisals and a future closing date, it is difficult to estimate a pro forma allocation of purchase price for the Acquisition. For purposes of these pro forma statements we have assumed that the consideration paid in excess of the historical book value of net assets acquired is related to the step-up in fair value of Texas Genco’s emission credit inventory, a step-up in the value of Texas Genco’s fixed assets, and an increase in liabilities for assumed out-of-market contracts. Once the Acquisition is closed, the excess of the estimated purchase price may differ considerably from these assumptions based on the results of appraisals and the finalization of the purchase price allocation as a result of closing and other analyses, which NRG is obtaining. The other analyses include actuarial studies of employee benefit plans, income tax effects of the Acquisition, analyses of operations to identify assets for disposition and the evaluation of staffing requirements necessary to meet future business needs. Ultimately, the excess of the purchase price over the fair value of the net tangible and identified intangible assets acquired will be recorded as goodwill.
      The unaudited pro forma financial information is for informational purposes only, however, and is based on several assumptions, including our assumptions regarding the Financing Transactions and the Acquisition, that may prove to be inaccurate. The unaudited pro forma consolidated financial data presented below do not purport to represent what the combined company’s results of operations would actually have been had the Acquisition and the Financing Transactions in fact occurred on the dates specified above or to project the combined company’s results of operations for any future period.
      The historical consolidated financial information and the unaudited pro forma combined financial information set forth below should be read in conjunction with (i) the consolidated financial statements of NRG, the related notes thereto and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in NRG’s annual report for the year ended December 31, 2004 as amended by the current report on Form 8-K filed on December 20, 2005, and quarterly report on Form 10-Q for the nine months ended September 30, 2005, each as incorporated in this prospectus supplement by reference, (ii) the consolidated financial statements of Texas Genco and Texas Genco Holdings, Inc., the related notes thereto and Management’s Discussion and Analysis of Financial Condition and Results of Operations for the year ended December 31, 2004 and for the nine months ended September 30, 2005, each as incorporated in this prospectus supplement by reference to NRG’s current report on Form 8-K filed on December 21, 2005, (iii) the financial statements of WCP, the related notes thereto included in NRG’s annual report on Form 10-K as Exhibit 99.1 as of and for the year ended December 31, 2004 and the financial statements as of and for the nine months ended September 30, 2005 as found in Exhibit 99.06 to the current report on Form 8-K/A filed on January 5, 2006 and (iv) “Selected Consolidated Financial Information of NRG,” “Selected Consolidated Financial Information of Texas Genco,” “Risk Factors— Risks Related to the Acquisition— Because the historical and pro forma financial information incorporated by reference or included elsewhere in this prospectus supplement may not be representative of our results as a combined company or capital structure after the Acquisition, and NRG’s and Texas Genco’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate us, NRG, Texas Genco and your investment decision,” and “Risk Factors— Risks Related to the Offering— If NRG is unable to raise sufficient proceeds through other Financing Transactions described elsewhere in this prospectus supplement, NRG may draw down on a bridge loan facility in order to close the Acquisition which would significantly increase our indebtedness. If NRG elects not to consummate the financing under the bridge loan facility, NRG may seek alternative sources of financing for the Acquisition, the terms of which are unknown to us and could limit our ability to operate our business” elsewhere in this prospectus supplement. In addition, no assurance can be given that the Acquisition will be consummated in accordance with the anticipated timing or at all. See “Risk Factors— Risks Related to the Offering— There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not consummated, NRG’s common stock, and therefore our mandatory convertible preferred stock, will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.”

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 	 	NRG Energy,	 	 	Texas Genco	 	 	NRG Energy,	 	 	Texas Genco	 	 	Pro Forma Combined	 	
 	 	Inc.(1)	 	 	LLC	 	 	Inc.(1)	 	 	LLC	 	 	Company(1)(2)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	For the	 	 	 	 	 	 	 	
 	 	 	 	Period from	 	 	 	 	 	 	 	
 	 	For the Year	 	 	July 19, 2004	 	 	For the Nine	 	 	For the Nine	 	 	For the Year	 	 	For the Nine	 	
 	 	Ended	 	 	through	 	 	Months Ended	 	 	Months Ended	 	 	Ended	 	 	Months Ended	 	
 	 	December 31,	 	 	December 31,	 	 	September 30,	 	 	September 30,	 	 	December 31,	 	 	September 30,	 	
 	 	2004	 	 	2004	 	 	2005	 	 	2005	 	 	2004	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	(unaudited)	 	 	(unaudited)	 	 	(unaudited)	 	 	(unaudited)	 	
 	 	($ in thousands, except per share data)	 	
Income Statement Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating revenues	 	$	2,347,882	 	 	$	95,847	 	 	$	1,942,828	 	 	$	1,999,827	 	 	$	5,394,910	 	 	$	5,180,190	 	
Total operating costs and expenses	 	 	1,955,887	 	 	 	82,105	 	 	 	1,861,569	 	 	 	1,502,170	 	 	 	4,559,583	 	 	 	3,820,967	 	
Income/(loss) from continuing operations	 	 	159,144	 	 	 	(20,133	)	 	 	6,991	 	 	 	345,928	 	 	 	186,710	 	 	 	620,145	 	
Income/(loss) on discontinued operations, net of income taxes	 	 	26,473	 	 	 	—	 	 	 	12,612	 	 	 	—	 	 	 	NA	 	 	 	NA	 	
Net income/(loss)	 	 	185,617	 	 	 	(20,133	)	 	 	19,603	 	 	 	345,928	 	 	 	NA	 	 	 	NA	 	
Other Financial Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	$	(114,360	)	 	$	(5,744	)	 	$	(45,518	)	 	 	(73,781	)	 	 	(120,104	)	 	 	(119,299	)	
Cash flows from operating
activities	 	 	643,993	 	 	 	36,023	 	 	 	(113,802	)	 	 	408,821	 	 	 	NA	 	 	 	NA	 	
Per Share Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic earnings per share	 	$	1.86	 	 	$	(0.13	)(3)	 	$	0.07	 	 	$	2.05	 	 	$	1.01	 	 	$	4.11	 	
Diluted earnings per share	 	 	1.85	 	 	 	(0.13	)(3)	 	 	0.07	 	 	 	1.98	 	 	 	1.01	 	 	 	3.78	 	
Balance Sheet Data (at period end):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	1,103,678	 	 	$	85,939	 	 	$	504,336	 	 	$	222,393	 	 	 	NA	 	 	$	163,065	 	
Restricted cash	 	 	109,633	 	 	 	—	 	 	 	91,508	 	 	 	—	 	 	 	NA	 	 	 	91,508	 	
Total Assets	 	 	7,830,283	 	 	 	4,587,566	 	 	 	7,795,367	 	 	 	6,098,723	 	 	 	NA	 	 	 	20,831,886	 	
Total long-term debt including current maturities	 	 	3,723,854	 	 	 	2,280,105	 	 	 	3,042,398	 	 	 	2,742,910	 	 	 	NA	 	 	 	8,009,504	 	
Stockholders’ equity/(deficit)	 	 	2,692,164	 	 	 	771,516	 	 	 	2,019,168	 	 	 	773,112	 	 	 	NA	 	 	 	4,966,403	 	

(1)	NRG’s results and our pro forma results include the following items that have had a significant impact on operations during the periods indicated below:	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Pro Forma	 	
 	 	NRG Energy, Inc.	 	 	Combined Company	 	
 	 	 	 	 	 	 	
 	 	For the Year	 	 	For the Nine	 	 	For the Year	 	 	For the Nine	 	
 	 	Ended	 	 	Months Ended	 	 	Ended	 	 	Months Ended	 	
 	 	December 31,	 	 	September 30,	 	 	December 31,	 	 	September 30,	 	
 	 	2004	 	 	2005	 	 	2004	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(unaudited)	 	 	(unaudited)	 	 	(unaudited)	 	
 	 	($ in thousands)	 	
(Income)/loss on discontinued operations, net of income taxes	 	$	26,473	 	 	$	12,612	 	 	 	—(a	)	 	 	—(a	)	
Corporate relocation charges	 	 	16,167	 	 	 	5,651	 	 	 	16,167	 	 	 	5,651	 	
Reorganization items	 	 	(13,390	)	 	 	—	 	 	 	(13,390	)	 	 	—	 	
Restructuring and impairment charges	 	 	44,661	 	 	 	6,223	 	 	 	69,009	 	 	 	6,223	 	
Gain on sale of assets	 	 	—	 	 	 	—	 	 	 	(689	)	 	 	(28,358	)	
Write downs, gains and losses on sales of equity method investments	 	 	(16,270	)	 	 	15,894	 	 	 	(16,270	)	 	 	15,894	 	
FERC authorized settlement	 	 	(38,357	)	 	 	—	 	 	 	(38,357	)	 	 	—	 	
Write down of Note Receivable	 	 	4,572	 	 	 	—	 	 	 	4,572	 	 	 	—	 	

 	(a)	Our pro forma combined company reflects items from continuing operations only.	

(2)	On May 19, 2005, pursuant to the exercise of a right of first refusal, or the ROFR, by Texas Genco, subsequent to a third party offer to American Electric Power, or AEP, in early 2004, Texas Genco acquired from AEP an additional 13.2% undivided interest in South Texas Project Electric Generating Station, or STP. As a result, Texas Genco currently owns a 44.0% undivided interest in STP. For pro forma purposes, NRG has accounted for the ROFR as a business acquisition and included the ROFR in its pro forma adjustments to the statements of operation. NRG has also accounted for the sale of Audrain, the acquisition of WCP Holdings and the sale of Rocky Road for purposes of these pro forma financial statements.	
 	 	
(3)	For the period from July 19, 2004 through December 31, 2004.	
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RISK FACTORS
      Investing in our common stock involves a high degree of risk. The risks below are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business operations. The following risks could affect our business, financial condition or results of operations. In such a case, you may lose all or part of your original investment. You should carefully consider the risks described below as well as other information and data set forth in this prospectus supplement, the accompanying prospectus and the documents incorporated by reference herein and therein before making an investment decision with respect to the common stock.
Risks Related to the Operation of our Business
 	 	
 	Many of our power generation facilities operate, wholly or partially, without long-term power sale agreements.	
      Many of our facilities operate as “merchant” facilities without long-term power sale agreements, and therefore are exposed to market fluctuations. Without the benefit of long-term power purchase agreements for certain assets, we cannot be sure that we will be able to sell any or all of the power generated by these facilities at commercially attractive rates or that these facilities will be able to operate profitably. This could lead to future impairments of our property, plant and equipment or to the closing of certain of our facilities resulting in economic losses and liabilities, which could have a material adverse effect on our results of operations, financial condition or cash flows.
 	 	
 	Our financial performance may be impacted by future decreases in oil and natural gas prices, significant and unpredictable price fluctuations in the wholesale power markets and other market factors that are beyond our control.	
      A significant percentage of the combined company’s domestic revenues is derived from baseload power plants that are fueled by coal or nuclear fuel. In many of the competitive markets where NRG and Texas Genco operate, the price of power typically is set by marginal cost natural gas-fired and oil-fired power plants that currently have substantially higher variable costs than our solid fuel baseload power plants. This tends to increase the market clearing price for power. The current pricing and cost environment allows NRG’s and Texas Genco’s baseload coal and nuclear fuel generation assets to earn attractive operating margins compared to plants fueled by natural gas and oil. A decrease in oil and natural gas prices could be expected to result in a corresponding decrease in the market price of power but would generally not affect the cost of the solid fuels that NRG and Texas Genco use. This could significantly reduce the operating margins of NRG’s and Texas Genco’s baseload generation assets and materially and adversely impact NRG’s and Texas Genco’s financial performance.
      We sell all or a portion of the energy, capacity and other products from many of our facilities to wholesale power markets, including energy markets operated by independent system operators, or ISOs, or regional transmission organizations, or RTOs, as well as wholesale purchasers. We are generally not entitled to traditional cost-based regulation, therefore we sell electric generation capacity, power and ancillary services to wholesale purchasers at prices determined by the market. As a result, we are not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations depend upon current and forward market prices for power.
      Market prices for power, generation capacity and ancillary services tend to fluctuate substantially. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility from supply and demand imbalances, especially in the day-ahead and spot markets. Long-term and short-term power prices may also fluctuate substantially due to other factors outside of our control, including:
 	 	 	
 	•	increases and decreases in generation capacity in our 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;	
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 	•	changes in power transmission or fuel transportation capacity constraints or inefficiencies;	
 	 	 	
 	•	electric supply disruptions, including plant outages and transmission disruptions;	
 	 	 	
 	•	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;	
 	 	 	
 	•	availability of competitively priced alternative power sources;	
 	 	 	
 	•	development of new fuels and new technologies for the production of power;	
 	 	 	
 	•	natural disasters, wars, embargoes, terrorist attacks and other catastrophic events;	
 	 	 	
 	•	regulations and actions of the ISOs or RTOs; and	
 	 	 	
 	•	federal and state power market and environmental regulation and legislation.	
      These factors have caused NRG’s and Texas Genco’s quarterly operating results to fluctuate in the past and will continue to cause them to do so in the future.
 	 	
 	Our costs, results of operations, financial condition and cash flows could be adversely impacted by an increase in fuel prices or disruption of our fuel supplies.	
      We rely on coal, nuclear fuel derived from uranium, oil and natural gas to fuel our power generation facilities. Delivery of these fuels to our 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, we are subject to the risks of disruptions or curtailments in the production of power at our generation facilities if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
      The combined company has sold forward a substantial part 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 our obligations under these forward power sales contracts, we have entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of our forward power sales contracts do not allow us to pass through changes in fuel costs or discharge the company’s 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 our fuel supplies may therefore require us to find alternative fuel sources at higher costs, to find other sources of power to deliver to counterparties at 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 our financial performance.
      We also buy significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate, sometimes rising or falling significantly over a short period. The price we 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 our 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 of electricity, gas or coal transmission or transportation, infrastructure or other constraints or inefficiencies;	
 	 	 	
 	•	additional generating capacity;	
 	 	 	
 	•	availability of competitively priced alternative energy sources;	
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 	•	availability and levels of storage and inventory for fuel stocks;	
 	 	 	
 	•	natural gas, crude oil, refined products and coal production levels;	
 	 	 	
 	•	the creditworthiness or bankruptcy or other financial distress of market participants;	
 	 	 	
 	•	changes in market liquidity;	
 	 	 	
 	•	natural disasters, wars, embargoes, acts of terrorism and other catastrophic events;	
 	 	 	
 	•	federal, state and foreign governmental regulation and legislation; and	
 	 	 	
 	•	our creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with us.	
      Our plant operating characteristics and equipment, particularly at our 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 we may not be able to transport such coal to our facilities on a timely basis. In such case, we may not be able to run a coal facility even if it would be profitable. Operating a coal facility with lesser quality coal can lead to emission or operating problems. If we had sold forward the power from such a coal facility, we 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 our results of operations.
      Texas Genco procures approximately 70% of the fuel for its Limestone facility from a lignite mine adjacent to the plant, pursuant to a contract that expires in 2015. The contract has been the subject of past litigation over pricing and other matters, and requires the parties periodically to renegotiate both the price and volume of lignite provided. If we are unable to renegotiate the terms of the agreement, if the counterparty fails to perform, or if the mine is unable to yield sufficient quantities of lignite, we could experience a disruption of supply, which could result in a curtailment or shutdown of the Limestone plant, or could require us to acquire the fuel at higher spot market prices.
      The owners (including Texas Genco) of STP satisfy fuel supply requirements for STP by acquiring uranium concentrates and contracting to convert uranium concentrates into uranium hexafluoride, enrich uranium hexafluoride and fabricate nuclear fuel assemblies. These contracts have varying expiration dates, and most are short to medium term. A disruption in uranium supplies, or in conversion, enrichment or fabrication services, could adversely affect operations at STP or increase the fuel costs associated with operations.
 	 	
 	There may be periods when we will not be able to meet our commitments under our forward sales obligations at a reasonable cost or at all.	
      A substantial portion of the output from NRG’s units is sold forward under fixed price power sales contracts through 2010, and we also sell forward the output from our intermediate and peaking facilities when we deem it commercially advantageous to do so. Because our obligations under most of these agreements are not contingent on a unit being available to generate power, we are 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 we do not have sufficient lower cost capacity to meet our commitments under our forward sales obligations, we would be required to supply replacement power either by running our other, higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price. If we failed to deliver the contracted power, then we would be required to pay the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial.
      In NRG’s South Central region, NRG has long-term contracts with rural cooperatives that require it to serve all of the cooperatives’ requirements at prices that generally reflect the costs of coal-fired generation. At times, the output from NRG’s coal-fired Big Cajun II facility is inadequate to serve these obligations, and when that happens NRG typically purchases power from other power producers, often at a loss. NRG’s

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financial returns from its South Central region are likely to deteriorate over time as the rural cooperatives grow their customer bases, unless NRG is able to amend or renegotiate its contracts with the cooperatives or add generating capacity.
 	 	
 	Our trading operations and the use of hedging agreements could result in financial losses that negatively impact our results of operations.	
      We enter 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 our power generation operations. These activities, although intended to mitigate price volatility, expose us to other risks. When we sell power forward, we give 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 us to post significant amounts of cash collateral or other credit support to our counterparties. Further, if the values of the financial contracts change in a manner we do not anticipate, or if a counterparty fails to perform under a contract, it could harm our business, operating results or financial position.
      We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position may be improved or diminished based upon movement in commodity prices.
      From time to time we may engage in trading activities, including the trading of power, fuel and emissions credits, that are not directly related to the operation of our 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. We would expect to settle these trades financially rather than through the production of power or the delivery of fuel. This trading activity may expose us to the risk of significant financial losses which could have a material adverse effect on our business and financial condition.
 	 	
 	We may not have sufficient liquidity to hedge market risks effectively.	
      We are exposed to market risks through our 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.
      We undertake these marketing activities through agreements with various counterparties. Many of our agreements with counterparties include provisions that require us to provide guarantees, offset of netting arrangements, letters of credit, a second lien on assets and/or cash collateral to protect the counterparties against the risk of our 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 our being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or are able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as cash margin, we may not be able to manage price volatility effectively or to implement our strategy. An increase in demands from our counterparties to post letters of credit or cash collateral may negatively affect our liquidity position and financial condition.
      Further, if our facilities experience unplanned outages, we may be required to procure replacement power at spot market prices in order to fulfill contractual commitments. Without adequate liquidity to post margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities, and may have increased exposure to the volatility of spot markets.

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 	The accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.	
      We engage in commodity-related marketing and price-risk management activities in order to economically hedge our exposure to market risk with respect to:
 	 	 	
 	•	electricity sales from our generation assets;	
 	 	 	
 	•	fuel utilized by those assets; and	
 	 	 	
 	•	emission allowances.	
      We generally attempt to balance our fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations, through the use of financial and physical derivative contracts. These derivatives are accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires us 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 hedge accounting treatment. Whether a derivative qualifies for hedge accounting depends upon it meeting specific criteria used to determine if hedge accounting is and will remain appropriate for the term of the derivative. Economic hedges will not necessarily qualify for hedge accounting treatment. As a result, we are unable to predict the impact that our risk management decisions may have on our quarterly and annual operating results.
 	 	
 	Goodwill and/or other intangible assets that we will record in connection with the Acquisition are subject to mandatory annual impairment evaluations and as a result, the combined company could be required to write off some or all of this goodwill and other intangibles, which may adversely affect its financial condition and results of operations.	
      NRG will account for the Acquisition using the purchase method of accounting. The purchase price for Texas Genco will be allocated to identifiable tangible and intangible assets and assumed liabilities based on estimated fair values at the date of consummation of the Acquisition. Any unallocated portion of the purchase price will be allocated to goodwill. On a pro forma basis, approximately 23% of the pro forma combined company’s total assets will be goodwill and other intangibles, of which approximately $2.4 billion will be goodwill. In accordance with Financial Accounting Standard No. 142, “Goodwill and Other Intangible Assets,” goodwill is not amortized but is reviewed annually or more frequently for impairment and other intangibles are also reviewed at least annually or more frequently, if certain conditions exist, and may be amortized. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings which could materially adversely affect our reported results of operations and financial position in future periods.
 	 	
 	Competition in wholesale power markets may have a material adverse effect on our results of operations, cash flows and the market value of our assets.	
      We have numerous competitors in all aspects of our business, and additional competitors may enter the industry. Because many of our facilities are old, newer plants owned by our competitors are often more efficient than our aging plants, which may put some of our plants at a competitive disadvantage to the extent our competitors are able to consume the same fuel as we consume at those plants. Over time, our plants may be squeezed out of their markets, or may be unable to compete with these more efficient plants.
      In our power marketing and commercial operations, we compete on the basis of our 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, we seek 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.

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      Other companies with which we compete may have greater liquidity, 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 we do.
      Our 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 we 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 we will be able to compete successfully against current and future competitors, and any failure to do so would have a material adverse effect on our business, financial condition, results of operations and cash flow. See “Business— Competition.”
 	 	
 	Operation of power generation facilities involves significant risks that could have a material adverse effect on our revenues and results of operations.	
      The ongoing operation of our 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 our product to our 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 our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or require us to incur significant costs as a result of running one of our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. Our inability to operate our plants efficiently, manage capital expenditures and costs, and generate earnings and cash flow from our asset-based businesses in relation to our debt and other obligations could have a material adverse effect on our results of operations, financial condition or cash flows.
      While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover our lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown or non-performance by contractors or vendors.
 	 	
 	Construction, 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 our revenues and results of operations.	
      Many of our facilities are old and are likely to require periodic upgrade and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures, could result in reduced profitability.
      We 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 our financial performance and condition.
      If we make any major modifications to our power generation facilities, we may be required to install the best available control technology or to achieve the lowest achievable emissions rate, 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.
      We may also choose to undertake the repowering, refurbishment or upgrading of current facilities based on our assessment that such activity will provide adequate financial returns. Such projects often require several

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years of development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. The construction, expansion, modification and refurbishment of power generation facilities involve many additional risks, including:
 	 	 	
 	•	delays in obtaining necessary permits and licenses;	
 	 	 	
 	•	environmental remediation of soil or groundwater at contaminated sites;	
 	 	 	
 	•	interruptions to dispatch at our facilities;	
 	 	 	
 	•	supply interruptions;	
 	 	 	
 	•	work stoppages;	
 	 	 	
 	•	labor disputes;	
 	 	 	
 	•	weather interferences;	
 	 	 	
 	•	unforeseen engineering, environmental and geological problems; and	
 	 	 	
 	•	unanticipated cost overruns.	
      Any of these risks could cause our financial returns on new investments to be lower than expected, or could cause us to operate below expected capacity or availability levels, which could result in lost revenues, increased expenses, higher maintenance costs and penalties.
 	 	
 	Supplier and/or customer concentration at certain of our facilities may expose us to significant financial credit or performance risks.	
      We often rely 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 our facilities. If these suppliers cannot perform, we utilize the marketplace to provide these services. There can be no assurance that the marketplace can provide these services.
      At times, we rely 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. We have hedged a portion of our 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. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements, or at all. If we were unable to enter into replacement power purchase agreements, we would sell our plants’ power at market prices. If we were unable to enter into replacement fuel or fuel transportation purchase agreements, we would seek to purchase our plants’ fuel requirements at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price.
      In the past several years, a substantial number of companies, some of which serve as our counterparties from time to time, have experienced downgrades in their credit ratings. The failure of any supplier or customer to fulfill its contractual obligations to us could have a material adverse effect on our financial results. Consequently, the financial performance of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.
 	 	
 	We rely on power transmission facilities that we do not own or control and are subject to transmission constraints within a number of our core regions. If these facilities fail to provide us with adequate transmission capacity, we may be restricted in our ability to deliver wholesale electric power to our customers and we may either incur additional costs or forego revenues. Conversely, improvements to certain transmission systems could also reduce revenues.	
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      We depend on transmission facilities owned and operated by others to deliver the wholesale power we sell from our power generation plants to our customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be adversely impacted. If a region’s power transmission infrastructure is inadequate, our 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. We also cannot 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 we operate, energy transmission congestion may occur and we may be deemed responsible for congestion costs if we schedule delivery of power between congestion zones during times when congestion occurs between the zones. If we are liable for congestion costs, our financial results could be adversely affected.
      In the ERCOT, California ISO, New York ISO and New England ISO markets, the combined company will have a significant amount of generation located in load pockets making that generation valuable, particularly with respect to maintaining the reliability of the transmission grid. Expansion of transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of our existing facilities in these areas.
 	 	
 	Because we own less than a majority of some of our project investments, we cannot exercise complete control over their operations.	
      We have limited control over the operation of some project investments and joint ventures because our investments are in projects where we beneficially own less than a majority of the ownership interests. We seek to exert a degree of influence with respect to the management and operation of projects in which we own 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, we may not always succeed in such negotiations. We may be dependent on our co-venturers to operate such projects. Our 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 us to receive distributions of funds from projects or to transfer our interest in projects.
 	 	
 	Future acquisition activities may not be successful.	
      We may seek to acquire additional companies or assets in our industry. The acquisition of power generation companies and assets is subject to substantial risks, including the failure to identify material problems during due diligence, the risk of over-paying for assets and the inability to arrange financing for an acquisition as may be required or desired. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, our 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.
 	 	
 	Our operations are subject to hazards customary to the power generation industry. We may not have adequate insurance to cover all of these hazards.	
      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 our 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 our being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property

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damage and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate, but we cannot assure you that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, we cannot assure you that insurance coverage will continue to be available at all or at rates or on terms similar to those presently available to us. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.
 	 	
 	Our business is subject to substantial governmental regulation and may be adversely affected by liability under, or any future inability to comply with, existing or future regulations or requirements.	
      Our business is subject to extensive foreign, federal, state and local laws and regulation. Compliance with the requirements under these various regulatory regimes may cause us to incur significant additional costs and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.
      Public utilities under the Federal Power Act, or FPA, are required to obtain the Federal Energy Regulatory Commission’s, or FERC’s, acceptance of their rate schedules for wholesale sales of electricity. All of NRG’s non-qualifying facility generating companies and power marketing affiliates in the United States make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. FERC has granted each of NRG’s generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant NRG’s generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. In addition, NRG’s market-based sales are subject to certain market behavior rules and, if any of NRG’s generating and power marketing companies were deemed to have violated one of those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG’s generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and would 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.
      We are also affected by changes to market rules, tariffs, changes in market structures, changes in administrative fee allocations and changes in market bidding rules that occur in the existing ISOs and RTOs. The ISOs and RTOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, 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 adversely affect the profitability of our generation facilities that sell energy and capacity into the wholesale power markets. In addition, the regulatory and legislative changes that have recently been enacted at the federal level and in a number of states in an effort to promote competition are novel and untested in many respects. These new approaches to the sale of electric power have very short operating histories, and it is not yet clear how they will operate in times of market stress or pressure, given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price limitations by independent system operators.
      Similarly, the Texas Genco subsidiaries are registered as power generation companies with the Public Utility Commission of Texas, or PUCT. PUCT has jurisdiction with respect to the mitigation of undue market power and has authority to remedy market power abuses in the ERCOT market, both directly and, indirectly, through oversight of ERCOT. PUCT has proposed a significant change in the rules governing the ERCOT market. Specifically the PUCT adopted a rule directing the ERCOT ISO to develop and implement a wholesale market that, among other things, replaces the existing zonal market design with a nodal market design based on locational marginal prices for power. The market redesign project is expected to take effect in 2009. We expect that implementation of any new market design will require modification to our procedures

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and systems. 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.
 	 	
 	Texas Genco’s ownership interest in a nuclear power facility subjects it 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 Texas Genco owns indirectly a 44.0% interest, is subject to regulation by the Nuclear Regulatory Commission, or NRC. Such regulation includes licensing, inspection, enforcement, testing, evaluation and modification of all aspects of nuclear reactor power plant design and operation, environmental and safety performance, technical and financial qualifications, decommissioning funding assurance and transfer and foreign ownership restrictions. Texas Genco’s 44.0% share of the output of STP represents approximately 1,101 MW of generation capacity, which is approximately 10% of the total gross generation capacity owned by Texas Genco.
      There are unique risks to owning and operating a nuclear power facility. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, particularly with respect to spent nuclear fuel, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning a nuclear facility. The NRC could require the shutdown of the plant for safety reasons or refuse to permit restart of the unit after unplanned or planned outages. New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. STP may be obligated to continue storing spent nuclear fuel if the Department of Energy continues to fail to meet its contractual obligations to STP made pursuant to the U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of STP’s spent nuclear fuel. See “Business— Environmental Matters— U.S. Federal Environmental Initiatives— Nuclear Waste.” Costs associated with these risks could be substantial and have a material adverse effect on our 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, Texas Genco may incur additional costs to the extent it is obligated to provide power from more expensive alternative sources— either Texas Genco’s own plants, third party generators or the ERCOT— to cover Texas Genco’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.
      Texas Genco 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 our financial condition, results of operations or cash flows.
 	 	
 	We are subject to environmental laws and regulations that impose extensive and increasingly stringent requirements on our ongoing operations, as well as potentially substantial liabilities arising out of environmental contamination. These environmental requirements and liabilities could adversely impact our results of operations, financial condition and cash flows.	
      Our business is subject to the environmental laws and regulations of foreign, federal, state and local authorities. We must comply with numerous environmental laws and regulations and obtain numerous governmental permits and approvals to operate our plants. If we fail to comply with any environmental requirements that apply to our operations, we could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions seeking to curtail our operations. In addition, when

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new requirements take effect or when existing environmental requirements are revised, reinterpreted or subject to changing enforcement policies, our 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 we expect this trend to continue. In particular, the U.S. Environmental Protection Agency, or USEPA, has recently promulgated regulations requiring additional reductions in nitrogen oxides, or NO x  and sulfur dioxide, or SO 2 , emissions, commencing in 2009 and 2010 respectively, and has also promulgated regulations requiring reductions in mercury emissions from coal-fired electric generating units, commencing in 2010 with more substantial reductions in 2018. These regulatory programs are currently subject to litigation and reconsideration by the USEPA, which could affect the timing of our future capital projects. See “Business— Environmental Matters— U.S. Federal Environmental Initiatives— Air.” Moreover, certain of the states in which we operate have promulgated air pollution control regulations which are more stringent than existing and proposed federal regulations. Ongoing public concerns about emissions of SO 2 , NO x , mercury and carbon dioxide and other greenhouse gases from power plants have resulted in proposed laws and regulations at the federal, state and regional levels that, if they were to take effect substantially as proposed, would likely apply to our operations. For example, we could incur substantial costs pursuant to the proposed multi-state carbon cap-and-trade program known as the Regional Greenhouse Gas Initiative, or RGGI, which would apply to the facilities in our Northeast region. A model rule for implementation of RGGI is expected to be released within the next few months. See “Business— Environmental Matters— Regional U.S. Environmental Regulatory Initiatives.”
      Significant capital expenditures may be required to keep our facilities compliant with environmental laws and regulations, and if it is not economical to make those capital expenditures then we may need to retire or mothball facilities, or restrict or modify our operations to comply with more stringent standards.
      Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. We are generally responsible for all liabilities associated with the environmental condition of our power generation plants, including any soil or groundwater contamination that may be present, regardless of when the liabilities arose and whether the liabilities are known or unknown, or arose from the activities of our predecessors or third parties. We are currently subject to remediation obligations at a number of our facilities. See “Business— Environmental Matters— Domestic Site Remediation Matters.”
 	 	
 	The value of our assets is subject to the nature and extent of decommissioning and remediation obligations applicable to us.	
      Our facilities and related properties may become subject to decommissioning and/or site remediation obligations that may require material unplanned expenditures or otherwise materially affect the value of those assets. The closure or modification of any of our facilities, especially with respect to STP, could lead to substantial liabilities, including related to the cleanup of any contamination that occurred during the facility’s operation. While we believe that we meet, or are performing, all site remediation obligations currently applicable to our assets (including through the provision of various forms of financial assurance at certain facilities at which we are not currently required to perform remediation), more onerous obligations often apply to sites where a plant is to be dismantled, which could negatively affect our ability to economically undertake power redevelopments or alternate uses at existing power plant sites. Further, laws and regulations may change to impose material additional decommissioning and remediation obligations on us in the future, negatively impacting the value of our assets and/or our ability to undertake redevelopment projects.
 	 	
 	Our business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by our unionized employees.	
      As of September 30, 2005, after giving pro forma effect to the Acquisition, approximately 46.8% of the combined company’s employees at its U.S. generation plants would have been covered by collective bargaining agreements, and 774 employees of the combined company’s plants in Texas are covered by a single collective

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bargaining agreement that expires in September 2006. In the event that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or outages. Our 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 our business, financial condition, results of operations and cash flows.
 	 	
 	Changes in technology may impair the value of our 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, microturbines, 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 we have currently forecasted, which could adversely affect our revenue, results of operations or competitive position.
 	 	
 	Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.	
      Our 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 their 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 our financial condition, results of operations and cash flows.
 	 	
 	Our international investments are subject to additional risks that our U.S. investments do not have.	
      We have investments in power projects in Australia, Germany and Brazil. International investments are subject to risks and uncertainties relating to the political, social and economic structures of the countries in which we invest. Risks specifically related to our investments in international projects may include:
 	 	 	
 	•	fluctuations in currency valuation;	
 	 	 	
 	•	currency inconvertibility;	
 	 	 	
 	•	expropriation and confiscatory taxation;	
 	 	 	
 	•	restrictions on the repatriation of capital; and	
 	 	 	
 	•	approval requirements and governmental policies limiting returns to foreign investors.	

 	Texas Genco’s plants are the subject of a number of lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast, and NRG is also subject to asbestos-related claims with respect to certain of its facilities.	
      Many of Texas Genco’s plants have been subject to personal injury claims arising out of alleged exposure to asbestos. Most of the claimants who have brought such claims have been third-party workers who participated in the construction, renovation or repair of various industrial plants, including power plants. While many of the claimants have never worked at or near Texas Genco’s plants, some of the claimants have worked at locations owned by Texas Genco. While Texas Genco has been dismissed from many of these lawsuits without having to make any payment to claimants, Texas Genco has incurred and expects to continue to incur settlement costs associated with these claims. NRG is also subject to claims for asbestos exposure in certain of its facilities, as well as claims for indemnity from previous owners of those facilities. We defend against these claims aggressively, and, thus, we have incurred and expect to continue to incur defense costs as a result of such claims. For further discussion of such claims, see “Business— Legal Proceedings.”

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      If asbestos-related claims against us rise significantly, our liability may be substantial. Moreover, if insurance currently available for contribution to the payment of asbestos liabilities becomes unavailable (through insurer insolvencies, coverage disputes, changes in law or otherwise), asbestos liabilities could impact our results of operations, financial condition and cash flows.
 	 	
 	Our high level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, expose us to the risk of increased interest rates, make it more difficult for us to satisfy our obligations with respect to our indebtedness and limit our ability to react to changes in the economy or our industry.	
      Our substantial debt could have important consequences for you, including:
 	 	 	
 	•	increasing our vulnerability to general economic and industry conditions;	
 	 	 	
 	•	requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our preferred or common stock or to use our cash flow to fund our operations, capital expenditures and future business opportunities;	
 	 	 	
 	•	limiting our ability to enter into long-term power sales or fuel purchases which require credit support;	
 	 	 	
 	•	exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under our senior secured credit facilities, are, and under our new senior secured credit facility will be, at variable rates of interest;	
 	 	 	
 	•	placing us at a competitive disadvantage compared to our competitors that have less debt;	
 	 	 	
 	•	limiting our 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 our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who have less debt.	
      The indenture for the senior notes contains, and our new credit facility will contain, financial and other restrictive covenants that will limit our ability to engage in activities that may be in our long-term best interests. Our 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 our borrowed indebtedness.
      In addition, our 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 us, our partners and the regional wholesale power markets;	
 	 	 	
 	•	our financial performance and the financial performance of our subsidiaries;	
 	 	 	
 	•	our levels 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.	
      We 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 our business and operations.

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Risks Related to the Acquisition
 	 	
 	We may not be able to realize the anticipated benefits from the Acquisition.	
      The success of the Acquisition will depend largely on NRG’s ability to consolidate and effectively integrate Texas Genco’s assets, operations and employees into NRG. The integration will require substantial time and attention from our management. If the integration takes longer or is more complex or expensive than anticipated, or if we cannot operate our combined business as effectively as we anticipate, our operating performance and profitability could be materially adversely affected.
      Texas Genco’s power generation assets operate in the ERCOT market, a market in which NRG does not currently operate. Accordingly, we are dependent upon Texas Genco’s existing managers and employees to manage those assets, and the loss of key Texas Genco managers or employees could adversely affect our business.
      In addition, as a result of the Acquisition, we have assumed all of Texas Genco’s liabilities. After the Acquisition, we may learn additional information about Texas Genco’s business that adversely affects us, such as unknown or contingent liabilities, issues relating to internal controls over financial reporting and issues relating to compliance with applicable laws.
 	 	
 	Because the historical and pro forma financial information incorporated by reference or included elsewhere in this prospectus supplement may not be representative of our results as a combined company or capital structure after the Acquisition, and NRG’s and Texas Genco’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate us, NRG, Texas Genco and your investment decision.	
      NRG’s financial statements prior to December 5, 2003 are not comparable to its financial statements after that date. As a result of NRG’s emergence from bankruptcy, it is operating its business with a new capital structure, and is subject to Fresh Start reporting requirements prescribed by generally accepted accounting principles in the United States. As required by Fresh Start reporting, assets and liabilities as of December 6, 2003 were recorded at fair value, with the enterprise value being determined in connection with the reorganization.
      Texas Genco did not exist prior to July 19, 2004, and Texas Genco and its subsidiaries had no operations and no material activities until December 15, 2004 when Texas Genco acquired its gas and coal-fired assets. Consequently, Texas Genco’s historical financial statements are not comparable to its current financial statements.
      NRG and Texas Genco have been operating as separate companies prior to the Acquisition. We have had no prior history as a combined entity and our operations have not previously been managed on a combined basis. Preparing the pro forma financial information contained in this prospectus supplement involved making several assumptions, such as the makeup of our capital structure after the consummation of the Financing Transactions. These assumptions may prove inaccurate. Therefore, the historical financial statements and pro forma financial statements incorporated by reference or presented in this prospectus supplement may not reflect what our results of operations, financial position and cash flows would have been had we operated on a combined basis and may not be indicative of what our results of operations, financial position and cash flows will be in the future.
      As a result, the historical and pro forma financial information incorporated by reference or included elsewhere in this prospectus supplement is of limited relevance to an investor in this offering. See “Selected Consolidated Financial Information of NRG” and “Selected Consolidated Financial Information of Texas Genco.” See also “—Risks Related to the Offering— If NRG is unable to raise sufficient proceeds through other Financing Transactions described elsewhere in this prospectus supplement, NRG may draw down on a bridge loan facility in order to close the Acquisition which would significantly increase our indebtedness. If NRG elects not to consummate the financing under the bridge loan facility, NRG may seek alternative sources of financing for the Acquisition, the terms of which are unknown to us and could limit our ability to operate our business.”

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Risks Related to the Offering
 	 	
 	There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not consummated, NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.	
      Although NRG expects to close the Acquisition in or about the first week of February 2006, there can be no assurance that the Acquisition will be completed in accordance with the anticipated timing or at all. In order to consummate the Acquisition, NRG and Texas Genco must obtain certain regulatory and other approvals and consents in a timely manner. If these approvals or consents are not received, or they are not received on terms that satisfy the conditions set forth in the Acquisition Agreement, then NRG and/or Texas Genco will not be obligated to complete the Acquisition. Also, NRG and/or Texas Genco may not receive these approvals or consents by the first week of February 2006, the current anticipated timing for closing the Acquisition. The Acquisition Agreement also contains customary and other closing conditions, which may not be satisfied or waived. In addition, under circumstances specified in the Acquisition Agreement, NRG or Texas Genco may terminate the Acquisition Agreement.
      The closing of this offering is not conditioned on the consummation of the Acquisition. Therefore, upon the closing of this offering, you will become a holder of NRG’s common stock irrespective of whether the Acquisition is consummated or delayed. If the Acquisition is not completed, NRG’s common stock that you have purchased in this offering, will not reflect any interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay. If this offering is consummated and the Acquisition does not occur, your expected earnings per share of our common stock will be significantly reduced. Also, the price of NRG’s common stock may decline to the extent that the current market price of NRG’s common stock reflects a market assumption that the Acquisition will be consummated and that NRG will realize certain anticipated benefits of the Acquisition. See also below “—The price of our common stock may fluctuate significantly, which may make it difficult for you to resell the common stock when you want or at prices you find attractive.” In addition, NRG’s business may be harmed to the extent that customers, suppliers and others believe that NRG cannot effectively compete in the marketplace without Texas Genco, or otherwise remain uncertain about NRG. NRG will be required to pay significant costs incurred in connection with the Acquisition, including legal, accounting, financial advisory and other costs, whether or not the Acquisition is completed. The occurrence of any of these events individually or in combination could have a material adverse effect on NRG’s business, financial condition and results of operations.
 	 	
 	The price of our common stock may fluctuate significantly, which may make it difficult for you to resell the common stock when you want or at prices you find attractive.	
      The price of our common stock on the New York Stock Exchange constantly changes. We expect that the market price of our common stock will continue to fluctuate. Holders of our common stock will be subject to the risk of volatility and depressed prices.
      Our common stock price can fluctuate as a result of a variety of factors, many of which are beyond our control. These factors include:
 	 	 	
 	•	our ability to consummate the Acquisition in accordance with the anticipated timing or at all;	
 	 	 	
 	•	new laws or regulations or new interpretations of existing laws or regulations applicable to our business;	
 	 	 	
 	•	changes in accounting standards, policies, guidance, interpretations or principles;	
 	 	 	
 	•	our inability to raise additional capital;	
 	 	 	
 	•	sales of common stock by us or members of our management team;	
 	 	 	
 	•	quarterly variations in our operating results;	
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 	•	operating results that vary from the expectations of management, securities analysts and investors;	
 	 	 	
 	•	changes in expectations as to our future financial performance, including financial estimates by securities analysts and investors;	
 	 	 	
 	•	developments generally affecting our industry;	
 	 	 	
 	•	announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;	
 	 	 	
 	•	announcements by third parties of significant claims or proceedings against us;	
 	 	 	
 	•	changes in our dividend policy;	
 	 	 	
 	•	future sales of our equity or equity-linked securities; and	
 	 	 	
 	•	general domestic and international economic conditions.	
      In addition, the stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the market price of our common stock.
 	 	
 	Our ability to pay dividends may be limited.	
      The terms of our existing senior secured credit facility and the indenture for the Second Priority Notes restrict, and we expect the terms of our new senior credit facility and the indenture governing the New Senior Notes to restrict, our ability to pay dividends to the holders of our common stock. In addition, under the terms of our outstanding preferred stock, including the mandatory convertible preferred stock offered as part of the Financing Transactions, we are restricted from paying any cash dividend on our common stock if we are not current in our dividend payments with respect to such preferred stock. If we issue Cumulative Redeemable Preferred Stock to the Sellers pursuant to the Acquisition Agreement, we will be prohibited from paying dividends on our common stock so long as any shares of Cumulative Redeemable Preferred Stock are outstanding. In the future, we may agree to further restrictions on our ability to pay dividends. In addition, to maintain our credit ratings, we may be limited in our ability to pay dividends so that we can maintain an appropriate level of debt. Our future dividend policy depends on earnings, financial condition, liquidity, capital requirements and other factors. There is no guarantee that we will pay dividends on shares of our common stock.
 	 	
 	If NRG is unable to raise sufficient proceeds through other Financing Transactions described elsewhere in this prospectus supplement, NRG may draw down on a bridge loan facility in order to close the Acquisition which would significantly increase our indebtedness. If NRG elects not to consummate the financing under the bridge loan facility, NRG may seek alternative sources of financing for the Acquisition, the terms of which are unknown to us and could limit our ability to operate our business.	
      The offering of the common stock forms part of a larger financing plan for the Acquisition described elsewhere in this prospectus supplement. See “The Acquisition— The Financing Transactions.” Concurrently with this offering, NRG intends to conduct offerings of its mandatory convertible preferred stock and New Senior Notes. In addition, NRG intends to enter into a new senior secured credit facility at or prior to the Acquisition that will replace its existing senior secured credit facility. NRG intends to use initial borrowings under its new senior secured credit facility, together with the net proceeds from this offering and the offerings of mandatory convertible preferred stock and New Senior Notes, to finance the Acquisition and to repay certain of its and Texas Genco’s outstanding indebtedness. See “Use of Proceeds.” NRG’s obligations under the Acquisition Agreement are not conditioned upon the consummation of any or all of the Financing Transactions. NRG has entered into the commitment letter with the bridge lenders pursuant to which the bridge lenders have committed to fund NRG’s new senior secured credit facility and to provide, subject to certain conditions, the additional financing required for the Acquisition through a $5.1 billion bridge loan facility in the event that sufficient proceeds are not raised from this offering, the mandatory convertible

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preferred stock offering and/or the New Senior Notes offering. See “Description of Certain Indebtedness— Bridge Loan Facility.”
      In the event that NRG is unable to raise sufficient proceeds through the consummation of the New Senior Notes offering and/or the mandatory convertible preferred stock offering, NRG may draw down on the bridge loan facility, in whole or in part, in order to finance the Acquisition. No assurances can be given that the terms of the bridge loan facility on the draw down date would not vary from the existing terms of such facility on the date of this prospectus supplement. See “Description of Certain Indebtedness— Bridge Loan Facility.” In the event of such draw down, we would be significantly more highly leveraged, which means we will have a larger amount of indebtedness in relation to our equity (deficit). Our interest expense would significantly increase and require us to dedicate a substantial portion of our cash flow from operations to payments in respect of our outstanding indebtedness, thereby reducing the availability of our cash flow to fund working capital, including collateral postings, capital expenditures and other general corporate expenditures. Our substantial indebtedness could adversely affect our financial condition.
      In the event that NRG does not consummate the mandatory convertible stock offering and the New Senior Notes offering as currently contemplated and elects not to consummate the financing under the bridge loan facility, it could seek alternative sources of financing for the Acquisition, which may include, among other alternatives, the issuance in part of senior secured debt securities or borrowing in part on a senior secured basis. This could further exacerbate the risks associated with our substantial leverage. There can be no assurance as to the terms on which NRG would issue these senior secured debt securities or borrow funds. We are unable to predict the interest rate payable on any such debt or give any assurance that the terms would not restrict our financial flexibility or limit our ability to operate our business.
 	 	
 	Our corporate documents and Delaware law contain provisions that could discourage, delay or prevent a change in control of our company even if some stockholders might consider such a development favorable, which may adversely affect the price of our common stock.	
      Provisions in our amended and restated certificate of incorporation and amended and restated by-laws may discourage, delay or prevent a merger or acquisition involving us that our stockholders may consider favorable. For example, our amended and restated certificate of incorporation authorizes our board of directors to issue shares of preferred stock to which special rights are attached, including voting and dividend rights. With these rights, preferred stockholders could make it more difficult for a third party to acquire us. In addition, our amended and restated certificate of incorporation provides for a staggered board of directors, whereby directors serve for three-year terms, with approximately one third of the directors coming up for reelection each year. Having a staggered board of directors would make it more difficult for a third party to obtain control of our board of directors through a proxy contest, which may be a necessary step in an acquisition of us that is not favored by our board of directors.
      We are also subject to the anti-takeover provisions of Section 203 of the Delaware General Corporation Law. Under these provisions, if anyone becomes an “interested stockholder,” we may not enter into a “business combination” with that person for three years without special approval, which could discourage a third party from making a takeover offer and could delay or prevent a change of control. For purposes of Section 203, “interested stockholder” means, generally, someone owning 15% or more of our outstanding voting stock or an affiliate of ours that owned 15% or more of our outstanding voting stock during the past three years, subject to certain exceptions as described in Section 203.
      Under our existing senior secured credit facility and the new senior secured credit facility which we expect will be in effect after closing the Acquisition, a change of control is an event of default. Upon the occurrence of a change in control, the holders of the New Senior Notes will have the right, subject to certain conditions, to require us to repurchase their notes at a price equal to 101% of their principal amount plus accrued and unpaid interest and liquidated damages, if any, to the date of repurchase.

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 	Shares eligible for future issuance or sale may cause our common stock price to decline, which may negatively impact your investment.	
      Issuances or sales of substantial numbers of additional shares of our common stock, including in connection with future acquisitions, if any, or the perception that such issuances or sales could occur, may cause prevailing market prices for shares of our common stock to decline and may adversely affect our ability to raise additional capital in the financial markets at a time and price favorable to us. As of the date of this prospectus supplement, our amended and restated certificate of incorporation provides that we have authority to issue up to 500,000,000 shares of our common stock. As of January 3, 2006, 100,048,676 shares of our common stock were issued, 80,701,888 shares of our common stock were outstanding and 19,346,788 shares of our common stock were issued and held in treasury. Also as of such date, there were 4,000,000 shares of our common stock reserved for issuance under stock incentive plans or pursuant to individual option grants or stock awards. After giving effect to the Financing Transactions, we will have 101,556,945 million shares of common stock outstanding (104,685,204 million shares of common stock outstanding if the underwriters in this offering exercise their over-allotment option in full).
      In connection with the Acquisition, we are issuing to the Sellers shares of our common stock valued at approximately 1.6 billion on a pro forma basis. The shares of common stock issued to the Sellers are subject to a 180 day lock-up period following the closing date of the Acquisition. If the restrictions under the lock-up agreements are waived or terminated, or upon expiration of the lock-up period, such shares held by the Sellers will be available for sale into the market at that time, subject only to applicable securities laws, rules and regulations. These sales or a perception that these sales may occur could reduce the market price for our common stock.
      Concurrently with this offering, we are offering to sell to the public 2,000,000 shares of our mandatory convertible preferred stock (or 2,300,000 shares if the underwriters exercise their over-allotment option to purchase additional shares in full) and an additional 8,271,200 to 10,256,400 shares of common stock will be issuable upon conversion of the mandatory convertible preferred stock (or an additional 1,240,680 to 1,538,460 shares of common stock if the underwriters exercise their over-allotment option in full). We will reserve for issuance the maximum number of shares of our common stock issuable upon conversion of the mandatory convertible preferred stock. See “Description of Capital Stock— Mandatory Convertible Preferred Stock.”

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THE ACQUISITION
The Acquisition
 	 	
 	Overview	
      On September 30, 2005, NRG entered into the Acquisition Agreement with Texas Genco and the Sellers. Pursuant to the Acquisition Agreement, NRG agreed to purchase all of the outstanding equity interests in Texas Genco for a total pro forma purchase price of approximately $6.121 billion that includes the assumption of approximately $2.7 billion of indebtedness. The purchase price is subject to adjustment, and includes an equity component valued at up to $2.0 billion based on a price per share of $45.37 of NRG’s common stock issued to the Sellers, and an average price per share of $40.73 for the Other Consideration to the Sellers. As a result of the Acquisition, Texas Genco will become a wholly-owned subsidiary of NRG.
      The closing of this offering is not conditioned on the consummation of the Acquisition. While we expect that the Acquisition will be consummated in or about the first week of February 2006, no assurance can be given that the Acquisition will be completed in accordance with the anticipated timing or at all. See “Risk Factors— Risks Related to the Offering— There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not consummated, NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.”
 	 	
 	Certain Terms and Conditions of the Acquisition Agreement	
      Of the approximately $6.121 billion payable to the Sellers upon consummation of the Acquisition, NRG will pay $4.399 billion in cash, subject to adjustment, and issue a minimum of 35,406,320 shares of NRG’s common stock. The remaining consideration is to be comprised of an additional 9,038,125 shares of common stock, or at NRG’s election, the equivalent in the form of common stock, additional cash or shares of a new series of NRG’s Cumulative Redeemable Preferred Stock, or any combination of the foregoing. If issued, the aggregate liquidation preference of the Cumulative Preferred Stock will be determined by reference to the average price of NRG’s common stock over a 20 trading day period prior to the closing of the Acquisition, which on a pro forma basis is $40.73. NRG has elected to pay this amount in cash. The purchase price payable by NRG is subject to adjustment based on the level of Texas Genco’s working capital, the amount of Texas Genco’s indebtedness and the amount of Texas Genco’s cash and cash equivalents on hand, all as of the closing date.
      The Acquisition Agreement contains customary terms and conditions, including representations and warranties of NRG, Texas Genco and the Sellers and covenants of NRG and Texas Genco with respect to the conduct of their businesses prior to the closing of the Acquisition. Pending closing of the Acquisition, Texas Genco and NRG are obligated to conduct their businesses in the ordinary course of business, to preserve their business, assets, properties and relationships, and to refrain from certain activities without prior written consent of the other party, such consent not to be unreasonably withheld or delayed.
      The obligations of NRG, on the one hand, and Texas Genco and the Sellers, on the other, to consummate the Acquisition are subject to the satisfaction or waiver of various conditions, including: the other party or parties having performed their agreements, covenants and obligations required by the Acquisition Agreement in all material respects and having delivered certain certificates and other documents, the representations and warranties of the other party or parties being true and correct on the date of the Acquisition Agreement and the closing date (except for inaccuracies that would not, individually or in the aggregate, have a Material Adverse Effect (as defined in the Acquisition Agreement)), no Law or Order (each as defined in the Acquisition Agreement) being in effect on the closing date that would prohibit the consummation of the acquisition or related transactions, no Material Adverse Effect on the other party having occurred since June 30, 2005, the parties having received all consents and approvals of, and made all filings with various governmental authorities necessary to consummate the acquisition and related transactions, including with respect to the NRC and FERC, and any applicable terminations or expirations of waiting periods having

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occurred, including with respect to the Hart Scott Rodino Antitrust Improvements Act, or the HSRA. On November 10, 2005, NRG was notified by the Federal Trade Commission’s Premerger Notification Office that early termination of the applicable waiting period under the HSRA was granted with respect to the Acquisition. On December 27, 2005, FERC granted approval for the Acquisition. On January 13, 2006, NRG and Texas Genco received approval from the Nuclear Regulatory Commission to transfer indirect ownership of the 44 percent interest in the South Texas Project Electric Generation Station. The Acquisition Agreement does not contain any financing condition.
      The Acquisition Agreement may be terminated upon the occurrence of certain events, including at any time before closing by mutual written agreement of NRG and the Seller Representatives (as defined in the Acquisition Agreement). NRG or the Seller Representatives may terminate the Acquisition Agreement if the Acquisition has not been consummated within nine months of the date of the Acquisition Agreement (subject to certain provisions for extension), upon an uncured material breach by the other party or parties of any of the covenants, agreements or representations or warranties in the Acquisition Agreement if such breach would cause a failure of any of the conditions to the obligations of NRG or the Sellers, as the case may be, to consummate the Acquisition, upon an Order by a Governmental Authority (each as defined in the Acquisition Agreement) preventing the consummation of the Acquisition or the related transactions or the failure by a Governmental Authority to issue certain required approvals for the Acquisition or related transactions, which failure becomes final and non-appealable, or if the other party has incurred a Material Adverse Effect (as defined in the Acquisition Agreement) on the other party.
The Financing Transactions
      The offering of common stock forms part of a larger financing plan for the Acquisition described elsewhere in this prospectus supplement. Concurrently with this offering, NRG intends to offer, by means of separate prospectus supplements (i) $500 million of its mandatory convertible preferred stock and (ii) $3.6 billion of New Senior Notes. See “Description of Capital Stock— Mandatory Convertible Preferred Stock” and “Description of Certain Indebtedness—New Senior Notes.” This offering, the mandatory convertible preferred stock offering and the New Senior Notes offering are expected to be consummated at or prior to the completion of the Acquisition. The closing of this offering will not necessarily be contemporaneous with the closing of the New Senior Notes offering and/or the closing of the mandatory convertible preferred stock offering. The net proceeds of the offering of the New Senior Notes (after payment of underwriting discounts and commissions) will be placed into an escrow account held by the escrow agent until the consummation of the Acquisition.
      In addition, NRG intends to enter into a new senior secured credit facility at or prior to the closing of the Acquisition that will replace its existing senior secured credit facility. See “Description of Certain Indebtedness— New Senior Secured Credit Facility.” Concurrently with this offering, NRG is conducting a cash tender offer and consent solicitation with respect to (i) all of its outstanding Second Priority Notes, and (ii) all of Texas Genco’s outstanding Unsecured Senior Notes. The completion of the Acquisition is not conditioned on the completion of the tender offer or receipt of the consents for either the Second Priority Notes or Texas Genco’s Unsecured Senior Notes. The completion of the tender offer for the Second Priority Notes and Texas Genco’s Unsecured Senior Notes is conditioned on the completion of the Acquisition. However, NRG can waive this condition in the case of the tender offer and consent solicitation for the Second Priority Notes. See “Summary— Recent Developments— Tender Offers and Consent Solicitations.”
      NRG intends to use initial borrowings under its new senior secured credit facility, together with the net proceeds from this offering, the offerings of mandatory convertible preferred stock and New Senior Notes and cash on hand (i) to finance the Acquisition, (ii) to repurchase NRG’s outstanding Second Priority Notes, (iii) to repurchase Texas Genco’s outstanding Unsecured Senior Notes, (iv) to repay amounts outstanding under NRG’s existing senior secured credit facility and Texas Genco’s existing senior secured credit facility, (v) for ongoing credit needs of the combined company, including replacement of existing letters of credit and (vi) to pay related premiums, fees and expenses. In the event that NRG does not consummate the Acquisition, NRG intends to use the net proceeds from this offering for general corporate purposes. See “Use of Proceeds.”

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      The closing of this offering is not contingent on the closing of the mandatory convertible preferred stock offering, the closing of the New Senior Notes offering, the effectiveness of the new senior secured credit facility, the completion of the tender offers and receipt of the consents in connection with the outstanding tender offers for NRG’s and Texas Genco’s notes or the consummation of the Acquisition. See “Risk Factors— Risks Related to the Offering— There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not consummated, NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.” NRG’s obligations under the Acquisition Agreement are not conditioned upon the consummation of any or all of the Financing Transactions.
      NRG has entered into the commitment letter with the bridge lenders pursuant to which the bridge lenders have committed to fund NRG’s new senior secured credit facility and to provide, subject to certain conditions, the additional financing required for the Acquisition through a $5.1 billion bridge loan facility in the event that sufficient funds are not raised from this offering, the mandatory convertible preferred stock and/or the New Senior Notes offering. See “Description of Certain Indebtedness— Bridge Loan Facility.” In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the mandatory convertible preferred stock offering and/or the New Senior Notes offering, NRG may draw down on the bridge loan facility, in whole or in part, in order to finance the Acquisition. In the event that NRG does not consummate the mandatory convertible preferred stock offering and the New Senior Notes offering as currently contemplated and elects not to consummate the financing under the bridge loan facility, it could seek alternative sources of financing for the Acquisition, which may include, among other alternatives, the issuance in part of senior secured debt securities or borrowing in part on a senior secured basis.

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USE OF PROCEEDS
      We estimate that the net proceeds of this offering, after giving effect to underwriting discounts, commissions and estimated expenses payable by us, will be approximately $985.1 million. We intend to use the net proceeds from the common stock offering and the offerings of mandatory convertible preferred stock and New Senior Notes, together with initial borrowings under our new senior secured credit facility and cash on hand, (i) to finance the Acquisition, (ii) to repurchase NRG’s outstanding Second Priority Notes, (iii) to repurchase Texas Genco’s outstanding Unsecured Senior Notes, (iv) to repay amounts outstanding under NRG’s existing senior secured credit facility and Texas Genco’s existing senior secured credit facility, (v) for ongoing credit needs of the combined company, including replacement of existing letters of credit and (vi) to pay related premiums, fees and expenses. In the event that NRG does not consummate the Acquisition, NRG intends to use net proceeds from this offering for general corporate purposes. The closing of this offering is not conditioned on the consummation of the Acquisition.
      NRG has agreed to acquire Texas Genco for a total pro forma purchase price of approximately $6.121 billion, including an equity component valued at approximately $2.0 billion. In addition, NRG will assume approximately $2.7 billion of Texas Genco’s debt. Before giving effect to the Acquisition and Financing Transactions, as of September 30, 2005, NRG had (i) $1.08 billion of Second Priority Notes outstanding, which provide for cash interest at 8.0% per annum payable semi-annually and (ii) $876.6 million of outstanding indebtedness under its amended and restated credit facility, which consisted of (a) $446.6 million in term loans outstanding, which term loans provide for interest at a rate of LIBOR (4.02% at September 30, 2005) plus 187.5 basis points payable quarterly and mature on December 24, 2011, (b) $80.0 million in principal amount outstanding under the revolving credit facility, which provides for interest at a rate of LIBOR (3.83% at September 30, 2005) plus 2.5% and matures on December 24, 2007 and (c) $350.0 million outstanding under the funded letter of credit facility, which provide for a participation fee of 1.875%, a deposit fee of 0.10%, and an issuance fee of 0.25% and matures on December 24, 2011. In addition, before giving effect to the Acquisition and Financing Transactions, as of September 30, 2005 (i) Texas Genco had $1.125 billion of Unsecured Senior Notes outstanding, which provide for cash interest at 6.875% per annum payable semiannually and (ii) Texas Genco had $1,614 million in term loans outstanding under its existing senior secured credit facility, which term loans provide for interest at a rate of 5.94% (as of September 30, 2005) payable at least quarterly and mature in December 2011. See “The Acquisition” and “Description of Certain Indebtedness.”
Sources and Uses of Funds
      The following table sets forth the expected sources and uses of funds in connection with the Acquisition on a pro forma basis giving effect to the Transactions as if they had occurred on September 30, 2005. No assurances can be given that the information in the following table will not change depending on the nature of our financings and/or whether the Acquisition will be consummated in accordance with the anticipated timing or at all. See “Risk Factors—Risks Related to the Acquisition—Because the historical and pro forma financial information incorporated by reference or included elsewhere in this prospectus supplement may not be representative of our results as a combined company or capital structure after the Acquisition, and NRG’s and Texas Genco’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate us, NRG, Texas Genco and your investment decision” and “Risk Factors—Risks Related to the Offering—If NRG is unable to raise sufficient proceeds through other Financing Transactions described elsewhere in this prospectus supplement, NRG may draw down on a bridge loan facility in order to close the Acquisition which would significantly increase our indebtedness. If NRG elects not to consummate the financing under the bridge loan facility, NRG may seek alternative sources of financing for the Acquisition, the terms of which are unknown to us and could limit our ability to operate our business” and “Risk Factors—Risks Related to the Offering—There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not consummated,

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NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.”
 	 	 	 	 	 	 	 	
 	 	Amount	 	
Sources(1)	 	(in millions)	 	
 	 	 	 	
Gross proceeds of common stock offering	 	 	 	$	1,016	 	
 	
New senior secured term loan facility	 	 	 	 	3,575	 	
 	
Cash released from canceling existing funded letter of credit facility	 	 	 	 	350	 	
 	
Gross proceeds of mandatory convertible preferred stock offering	 	 	 	 	500	 	
 	
Common stock consideration to be issued to Sellers	 	 	 	 	1,606 (2	)	
 	
Gross proceeds of 2014 fixed rate notes offering	 	 	 	 	1,200	 	
 	
Gross proceeds of 2016 fixed rate notes offering	 	 	 	 	2,400	 	
 	
NRG’s cash on hand	 	 	 	 	373	 	

 	Total	 	 	 	$	11,020	 	

 	 	Amount	 	
Uses	 	(in millions)	 	
 	 	 	 	
Purchase price less acquisition costs(2)	 	 	 	$	6,005	 	
Texas Genco’s cash on hand to reduce consideration	 	 	 	 	(222	)	
Refinancing:	 	 	 	 	 	 	
 	Repayment of NRG’s existing credit facilities	 	877	 	 	 	 	
 	Repayment of Texas Genco’s existing credit facilities	 	1,614	 	 	 	 	
 	 	 	 	 	 	
 	 	Total repayment of existing credit facilities	 	 	 	 	2,491	 	
Repurchase of NRG’s Second Priority Notes	 	 	 	 	1,080	 	
Repurchase of Texas Genco’s Unsecured Senior Notes	 	 	 	 	1,125	 	
Accrued interest for NRG and Texas Genco outstanding debt	 	 	 	 	52	 	
Estimated underwriting commissions, tender offer premiums, fees and expenses	 	 	 	 	489	 	

 	 	Total	 	 	 	$	11,020	 	

 	 	
(1) 	NRG has entered into the commitment letter with the bridge lenders pursuant to which the bridge lenders have committed to fund NRG’s new senior secured credit facility and to provide, subject to certain conditions, the additional financing required for the Acquisition through a $5.1 billion bridge loan facility in the event that this offering, the mandatory convertible preferred stock offering and/or the New Senior Notes offering are not consummated. In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the mandatory convertible preferred stock offering and/or the New Senior Notes offering, NRG may draw down on the bridge loan facility, in whole or in part, in order to finance the Acquisition. In the event that NRG does not consummate the mandatory convertible preferred stock offering and the New Senior Notes offering as currently contemplated and elects not to consummate the financing under the bridge loan facility, it could seek alternative sources of financing for the Acquisition, which may include, among other alternatives, the issuance in part of senior secured debt securities or borrowing in part on a senior secured basis.	
 	 	
(2) 	The common stock component of the consideration for the Acquisition is based on a fair value of $45.37 per share of NRG’s common stock and the Other Consideration is valued based on an average common stock price of $40.73, as prescribed in the Acquisition Agreement. This is because the foregoing table is based on a pro forma closing date of Acquisition of September 30, 2005. To the extent NRG’s common stock price for purposes of the equity component, and Texas Genco’s cash on hand, is different at closing of the Acquisition, this amount and the purchase price for the Acquisition will be adjusted accordingly.	
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CAPITALIZATION
      The following table sets forth NRG’s consolidated capitalization as of September 30, 2005 on an actual historical basis and on a combined pro forma cumulative as adjusted basis to reflect the (i) sale of Audrain; (ii) the refinancing of NRG’s debt structure; (iii) the remaining Financing Transactions and subsequent Acquisition; and (iv) the acquisition of the remaining 50% ownership interest in WCP Holdings and sale of our 50% ownership interest in Rocky Road, as if these transactions were consummated on September 30, 2005. The table below should be read in conjunction with “The Acquisition,” “Use of Proceeds” and the consolidated financial statements and the related notes thereto included in or incorporated by reference into this prospectus supplement and the accompanying prospectus. No assurances can be given that the information in the following table will not change depending on the nature of our financings. See “Risk Factors— Risks Related to the Acquisition— Because the historical and pro forma financial information incorporated by reference or included elsewhere in this prospectus supplement may not be representative of our results as a combined company or capital structure after the Acquisition, and NRG’s and Texas Genco’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate us, NRG, Texas Genco and your investment decision” and “Risk Factors— Risks Related to the Offering— If NRG is unable to raise sufficient proceeds through other Financing Transactions described elsewhere in this prospectus supplement, NRG may draw down on a bridge loan facility in order to close the Acquisition which would significantly increase our indebtedness. If NRG elects not to consummate the financing under the bridge loan facility, NRG may seek alternative sources of financing for the Acquisition, the terms of which are unknown to us and could limit our ability to operate our business” elsewhere in this prospectus supplement. In addition, no assurance can be given that the Acquisition will be consummated in accordance with the anticipated or timing or at all. See “Risk Factors— Risks Related to the Offering— There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not consummated, NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.”
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	As of September 30, 2005	 	
 	 	 	 	
 	 	 	 	Cumulative	 	 	 	
 	 	 	 	As Adjusted	 	 	 	
 	 	 	 	Cumulative	 	 	for Audrain,	 	 	Cumulative	 	
 	 	 	 	As Adjusted	 	 	Refinancing and	 	 	As Adjusted	 	
 	 	 	 	As Adjusted	 	 	for Audrain	 	 	Texas Genco	 	 	for the	 	
 	 	Historical	 	 	for Audrain	 	 	and Refinancing(8)	 	 	Acquisition	 	 	Transactions(1)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	504.3	 	 	$	519.3	 	 	$	249.2	 	 	$	146.4	 	 	$	163.0	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Restricted cash	 	 	91.5	 	 	 	91.5	 	 	 	91.5	 	 	 	91.5	 	 	 	91.5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt (including revolving line of credit):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Old Senior Secured Credit Facility:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Old Term Loan Facility	 	 	796.6	 	 	 	796.6	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Old Revolving Credit Facility (2)	 	 	80.0	 	 	 	80.0	 	 	 	—	 	 	 	—	 	 	 	—	 	
Outstanding Second Priority Notes (3)	 	 	1,080.4	 	 	 	1,080.4	 	 	 	—	 	 	 	—	 	 	 	—	 	
Xcel Energy Note(4)	 	 	9.6	 	 	 	9.6	 	 	 	9.6	 	 	 	9.6	 	 	 	9.6	 	
New Senior Secured Credit Facility	 	 	—	 	 	 	—	 	 	 	446.6	 	 	 	3,575.0	 	 	 	3,575.0	 	
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 	 	As of September 30, 2005	 	
 	 	 	 	
 	 	 	 	Cumulative	 	 	 	
 	 	 	 	As Adjusted	 	 	 	
 	 	 	 	Cumulative	 	 	for Audrain,	 	 	Cumulative	 	
 	 	 	 	As Adjusted	 	 	Refinancing and	 	 	As Adjusted	 	
 	 	 	 	As Adjusted	 	 	for Audrain	 	 	Texas Genco	 	 	for the	 	
 	 	Historical	 	 	for Audrain	 	 	and Refinancing(8)	 	 	Acquisition	 	 	Transactions(1)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2016 Fixed Rate Notes	 	 	—	 	 	 	—	 	 	 	1,080.4	 	 	 	2,400	 	 	 	2,400	 	
2014 Fixed Rate Notes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,200	 	 	 	1,200	 	
Existing non-guarantor debt(5)	 	 	607.2	 	 	 	607.2	 	 	 	607.2	 	 	 	607.2	 	 	 	607.2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total debt, before capital leases	 	 	2,573.8	 	 	 	2,573.8	 	 	 	2,143.8	 	 	 	7,791.8	 	 	 	7,791.8	 	
Capital leases	 	 	470.4	 	 	 	230.5	 	 	 	230.5	 	 	 	234.4	 	 	 	234.4	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total debt and capital leases	 	$	3,044.2	 	 	$	2,804.3	 	 	$	2,374.3	 	 	$	8,026.2	 	 	$	8,026.2	 	
3.625% Convertible Preferred Stock	 	 	246.2	 	 	 	246.2	 	 	 	246.2	 	 	 	246.2	 	 	 	246.2	 	
Mandatory Convertible Preferred Stock (6)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	484.6	 	 	 	484.6	 	
Convertible Perpetual Preferred Stock	 	 	406.2	 	 	 	406.2	 	 	 	406.2	 	 	 	406.2	 	 	 	406.2	 	
 	Other stockholders’ equity (7)	 	 	1,613.0	 	 	 	1,628.2	 	 	 	1,538.6	 	 	 	4,100.8	 	 	 	4,075.6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total capitalization	 	$	5,309.6	 	 	$	5,084.9	 	 	$	4,565.3	 	 	$	13,264.0	 	 	$	13,238.8	 	

 	 	
(1) 	NRG has entered into the commitment letter with the bridge lenders pursuant to which the bridge lenders have committed to fund NRG’s new senior secured credit facility and to provide, subject to certain conditions, the additional financing required for the Acquisition through a $5.1 billion bridge loan facility in the event that this offering, the mandatory convertible preferred stock offering and/or the New Senior Notes offering are not consummated. In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the mandatory convertible preferred stock offering and/or the New Senior Notes offering, NRG may draw down on the bridge loan facility, in whole or in part, in order to finance the Acquisition. See “Description of Certain Indebtedness — Bridge Loan Facility.” In the event that NRG does not consummate the mandatory convertible preferred stock offering and the New Senior Notes offering as currently contemplated and elects not to consummate the financing under the bridge loan facility, it could seek alternative sources of financing for the Acquisition, which may include, among other alternatives, the issuance in part of senior secured debt securities or borrowing in part on a senior secured basis.	
 	 	
(2) 	Total borrowing availability under the revolving credit facility portion of NRG’s old senior secured credit facility is $150.0 million, of which $80.0 million was drawn at September 30, 2005.	
 	 	
(3) 	The outstanding balance for the Second Priority Notes has been increased by $14.8 million because the tack-on offering was sold at a premium. The outstanding note balance excludes a decrease of $16.7 million as a result of an unfavorable fair value hedge on an interest rate swap entered into in March 2004. This interest rate swap will remain after the Acquisition and Financing Transactions.	
 	 	
(4) 	Xcel Energy Note has been reduced by $0.4 million as a result of marking the debt to a market rate of 9% in connection with NRG’s Fresh Start reporting on December 5, 2003. The stated interest rate of the note is 3%.	
 	 	
(5) 	As of September 30, 2005, existing non-guarantor debt has been reduced by $59.0 million as a result of marking the debt to a market rate in connection with NRG’s Fresh Start reporting on December 5, 2003. For more information on the various components of NRG’s debt, refer to Note 18 to NRG’s audited consolidated financial statements as of and for the year ended December 31, 2004 as amended on our Current Report on Form 8-K filed on December 20, 2005, incorporated herein by reference.	
 	 	
(6) 	The Mandatory Convertible Preferred Stock will be converted on March 16, 2009, and is subject to a 5.75% cumulative annual dividend. The Mandatory Convertible Preferred Stock has a total liquidation preference of $500 million and a conversion rate ranging from 4.14 to 5.13 shares of common stock per share of Mandatory Convertible Preferred Stock, depending on the price of NRG’s common stock at the time of conversion, and is convertible at the option of the holder at any time.	
 	 	
(7) 	Pro forma adjustments to Stockholders’ Equity include the issuance of $1.0 billion of common stock in this offering, and the issuance of common stock and reissuance of treasury stock to the Sellers valued at $1,606.4 million. These amounts are impacted by a $15.3 million gain on the sale of Audrain, a $25.2 million loss from the sale of Rocky Road and closing costs net of tax of $118.9 million.	
 	 	
(8) 	Refinancing reflects the changes due to the refinancing of NRG’s old debt structure.	
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PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
      Pursuant to the consummation of the NRG plan of reorganization, on December 5, 2003, all shares of our old common stock were canceled and shares of NRG’s new common stock were distributed to the holders of certain classes of claims. From December 5, 2003 to March 24, 2004, NRG’s common stock was listed on the OTC Bulletin Board under the symbol “NRGE.OB.” Since March 25, 2004, NRG’s common stock has been listed for trading on the New York Stock Exchange under the symbol “NRG.” The following table sets forth the quarterly high and low share price information for the periods indicated.
 	 	 	 	 	 	 	 	 	
 	 	High	 	 	Low	 	
 	 	 	 	 	 	 	
Year Ended December 31, 2004	 	 	 	 	 	 	 	 	
1st Quarter	 	$	22.50	 	 	$	18.10	 	
2nd Quarter	 	$	24.80	 	 	$	19.17	 	
3rd Quarter	 	$	28.43	 	 	$	24.10	 	
4th Quarter	 	$	36.18	 	 	$	26.00	 	
Year Ended December 31, 2005	 	 	 	 	 	 	 	 	
1st Quarter	 	$	39.10	 	 	$	32.79	 	
2nd Quarter	 	$	37.61	 	 	$	30.30	 	
3rd Quarter	 	$	44.45	 	 	$	36.40	 	
4th Quarter	 	$	49.44	 	 	$	37.60	 	
Year Ended December 31, 2006	 	 	 	 	 	 	 	 	
1st Quarter (through January 25, 2006)	 	$	49.46	 	 	$	45.50	 	
      On January 25, 2006, the closing sale price of NRG’s common stock was $49.25. NRG has not declared or paid dividends on its new common stock, although we may do so in the future. The terms of our existing senior secured credit facility and the indenture for the Second Priority Notes restrict, and we expect the terms of our new senior credit facility and the indenture governing the New Senior Notes to restrict, our ability to pay dividends to the holders of our common stock. See “Description of Certain Indebtedness— New Senior Secured Credit Facility” and “Description of Certain Indebtedness— New Senior Notes.” In addition, under the terms of our outstanding preferred stock, including the mandatory convertible preferred stock offered as part of the Financing Transactions, we are restricted from paying any cash dividend on our common stock if we are not current in our dividend payments with respect to such preferred stock. If we issue Cumulative Redeemable Preferred Stock to the Sellers pursuant to the Acquisition Agreement, we will be prohibited from paying dividends on our common stock so long as any shares of Cumulative Redeemable Preferred Stock are outstanding. See “Description of Capital Stock— Preferred Stock.”

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SELECTED CONSOLIDATED FINANCIAL INFORMATION OF NRG
      The following table presents selected historical consolidated financial information of (i) Predecessor Company as of and for the years ended December 31, 2000, 2001 and 2002 and for the period from January 1, 2003 to December 5, 2003 and (ii) Reorganized NRG for the period from December 6, 2003 to December 31, 2003, as of December 31, 2003, as of and for the year ended December 31, 2004 and the nine months ended September 30, 2005 and 2004. “Predecessor Company” refers to NRG’s operations prior to December 6, 2003, before emergence from bankruptcy and “Reorganized NRG” refers to NRG’s operations from December 6, 2003 onwards, after emergence from bankruptcy.
      The selected historical consolidated financial information of Predecessor Company as of and for the year ended December 31, 2000, 2001 and 2002 and for the period from January 1, 2003 to December 5, 2003 is derived from the historical financial information contained in the audited consolidated financial statements of Predecessor Company incorporated by reference in this prospectus supplement.
      The selected historical consolidated financial information of Reorganized NRG for the period December 6, 2003 to December 31, 2003 and as of and for the year ended December 31, 2004 is derived from the historical financial information contained in the audited consolidated financial statements of Reorganized NRG incorporated by reference in this prospectus supplement. The summary unaudited historical consolidated financial information as of and for the nine months ended September 30, 2005 and 2004 (i) have been derived from Reorganized NRG’s unaudited consolidated financial statements which are incorporated by reference in this prospectus supplement, (ii) have been prepared on a similar basis to that used in the preparation of the audited financial statements of Reorganized NRG and (iii) in the opinion of NRG’s management, include all adjustments necessary for a fair statement of the results for the unaudited interim period.
      The selected historical consolidated financial information set forth below should be read in conjunction with management’s discussion and analysis of financial condition and results of operations and the consolidated financial statements of Predecessor Company and Reorganized NRG and the related notes thereto incorporated by reference into this prospectus supplement. The results for period of less than a full year are not necessarily indicative of the results to be expected for any interim period.

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 	 	Predecessor Company	 	 	Reorganized NRG	 	
 	 	 	 	 	 	 	
 	 	For the Year	 	 	For the Year	 	 	For the Year	 	 	Period from	 	 	Period from	 	 	For the Year	 	 	For the Nine	 	 	For the Nine	 	
 	 	Ended	 	 	Ended	 	 	Ended	 	 	January 1-	 	 	December 6-	 	 	Ended	 	 	Months Ended	 	 	Months Ended	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	December 5,	 	 	December 31,	 	 	December	 	 	September 30,	 	 	September 30,	 	
 	 	2000	 	 	2001	 	 	2002	 	 	2003	 	 	2003	 	 	31, 2004	 	 	2004	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	($ in thousands, except per share data)	 	
Income Statement Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating revenues	 	$	1,664,980	 	 	$	2,085,350	 	 	$	1,938,293	 	 	$	1,798,387	 	 	$	138,490	 	 	$	2,347,882	 	 	$	1,770,669	 	 	$	1,942,828	 	
Legal settlement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	462,631	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Fresh start reporting adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(4,118,636	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Reorganization items	 	 	—	 	 	 	—	 	 	 	—	 	 	 	197,825	 	 	 	2,461	 	 	 	(13,390	)	 	 	(1,656	)	 	 	—	 	
Restructuring and impairment charges	 	 	—	 	 	 	—	 	 	 	2,563,060	 	 	 	237,575	 	 	 	—	 	 	 	44,661	 	 	 	42,183	 	 	 	6,223	 	
Total operating costs and expenses	 	 	1,308,589	 	 	 	1,703,531	 	 	 	4,321,385	 	 	 	(1,475,523	)	 	 	122,328	 	 	 	1,955,887	 	 	 	1,459,756	 	 	 	1,861,569	 	
Minority interest in (earnings)/losses of consolidated subsidiaries	 	 	(840	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(134	)	 	 	(16	)	 	 	(18	)	 	 	(36	)	
Equity in earnings of unconsolidated affiliates	 	 	139,364	 	 	 	210,032	 	 	 	68,996	 	 	 	170,901	 	 	 	13,521	 	 	 	159,825	 	 	 	117,187	 	 	 	82,501	 	
Write downs and losses on sales of equity method investments	 	 	—	 	 	 	—	 	 	 	(200,472	)	 	 	(147,124	)	 	 	—	 	 	 	(16,270	)	 	 	(14,057	)	 	 	15,894	 	
Income/(loss) from continuing operations	 	 	149,729	 	 	 	210,502	 	 	 	(2,788,452	)	 	 	2,949,078	 	 	 	11,405	 	 	 	159,144	 	 	 	142,154	 	 	 	6,991	 	
Income/(loss) on discontinued operations, net of income taxes	 	 	33,206	 	 	 	54,702	 	 	 	(675,830	)	 	 	(182,633	)	 	 	(380	)	 	 	26,473	 	 	 	25,326	 	 	 	12,612	 	
Net income/(loss)(1)	 	 	182,935	 	 	 	265,204	 	 	 	(3,464,282	)	 	 	2,766,445	 	 	 	11,025	 	 	 	185,617	 	 	 	167,480	 	 	 	19,603	 	
Net income per share—basic	 	 	NA	 	 	 	NA	 	 	 	NA	 	 	 	NA	 	 	$	0.11	 	 	$	1.86	 	 	$	1.67	 	 	$	0.07	 	
Net income per share—diluted	 	 	NA	 	 	 	NA	 	 	 	NA	 	 	 	NA	 	 	$	0.11	 	 	$	1.85	 	 	$	1.67	 	 	$	0.07	 	
Weighted average shares outstanding—basic (in millions)	 	 	NA	 	 	 	NA	 	 	 	NA	 	 	 	NA	 	 	 	100	 	 	 	100	 	 	 	100	 	 	 	86	 	
Weighted average shares outstanding— diluted (in millions)	 	 	NA	 	 	 	NA	 	 	 	NA	 	 	 	NA	 	 	 	100	 	 	 	100	 	 	 	100	 	 	 	86	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company	 	 	Reorganized NRG	 	
 	 	 	 	 	 	 	
 	 	For the Year	 	 	For the Year	 	 	For the Year	 	 	Period from	 	 	Period from	 	 	For the Year	 	 	For the Nine	 	 	For the Nine	 	
 	 	Ended	 	 	Ended	 	 	Ended	 	 	January 1-	 	 	December 6-	 	 	Ended	 	 	Months Ended	 	 	Months Ended	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	December 5,	 	 	December 31,	 	 	December 31,	 	 	September 30,	 	 	September 30,	 	
 	 	2000	 	 	2001	 	 	2002	 	 	2003	 	 	2003	 	 	2004	 	 	2004	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(unaudited)	 	 	(unaudited)	 	
 	 	($ in thousands, except per share data)	 	 	 	 	 	
Other Financial and Operating Data and Ratios:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	$	(223,560	)	 	$	(1,322,130	)	 	$	(1,439,733	)	 	$	(113,502	)	 	$	(10,560	)	 	$	(114,360	)	 	$	(78,293	)	 	$	(45,518	)	
Depreciation and amortization	 	 	92,673	 	 	 	140,975	 	 	 	207,027	 	 	 	218,843	 	 	 	11,808	 	 	 	208,036	 	 	 	158,603	 	 	 	144,317	 	
Cash flows from operating activities	 	 	361,678	 	 	 	276,014	 	 	 	430,042	 	 	 	238,509	 	 	 	(588,875	)	 	 	643,993	 	 	 	595,421	 	 	 	(113,802	)	
Ratio of earnings to fixed charges (2)	 	 	1.81x	 	 	 	1.26x	 	 	 	—	(3)	 	 	9.82x(4	)	 	 	1.68x	 	 	 	1.83x	 	 	 	1.80x	 	 	 	1.19x	 	
Ratio of earnings to combined fixed charges and preference dividends (2)	 	 	1.81x	 	 	 	1.26x	 	 	 	—	(3)	 	 	9.82x	(4)	 	 	1.68x	 	 	 	1.82x	 	 	 	1.80x	 	 	 	1.04x	 	
Balance Sheet Data (at period end):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	 	36,746	 	 	$	86,738	 	 	$	360,860	 	 	 	395,982	 	 	$	551,223	 	 	$	1,103,678	 	 	$	1,098,782	 	 	$	504,336	 	
Restricted cash	 	 	7,236	 	 	 	68,320	 	 	 	211,966	 	 	 	493,047	 	 	 	116,067	 	 	 	109,633	 	 	 	145,571	 	 	 	91,508	 	
Total Assets	 	 	5,986,289	 	 	 	12,915,222	 	 	 	10,896,851	 	 	 	9,167,329	 	 	 	9,244,987	 	 	 	7,830,283	 	 	 	8,185,858	 	 	 	7,795,367	 	
Long-term debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Recourse corporate level debt	 	 	1,512,386	 	 	 	3,742,400	 	 	 	3,998,280	 	 	 	8,651	 	 	 	2,458,690	 	 	 	2,544,048	 	 	 	2,437,088	 	 	 	1,964,865	 	
 	Non-recourse project level debt	 	 	1,689,954	 	 	 	3,946,811	 	 	 	4,814,432	 	 	 	3,386,434	 	 	 	1,689,340	 	 	 	1,179,806	 	 	 	1,131,764	 	 	 	1,077,533	 	
 	Total long-term debt including current maturities	 	 	3,202,340	 	 	 	7,689,211	 	 	 	8,812,712	 	 	 	3,395,085	 	 	 	4,148,030	 	 	 	3,723,854	 	 	 	3,568,852	 	 	 	3,042,398	 	
Stockholders’ equity/(deficit)	 	 	1,462,088	 	 	 	2,237,129	 	 	 	(696,199	)	 	 	2,404,000	 	 	 	2,437,256	 	 	 	2,692,164	 	 	 	2,597,151	 	 	 	2,019,168	 	
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(1) 	Our results include the following items that have had a significant impact on our operations during the periods indicated below:	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Predecessor Company	 	 	Reorganized NRG	 	
 	 	 	 	 	 	 	
 	 	For the Year	 	 	For the Year	 	 	For the Year	 	 	Period from	 	 	Period from	 	 	For the Nine	 	 	For the Nine	 	 	For the Year	 	
 	 	Ended	 	 	Ended	 	 	Ended	 	 	January 1-	 	 	December 6-	 	 	Months Ended	 	 	Months Ended	 	 	Ended	 	
 	 	December 31,	 	 	December 31,	 	 	December 31,	 	 	December 5,	 	 	December 31,	 	 	September 30,	 	 	September 30,	 	 	December 31,	 	
 	 	2000	 	 	2001	 	 	2002	 	 	2003	 	 	2003	 	 	2004	 	 	2005	 	 	2004	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	(unaudited)	 	 	(unaudited)	 	
 	 	($ in thousands, except per share data)	 	 	 	 	 	
Income/(loss) on discontinued operations, net of income taxes	 	$	33,206	 	 	$	54,702	 	 	$	(675,830	)	 	$	(182,633	)	 	$	(380	)	 	$	26,473	 	 	$	25,326	 	 	$	12,612	 	
Legal settlement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	462,631	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Fresh start reporting adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(4,118,636	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Corporate relocation charges	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	16,167	 	 	 	12,474	 	 	 	5,651	 	
Reorganization items	 	 	—	 	 	 	—	 	 	 	—	 	 	 	197,825	 	 	 	2,461	 	 	 	(13,390	)	 	 	(1,656	)	 	 	—	 	
Restructuring and impairment charges	 	 	—	 	 	 	—	 	 	 	2,563,060	 	 	 	237,575	 	 	 	—	 	 	 	44,661	 	 	 	42,183	 	 	 	6,223	 	
Write downs and gains/(losses) on sales of equity method investments	 	 	—	 	 	 	—	 	 	 	(200,472	)	 	 	(147,124	)	 	 	—	 	 	 	(16,270	)	 	 	(14,057	)	 	 	15,894	 	
FERC authorized settlement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(38,357	)	 	 	(38,357	)	 	 	—	 	
Write down of Note Receivable	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4,572	 	 	 	4,572	 	 	 	—	 	

(2) 	The ratio of earnings to fixed charges is computed by dividing earnings by fixed charges. The ratio of earnings to fixed charges and preference dividends is computed by dividing earnings by fixed charges and preference dividends. For this purpose, “earnings” includes pre-tax income (loss) before adjustments for minority interest in our consolidated subsidiaries and income or loss from equity investees, plus fixed charges and distributed income of equity investees, and amortization of capitalized interest reduced by interest capitalized. “Fixed charges” include interest, whether expensed or capitalized for both continuing and discontinued operations, amortization of debt expense and the portion of rental expense that is representative of the interest factor in these rentals. “Preference dividends” equals the amount of pre-tax earnings that is required to pay the dividends on outstanding preference securities.	
 	 	
(3) 	For the year ended December 31, 2002, the deficiency of earnings to fixed charges was $3,023 million.	
 	 	
(4) 	For the period January 1, 2003 through December 5, 2003, the earnings include a one time earning of $4,119 million due to Fresh Start adjustments.	
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SELECTED CONSOLIDATED FINANCIAL INFORMATION OF TEXAS GENCO
      The following table sets forth selected historical consolidated financial information for Texas Genco LLC and its subsidiaries and for Texas Genco Holdings, Inc., Texas Genco LLC’s predecessor for financial reporting purposes, and its subsidiaries. Because Texas Genco LLC acquired Texas Genco Holdings, Inc. as part of a multi-step transaction in which the Initial Acquisition (as described below) was consummated on December 15, 2004 and the Nuclear Acquisition (as described below) was consummated on April 13, 2005, information is presented for (i) Texas Genco Holdings, Inc. as of and for the years ended December 31, 2002, 2003 and 2004, and as of and for the nine months ended September 30, 2004 and for the period from January 1, 2005 through April 13, 2005 and (ii) Texas Genco LLC as of December 31, 2004, the period from July 19, 2004, or Inception, through December 31, 2004 and as of and for the nine months ended September 30, 2005.
      The selected historical consolidated financial information for Texas Genco Holdings, Inc. as of and for the years ended December 31, 2000, 2001, 2002, 2003 and 2004 were derived from Texas Genco Holdings, Inc.’s audited financial statements incorporated by reference into this prospectus supplement. The selected historical consolidated financial information for Texas Genco Holdings, Inc. as of and for the nine months ended September 30, 2004 and for the period from January 1, 2005 through April 13, 2005 (i) were derived from Texas Genco Holdings, Inc.’s unaudited financial statements, (ii) have been prepared on a similar basis to that used in the preparation of Texas Genco Holdings, Inc.’s audited financial statements, and (iii) in the opinion of Texas Genco’s management, include all adjustments necessary for a fair statement of the results for the unaudited interim period. The financial information for Texas Genco Holdings, Inc. reflects ownership of the Non-Nuclear Assets for periods prior to December 15, 2004 and of an undivided 44.0% interest in STP for all periods presented, and is therefore not comparable to the historical financial information for Texas Genco LLC, which reflects ownership of the Non-Nuclear Assets only for periods subsequent to December 15, 2004, the Nuclear Acquisition only for periods subsequent to April 13, 2005 and the ROFR (as described below) only for periods subsequent to May 19, 2005.
      The selected historical consolidated financial information for Texas Genco LLC as of December 31, 2004 and for the period from July 19, 2004 (Inception) through December 31, 2004 were derived from the audited consolidated financial statements of Texas Genco LLC incorporated by reference into this prospectus supplement. The selected historical consolidated financial information for Texas Genco LLC as of and for the nine months ended September 30, 2005 (i) were derived from unaudited financial statements of Texas Genco LLC incorporated by reference into this prospectus supplement, (ii) have been prepared on a similar basis to that used in the preparation of the audited financial statements of Texas Genco LLC, and (iii) in the opinion of Texas Genco’s management, include all adjustments necessary for a fair statement of the results for the unaudited interim period. The results for a periods for less than a full year are not necessarily indicative of the results to be expected for any interim period. Texas Genco LLC did not exist prior to Inception; therefore, no consolidated financial and other information has been presented in the following table for Texas Genco LLC for any other period.
      The selected consolidated historical financial information of Texas Genco LLC and Texas Genco Holdings, Inc. set forth below should be read in conjunction with management’s discussion and analysis of financial condition and results of operations and the consolidated financial statements of Texas Genco LLC and Texas Genco Holdings, Inc. and the related notes thereto incorporated by reference into this prospectus supplement.

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 	 	Texas Genco Holdings, Inc.— Predecessor	 	 	Texas Genco LLC(1)	 	
 	 	 	 	 	 	 	
 	 	 	 	Period from	 	 	Period from	 	 	 	
 	 	 	 	January 1,	 	 	July 19,	 	 	 	
 	 	 	 	For the Nine	 	 	2005	 	 	2004	 	 	For the Nine	 	
 	 	 	 	Months Ended	 	 	through	 	 	through	 	 	Months Ended	 	
 	 	For the Years Ended December	 	 	September 30,	 	 	April 13,	 	 	December 31,	 	 	September 30,	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2000(2)	 	 	2001(2)	 	 	2002	 	 	2003	 	 	2004	 	 	2004	 	 	2005	 	 	2004	 	 	2005	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	(unaudited)	 	 	 	 	 	 	(unaudited)	 	
 	 	($ in millions, except per unit data)	 	
Statement of Operations Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues(3)	 	$	3,334	 	 	$	3,411	 	 	$	1,541	 	 	$	2,002	 	 	$	2,054	 	 	$	1,630	 	 	$	61	 	 	$	96	 	 	$	2,000	 	
Operating expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Fuel and purchased power expense (4)	 	 	2,397	 	 	 	2,527	 	 	 	1,083	 	 	 	1,171	 	 	 	1,021	 	 	 	810	 	 	 	6	 	 	 	45	 	 	 	913	 	
Operation and maintenance (5)	 	 	393	 	 	 	402	 	 	 	391	 	 	 	411	 	 	 	415	 	 	 	319	 	 	 	35	 	 	 	24	 	 	 	329	 	
Depreciation and amortization	 	 	151	 	 	 	154	 	 	 	157	 	 	 	159	 	 	 	89	 	 	 	85	 	 	 	5	 	 	 	13	 	 	 	253	 	
 	Write-down of assets (6)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	763	 	 	 	649	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	Gain on sale of assets	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(28	)	
Taxes other than income taxes	 	 	63	 	 	 	63	 	 	 	43	 	 	 	39	 	 	 	41	 	 	 	33	 	 	 	3	 	 	 	—	 	 	 	35	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total	 	 	3,004	 	 	 	3,146	 	 	 	1,674	 	 	 	1,780	 	 	 	2,329	 	 	 	1,896	 	 	 	49	 	 	 	82	 	 	 	1,502	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	330	 	 	 	265	 	 	 	(133	)	 	 	222	 	 	 	(275	)	 	 	(267	)	 	 	12	 	 	 	14	 	 	 	498	 	
Other income	 	 	1	 	 	 	2	 	 	 	3	 	 	 	2	 	 	 	5	 	 	 	3	 	 	 	1	 	 	 	—	 	 	 	3	 	
Interest income (expense), net (7)	 	 	(59	)	 	 	(65	)	 	 	(26	)	 	 	(2	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(34	)	 	 	(134	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) before income taxes	 	 	272	 	 	 	202	 	 	 	(156	)	 	 	222	 	 	 	(270	)	 	 	(264	)	 	 	13	 	 	 	(20	)	 	 	367	 	
Income tax expense (benefit) (8)	 	 	100	 	 	 	74	 	 	 	(63	)	 	 	71	 	 	 	(171	)	 	 	(94	)	 	 	4	 	 	 	—	 	 	 	21	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) before cumulative effective of accounting change	 	 	172	 	 	 	128	 	 	 	(93	)	 	 	151	 	 	 	(99	)	 	 	(170	)	 	 	9	 	 	 	(20	)	 	 	346	 	
Cumulative effect of accounting change, net of tax (9)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	99	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income (loss)	 	$	172	 	 	$	128	 	 	$	(93	)	 	$	250	 	 	$	(99	)	 	$	(170	)	 	$	9	 	 	$	(20	)	 	$	346	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings Per Share Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss) per share— basic	 	$	2.15	 	 	$	1.60	 	 	$	(1.16	)	 	$	3.13	 	 	$	(1.25	)	 	$	(2.13	)	 	$	0.14	 	 	$	(0.13	)	 	$	2.05	 	
Net income (loss) per share— diluted	 	 	2.15	 	 	 	1.60	 	 	 	(1.16	)	 	 	3.13	 	 	 	(1.25	)	 	 	(2.13	)	 	 	0.14	 	 	 	(0.13	)	 	 	1.98	 	
Weighted average shares outstanding— basic (in millions) (10)	 	 	80.0	 	 	 	80.0	 	 	 	80.0	 	 	 	80.0	 	 	 	79.4	 	 	 	80.0	 	 	 	64.8	 	 	 	156.5	 	 	 	168.6	 	
Weighted average shares outstanding— diluted (in millions) (10)	 	 	80.0	 	 	 	80.0	 	 	 	80.0	 	 	 	80.0	 	 	 	79.4	 	 	 	80.0	 	 	 	64.8	 	 	 	156.5	 	 	 	175.1	 	
Other Financial Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	$	252	 	 	$	409	 	 	$	258	 	 	$	157	 	 	$	73	 	 	$	46.0	 	 	$	9	 	 	$	6	 	 	$	74	 	
Balance Sheet Data (at period end):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, plant and equipment, net (11)	 	$	3,667	 	 	$	3,905	 	 	$	4,096	 	 	$	4,126	 	 	$	474	 	 	$	478	 	 	$	474	 	 	$	2,446	 	 	$	3,542	 	
Total assets(12)	 	 	4,032	 	 	 	4,323	 	 	 	4,508	 	 	 	4,640	 	 	 	1,395	 	 	 	4,272	 	 	 	996	 	 	 	4,588	 	 	 	6,099	 	
Total debt	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	75	 	 	 	2,280	 	 	 	2,743	 	
Net capitalization	 	 	2,323	 	 	 	2,624	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Shareholders’ equity	 	 	—	 	 	 	—	 	 	 	2,824	 	 	 	3,033	 	 	 	454	 	 	 	2,680	 	 	 	466	 	 	 	—	 	 	 	—	 	
Members’ equity (12)(13)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	772	 	 	 	773	 	

  (1) 	Texas Genco LLC was formed on July 19, 2004 to facilitate the acquisition of Texas Genco Holdings, Inc. in a multi-step transaction from CenterPoint Energy, Inc. and other minority public stockholders. On December 13, 2004, Texas Genco Holdings, Inc. divided its nuclear and non-nuclear generating assets and liabilities between two of its wholly-owned subsidiaries. Its non-nuclear generating assets and liabilities were allocated to Texas Genco II, LP and its nuclear assets and liabilities and its cash were allocated to Texas Genco, LP. The non-nuclear generating assets and liabilities, together with assets and liabilities unrelated to the wholesale generation business held by Texas Genco Services, LP, another wholly-owned subsidiary of Texas Genco Holdings, Inc., are referred to as the “Non-Nuclear Assets.” On December 14, 2004, Texas Genco Holdings, Inc. merged with a wholly-owned subsidiary of CenterPoint Energy, Inc. As a result of this merger, CenterPoint Energy, Inc. acquired 100% of the issued and outstanding common stock of Texas Genco Holdings, Inc. On December 15, 2004, two wholly-owned subsidiaries of Texas Genco LLC merged with and into Texas Genco II, LP and Texas Genco Services, LP, respectively. As a result of these mergers, referred to as the “Initial Acquisition,” Texas Genco II, LP and Texas Genco Services, LP became wholly-owned subsidiaries of Texas Genco LLC and Texas Genco LLC thereby acquired the Non-Nuclear Assets. On April 13, 2005, a wholly-owned subsidiary of Texas Genco LLC merged with and into Texas Genco Holdings, Inc. As a result of this merger, which is referred to as the “Nuclear Acquisition,” Texas Genco Holdings, Inc. became a wholly-owned subsidiary of Texas Genco LLC and Texas Genco LLC thereby indirectly acquired Texas Genco Holdings, Inc.’s assets and liabilities, including its indirect 30.8% undivided interest in STP. On May 19, 2005, pursuant to the exercise of a right of first refusal by Texas Genco, LP subsequent to a third party offer to American Electric Power, or AEP, in early 2004, Texas Genco LLC acquired from AEP an additional indirect 13.2% undivided interest, equivalent to 330 MW, in STP for approximately $174.2 million, less adjustments for working capital and other purchase price adjustments. This acquisition is referred to as the “ROFR.” As a result, Texas Genco LLC, through Texas Genco, LP, owns a 44.0% undivided interest, equivalent to 1,101 MW, in STP. The transactions described above are referred to, collectively, as the “The Texas Genco Formation Transactions.”	
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  (2) 	Prior to January 1, 2002, Texas Genco Holdings, Inc. sold power as part of an integrated utility at regulated rates; thereafter, power was sold at market-based rates. Therefore, the historical information included in the Texas Genco Holdings, Inc. financial statements for periods prior to January 1, 2002 does not reflect what the financial position and results of operations of Texas Genco Holdings, Inc. would have been had Texas Genco Holdings, Inc. been operated as a separate, stand-alone wholesale electric power generation company in a deregulated market during the periods presented.	
 	 	
  (3) 	Revenues for Texas Genco LLC include amortization of the liability related to below-market power sales contracts recorded in connection with the Initial Acquisition and the effect of other non-trading derivatives, which increased revenues by $12.3 million and decreased revenues by $3.6 million, respectively, for the period from Inception through December 31, 2004. For the nine months ended September 30, 2005, amortization of the liability related to below-market power sales contracts increased revenues for Texas Genco LLC by $186.3 million and the effect of other non-trading derivatives decreased revenues for Texas Genco LLC by $28.9 million.	
 	 	
  (4) 	Fuel and purchased power expense for Texas Genco LLC includes fuel-related depreciation and amortization— amortization of nuclear fuel— and the amortization of the liability related to above-market coal purchase contracts (which contracts expire in 2010) recorded in connection with the Initial Acquisition. Fuel-related depreciation and amortization had no effect on fuel expense for the period of Inception through December 31, 2004 and increased fuel expense by $10.3 million for the nine months ended September 30, 2005. The amortization of the liability related to above-market coal purchase contracts decreased fuel and purchased power expense for Texas Genco LLC by $1.5 million for the period from Inception through December 31, 2004 and $37.0 million for the nine months ended September 30, 2005.	
 	 	
  (5) 	Operation and maintenance for Texas Genco Holdings, Inc. includes allocations of overhead costs from CenterPoint Energy, Inc. Operations and maintenance for Texas Genco LLC includes payments to CenterPoint Energy, Inc. and Reliant Energy, Inc. for transition services. Operations and maintenance for Texas Genco LLC for the nine months ended September 30, 2005 includes a charge of $35.3 million related to our workforce optimization plan and a payment of $7.5 million of monitoring fees paid to affiliates of The Blackstone Group, Hellman & Friedman LLC, Kohlberg Kravis Roberts & Co. L.P. and Texas Pacific Group.	
 	 	
  (6) 	For the year ended December 31, 2004, Texas Genco Holdings, Inc. recorded an asset impairment of $763.0 million ($426.0 million net of tax) to reflect the net realizable value for the assets to be sold in the Initial Acquisition. Texas Genco Holdings, Inc. ceased depreciation on its coal, lignite and natural gas-fired generation plants at the time these assets were considered “held for sale.” This resulted in a decrease in depreciation expense of $69.0 million for the year ended December 31, 2004 as compared to the same period in 2003.	
 	 	
  (7) 	Interest income (expense), net for Texas Genco LLC includes amortization of deferred financing fees of $(1.0) million for the period from Inception through December 31, 2004 and $10.5 million for the nine months ended September 30, 2005.	
 	 	
  (8) 	Texas Genco LLC is a limited liability company that is treated as a partnership for U.S. federal income tax purposes and is, therefore, not itself subject to federal income taxation. Profits or losses are subject to taxation at the member interest level. Texas Genco Holdings, Inc., holds an indirect 44.0% undivided interest in STP and is a corporation that is subject to U.S. federal income taxation on its income.	
 	 	
  (9) 	Cumulative effect of an accounting change resulting from the allocation of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”	

(10) 	Texas Genco Holdings, Inc.’s Board of Directors declared an 80,000,000-for-one stock split that was effected on December 18, 2002. On January 6, 2003, CenterPoint Energy distributed approximately 19% of the 80,000,000 outstanding shares of Texas Genco’s common stock to CenterPoint Energy’s shareholders. Earnings per share has been presented as if the 80,000,000 shares were outstanding for all historical periods in accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share.”	
 	 	
(11) 	In accordance with ERCOT rules, Texas Genco has placed four units into mothball status for more than 180 days, retired one unit, sold one unit and intends to sell eight units, together representing approximately 3,378 MW of available capacity. Texas Genco placed one additional unit representing approximately 461 MW of net capacity, which was operated pursuant to a “reliability must run” contract with the ERCOT, into mothball status for more than 180 days when the contract terminated on October 29, 2005. On November 14, 2005, Texas Genco completed the sale of its natural gas-fired generation plant at Deepwater, representing 174 MW of available capacity.	
 	 	
(12) 	Total assets and members’ equity as of September 30, 2005 reflects distributions to members of an aggregate of $85.8 million from July 1, 2005 through September 30, 2005, representing preliminary distributions of net proceeds relating to certain asset sales.	
 	 	
(13) 	Members’ equity includes capital contributions from Texas Genco’s existing equityholders of $899.5 million, of which $892.2 million was contributed by the investment funds affiliated with The Blackstone Group, Hellman & Friedman LLC, Kohlberg Kravis Roberts & Co. L.P. and Texas Pacific Group and $7.3 million was contributed by certain members of Texas Genco’s management team.	
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LIQUIDITY AND CAPITAL RESOURCES DISCUSSION
      Our unaudited pro forma combined financial information incorporated by reference into this prospectus supplement does not purport to represent what our financial condition would actually have been had the Acquisition and the Financing Transactions in fact occurred on the dates specified below or to project our results of operations for any future period. See “Risk Factors—Risks Related to the Acquisition—Because the historical and pro forma financial information incorporated by reference or included elsewhere in this prospectus supplement may not be representative of our capital structure after the Acquisition, and NRG’s and Texas Genco’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate us, NRG, Texas Genco and your investment decision.” In addition, the closing of this offering is not conditioned on the consummation of the Acquisition. While we expect that the Acquisition will be consummated in or about the first week of February 2006, no assurance can be given that the Acquisition will be completed in accordance with the anticipated timing or at all. See “Risk Factors—Risks Related to the Offering—There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not consummated, NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.” For information regarding NRG’s management’s discussion and analysis of financial condition and results of operations, see “Incorporation of Certain Documents by Reference” and “Where You Can Find More Information.”
      The adjustments reflected in our unaudited pro forma financial information are based on available information and assumptions we believe are reasonable, including our assumptions regarding the financing for the Acquisition that may prove to be inaccurate. See “Risk Factors—Risks Related to the Offering—If NRG is unable to raise sufficient proceeds through other Financing Transactions described elsewhere in this prospectus supplement, NRG may draw down on a bridge loan facility in order to close the Acquisition which would significantly increase our indebtedness. If NRG elects not to consummate the financing under the bridge loan facility, NRG may seek alternative sources of financing for the Acquisition, the terms of which are unknown to us and could limit our ability to operate our business” elsewhere in this prospectus supplement.
Basis of Presentation
      On September 30, 2005, NRG entered into the Acquisition Agreement with Texas Genco and the Sellers. Under the Acquisition Agreement, NRG agreed to purchase from the Sellers 100% of the outstanding equity interests of Texas Genco. After the completion of the Acquisition, Texas Genco will become a 100% wholly-owned subsidiary of NRG. The Acquisition is currently expected to close in the first quarter of 2006. For a discussion of the Acquisition, see “The Acquisition.”
      The Management’s Discussion and Analysis of Financial Condition and Results of Operations, or MD&A, for each of NRG and Texas Genco incorporated by reference into this prospectus supplement were based upon each of their respective historical financial statements, and should each be read together with their respective historical consolidated financial statements, the notes to those financial statements and the other financial information incorporated by reference or appearing elsewhere in this prospectus supplement. Because neither NRG’s nor Texas Genco’s historical financial statements reflect the Acquisition and the Financing Transactions, a discussion of NRG’s and Texas Genco’s historical results of operations do not provide a sufficient understanding of the financial condition and results of operations of our business after giving effect to the consummation of the Acquisition and the Financing Transactions.
      NRG’s historical financial statements for the 2003 fiscal year are not comparable to its current financial statements. As a result of NRG’s emergence from bankruptcy, it is operating its business with a new capital structure, and is subject to Fresh Start reporting requirements prescribed by generally accepted accounting principles in the United States. As required by Fresh Start reporting, assets and liabilities as of December 6, 2003 were recorded at fair value, with the enterprise value being determined in connection with the reorganization. Texas Genco’s historical financial statements are not comparable to its current financial

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statements. Texas Genco did not exist prior to July 19, 2004 and, accordingly no comparative financial information for prior periods is available.
      The pro forma results also include adjustments for the following transactions that either occurred after the announcement of the Acquisition or pursuant to applicable rules are reflected in our pro forma results:
 	 	
 	      (i) On December 8, 2005 NRG entered into an Asset Purchase and Sale Agreement to sell all the assets of NRG Audrain Generating LLC, or Audrain, to AmerenUE, a subsidiary of Ameren Corporation. For purposes of these pro forma statements we have reflected the sale of assets of Audrain as a discontinued operation. The purchase price is $115 million, subject to customary purchase price adjustments. The transaction is expected to close during the first half of 2006. The sale is subject to customary approvals, including FERC, Missouri Public Utilities Commission, Illinois Commerce Commission, and Hart-Scott-Rodino review. We expect to record a gain of approximately $15 million at closing.	
 	 	
 	      (ii) On May 19, 2005, pursuant to the exercise of a right of first refusal, or the RFOR, by Texas Genco, subsequent to a third party offer to American Electric Power, or AEP, in early 2004, Texas Genco acquired from AEP an additional 13.2% undivided interest in South Texas Project, or STP. As a result, Texas Genco now owns a 44.0% undivided interest in STP. For pro forma purposes, NRG has accounted for the ROFR as a business acquisition and included the ROFR in our pro forma adjustments to the statements of operation.	
 	 	
 	      (iii) On December 27, 2005, NRG entered into two purchase and sale agreements for projects co-owned with Dynegy, Inc. Under the agreements, NRG will acquire Dynegy’s 50 percent ownership interest in WCP Holdings, and become the sole owner of WCP’s 1,808 MW of generation in Southern California. In addition, NRG is selling to Dynegy its 50 percent ownership interest in Rocky Road Power LLC, or Rocky Road, a 330 MW gas-fueled, simple cycle peaking plant located in Dundee, Illinois. These transactions are conditioned upon each other and NRG will pay Dynegy a net purchase price of $160 million at closing. NRG will effectively fund the net purchase price with cash held by WCP. NRG anticipates closing both transactions during the first quarter 2006. For purposes of these pro forma financial statements, we have assumed that the fair value of our equity investment in Rocky Road is equal to the negotiated price of $45 million. The current cost of our investment in Rocky Road is $70.2 million as of September 30, 2005 and we will record an impairment in our investment due to an other-than-temporary loss in our Rocky Road investment in the amount of $25.2 million.	
      For these reasons, our discussion below focuses on a discussion of our pro forma combined financial position as of September 30, 2005, which is included in a Current Report on a Form 8-K filed on December 21, 2005 as amended by our current report on From 8-K/ A as filed on January 5, 2006, our current report on Form 8-K/A as filed on January 23, 2006 and our current report on Form 8-K/ A as filed on January 26, 2006, and incorporated by reference into this prospectus supplement.
      This pro forma financial information may not reflect what our financial position would have been had we operated on a combined basis and may not be indicative of what our financial position will be in the future.
      The discussion below contains certain statements of a forward-looking nature that involve risks and uncertainties. As a result of many factors, including those set forth under the sections entitled “Disclosure Regarding Forward-Looking Statements” and “Risk Factors” and those appearing elsewhere in this prospectus supplement, actual results may differ materially from those anticipated by such forward-looking statements.
Liquidity and Capital Resources
      We plan to enter into a new senior secured credit facility for up to an aggregate amount of $5.575 billion to replace our existing senior credit facility. The senior secured credit facility is expected to consist of a $3.575 billion senior first priority secured term loan facility, a $1.0 billion senior first priority secured revolving credit facility and a $1.0 billion senior first priority secured synthetic letter of credit facility. Morgan Stanley Senior Funding, Inc., an affiliate of one of the underwriters for this offering, will be the administrative agent

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and one of its affiliates will be the collateral agent pursuant to the new senior secured credit facility. Citigroup Global Markets Inc., one of the underwriters for this offering, will be the syndication agent. Morgan Stanley Senior Funding, Inc. and Citigroup Global Markets Inc. will be the joint lead book runners, joint lead arrangers and co-documentation agents thereunder. Morgan Stanley Senior Funding, Inc., Citigroup Global Markets Inc., Lehman Commercial Paper Inc., Bank of America, N.A., Deutsche Bank AG Cayman Islands Branch, Merrill Lynch Capital Corporation and Goldman Sachs Credit Partners L.P., each an underwriter or an affiliate of one of the underwriters for this offering, will be lenders under the new senior secured credit facility.
      We expect to draw down approximately $3.575 billion from the term loan facility to be used together with the net proceeds (after giving effect to underwriting discounts and commissions) of approximately $3.53 billion from the notes offering, the offerings of common stock of $1.0 billion, $0.5 billion in mandatory convertible preferred stock and additional cash on hand, to finance the Acquisition, to repay $2 billion of our indebtedness and $2.7 billion of Texas Genco’s outstanding indebtedness and to pay related fees and expenses. Also see “Use of Proceeds— Sources and Uses of Funds.”
      The new senior secured credit facility will be guaranteed by substantially all of our subsidiaries, with certain customary or agreed-upon exceptions for immaterial subsidiaries and subsidiaries defined as “unrestricted,” foreign subsidiaries and certain project subsidiaries. In addition, it will be secured by liens on substantially all of our assets and the assets of our subsidiaries, with certain customary or agreed-upon exceptions for foreign subsidiaries, certain project subsidiaries and other subsidiaries or assets, and by a pledge of certain of our subsidiaries’ capital stock.
      The term loan, the revolving credit and the synthetic letter of credit facilities will mature in seven, five and seven years, respectively, from the closing date of the new senior secured credit facility. The term loan facility amortizes on a quarterly basis as described in “Description of Certain Indebtedness — New Senior Secured Credit Facility.” Borrowings under the new senior secured credit facility bear interest at an alternate base rate (calculated on the basis of prime rate) plus an applicable margin, or at an adjusted Eurodollar rate (calculated on the basis of the LIBO rate) plus an applicable margin, in each case as described in “Description of Certain Indebtedness—New Senior Secured Credit Facility.”
      There are certain affirmative and negative covenants (including financial covenants) placed on us under the new senior secured credit facility, including, but not limited to, restrictions on equity issuances, payment of dividends on or capital stock, the issuance of additional debt, incurrence of liens and capital expenditures, as further described in “Description of Certain Indebtedness—New Senior Secured Credit Facility.”
      As of September 30, 2005, on a pro forma basis after giving effect to the Acquisition and the Financing Transactions, our new senior first priority secured term loan facility would be drawn in its entirety, $1 billion of borrowings would be available under our new senior first priority secured revolving credit facility and $1 billion of undrawn letters of credit capacity would have been available under our new senior first priority secured synthetic letter of credit facility. As of September 30, 2005, on a pro forma basis after giving effect to (i) the sale of Audrain; (ii) the inclusion of the results pursuant to the ROFR; (iii) the refinancing of NRG’s old debt structure; (iv) the remaining Financing Transactions and subsequent Acquisition; and (v) the acquisition of the remaining 50% ownership interest in WCP Holdings and the sale of our 50% ownership interest in Rocky Road, we would have had approximately $8.0 billion of indebtedness, which includes the notes and amounts outstanding under our new senior secured credit facility. Of this total, approximately $3.575 billion would have been our secured indebtedness and the secured indebtedness of our subsidiaries. Interest payments on the notes and on borrowings under the new senior secured credit facility will significantly increase our liquidity requirements. See “Capitalization.”
      Certain of our subsidiaries and affiliates are subject to project financing. Such entities will not guarantee our obligations on the notes. The debt agreements of these subsidiaries and project affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. On a pro forma basis, giving effect to (i) the sale of Audrain; (ii) the inclusion of the results pursuant to the ROFR; (iii) the refinancing of NRG’s old debt structure; (iv) the remaining Financing Transactions and subsequent Acquisition; and (v) the acquisition of the remaining 50% ownership interest in WCP Holdings and the sale of our 50%

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ownership interest in Rocky Road, our guarantor subsidiaries would have represented approximately 90% of our revenues from wholly owned subsidiaries for the fiscal year ended December 31, 2004, and the nine months ended September 30, 2005. On a pro forma basis, our guarantor subsidiaries would have held approximately 90% of our consolidated assets as of September 30, 2005, and our non-guarantor subsidiaries would have had approximately $781 million in aggregate principal amount of funded indebtedness as of September 30, 2005. Our outstanding consolidated trade payables would have been $339 million as of September 30, 2005, on a pro forma basis. On a pro forma basis, approximately 77% of these trade payables would have constituted obligations of NRG Energy, Inc. and our guarantor subsidiaries.
      We expect that our 2006 total capital expenditures will be approximately $295.5 million and will relate to the operation and maintenance of our existing generating facilities. Also, see further discussions in the respective management’s discussion and analysis of financial condition and results of operations of NRG Energy Inc. and Texas Genco incorporated herein by reference.
      Texas Genco entered into a power purchase agreement with J. Aron & Company, the commodities trading subsidiary of Goldman Sachs & Co, which we refer to as J. Aron and the related agreement as the J. Aron PPA. Under the J. Aron PPA, Texas Genco sold forward, on a fixed price basis, a substantial portion of its expected ERCOT generation capacity beginning January 1, 2005 through December 31, 2010. As a result of the J. Aron PPA and certain power sales and gas swap transactions, approximately 26% of Texas Genco’s net baseload generation capacity in Texas, and approximately 16% of the combined company’s total net baseload capacity, as measured in MWh through 2010 has been sold on a fixed price basis to J. Aron, making J. Aron one of the combined company’s largest customers on a going forward basis.
      As collateral for Texas Genco’s obligations under the J. Aron PPA and certain power sales and gas swap transactions, Texas Genco agreed to post letters of credit and grant a second lien on Texas Genco’s assets in favor of J. Aron. For a detailed description of these credit support arrangements, see “Description of Certain Indebtedness.” The obligations of J. Aron under the J. Aron PPA and a subsequent natural gas swap are supported by an unlimited guarantee from J. Aron’s parent, The Goldman Sachs Group, Inc.
      Six other trading counterparties have similar arrangements with Texas Genco related to hedging agreements through December 31, 2010 collateralized by letters of credit and a retained second lien on the Texas Genco’s assets. These additional six counterparties comprise approximately 22% of Texas Genco’s net baseload capacity in Texas, and approximately 13% of the combined company’s total net baseload capacity, as measured in MWh through December 31, 2010. NRG expects that, at the closing of the Acquisition and the Financing Transactions, the collateral arrangements described above, including with respect to certain counterparties holding second liens on the ERCOT assets, will remain in place or will be replaced with substitute collateral arrangements comprising an interest in a second lien position on substantially all of NRG’s assets. On a going forward basis, NRG intends to secure some or all of its commodity hedging activities with interests in a second lien position on substantially all of NRG’s assets. There can be no assurance that this second lien position will provide enough capacity to cover all commodity hedges that are necessary or desirable for adequately hedging NRG’s commodity risk. See “Risk Factors—Risks Related to the Operation of our Business—We may not have sufficient liquidity to hedge market risks effectively.”
      As discussed in the “Business” section in respect to Texas Genco’s forward power sales, our revenues and cash flows from operations from forward power sales will decrease from $1.6 billion to $1.4 billion due to a reduction in the average contracted rates, from $44 per MWh to $39 per MWh. Total MWh’s sold remains substantially the same. This reduction in the contracted price will reduce the revenues and cash flows from operations of the combined company by approximately $209 million during 2007 in comparison to 2006. However, based upon our current level of operations, we believe that our existing cash and cash equivalents balances and our cash from operating activities, together with available borrowings under our new senior secured credit facility will be adequate to meet our anticipated requirements for working capital, capital expenditures, commitments, contingent purchase prices, program and other discretionary investments, and interest and principal payments for at least the next twenty-four months.
      In the event that NRG is unable to raise sufficient proceeds through the consummation of the New Senior Notes offering and/or the mandatory convertible preferred stock offering described elsewhere in this

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prospectus supplement, NRG may draw down, in whole or in part, on a $5.1 billion bridge loan facility made available to it by the bridge lenders in order to finance the Acquisition. See “Description of Certain Indebtedness—Bridge Loan Facility.” In the event of such draw down, we would be significantly more highly leveraged, which means we will have a larger amount of indebtedness in relation to our stockholders’ equity. Our interest expense would significantly increase and require us to dedicate a substantial portion of our cash flow from operations to payments in respect of our outstanding indebtedness. Our substantial indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our debt instruments. In the event that NRG does not consummate the New Senior Notes and mandatory convertible stock offerings as currently contemplated and elects not to consummate the financing under the bridge loan facility, it could seek alternative sources of financing for the Acquisition, which may include, among other alternatives, the issuance in part of senior secured debt securities or borrowing in part on a senior secured basis. There can be no assurance as to the terms on which NRG would issue these senior secured debt securities or borrow funds. We are unable to predict the interest rate payable on any such debt or give any assurance that the terms would not restrict our financial flexibility or limit our ability to operate our business. See “Risk Factors—Risks Related to the Offering—If NRG is unable to raise sufficient proceeds through other Financing Transactions described elsewhere in this prospectus supplement, NRG may draw down on a bridge loan facility in order to close the Acquisition which would significantly increase our indebtedness. If NRG elects not to consummate the financing under the bridge loan facility, NRG may seek alternative sources of financing for the Acquisition, the terms of which are unknown to us and could limit our ability to operate our business.”

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BUSINESS
Business
      In this section, “NRG” refers to NRG Energy, Inc. together with its consolidated subsidiaries, and “Texas Genco” refers to Texas Genco LLC, together with its consolidated subsidiaries. On September 30, 2005, NRG entered into a definitive agreement to acquire Texas Genco. “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 pro forma effect to the completion of the Acquisition and the Financing Transactions. 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 September 30, 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). The MW and MWh figures and other operational figures related to the combined company only give pro forma effect to the Acquisition and the Financing Transactions.
      The closing of this offering is not conditioned on the consummation of the Acquisition. While we expect that the Acquisition will be consummated in or about the first week of February 2006, no assurance can be given that the Acquisition will be completed in accordance with the anticipated timing or at all. See “Risk Factors—Risks Related to the Offering—There can be no assurance that the Acquisition will be consummated in accordance with the anticipated timing or at all, and the closing of this offering is not conditioned on the consummation of the Acquisition. If the Acquisition is not consummated, NRG’s common stock will not reflect any actual or anticipated interest in Texas Genco, and if the Acquisition is delayed, this interest will not be reflected during the period of delay.” For more information regarding the business and operations of NRG, see “Incorporation of Certain Documents by Reference” and “Where You Can Find More Information.”
      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 the marketing of energy, capacity and related products in the competitive markets in which we operate. As of September 30, 2005, the combined company would have had a total global portfolio of 235 operating generation units at 62 power generation plants, with an aggregate generation capacity of approximately 25,041 MW. Within the United States, the combined company will have one of the largest and most diversified power generation portfolios with approximately 23,124 MW of generation capacity in 213 generating units at 54 plants as of September 30, 2005. These power generation facilities are primarily located in our core regions in the Electric Reliability Council of Texas, or ERCOT, market (approximately 11,119 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, which we refer to as the merit order, 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.
Our Strategy
      Our strategy is to increase the value of, and extract maximum value from, our generation assets while using that asset base as a platform for enhanced financial performance which can be sustained and expanded upon the 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

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bulk power requirements of our customer base and other entities who offer load, or otherwise consume wholesale electricity products and services in bulk. Our strategy includes the following elements:
      Increase value from our existing assets. Following the Acquisition, we believe that we will 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 “ FOR NRG,” or Focus on ROIC@NRG.
      Pursue intrinsic growth opportunities at existing sites in our core regions. We believe that 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 the merit order.
      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 intend to 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 leveraging our expertise in marketing 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 will have one of the largest and most diversified power generation portfolios in the United States with approximately 23,124 MW of generation capacity in 213 generating units at 54 plants as of September 30, 2005. Our power generation assets will be diversified by fuel type, dispatch level and region, which will help mitigate the risks associated with fuel price volatility and market demand cycles. The combined company’s U.S. baseload facilities, which will consist of approximately 8,558 MW of generation capacity measured as of September 30, 2005, will provide the combined company with a significant source of stable cash flow, while the combined company’s intermediate and peaking facilities, with approximately 14,566 MW of generation capacity as of September 30, 2005, will 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 will have dual or multiple fuel capability, which will allow most of these plants to dispatch with the lowest cost fuel option.

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      The following chart demonstrates the diversification of the combined company’s generation assets:
 	 	 	 	 	
Approximate U.S. Portfolio Net	 	Approximate U.S. Portfolio Net	 	Approximate U.S. Portfolio Net	
Capacity By Fuel Type(1)	 	Capacity By Dispatch Level	 	Capacity By Region	

 	 	
(1) 	Reflects only domestic generation capacity; 19 MW of wood-fired generation capacity not shown. Also includes 461 MW of generation capacity from facilities that were mothballed after September 30, 2005.	
     Reliability of future cash flows. We have sold forward a significant amount of our expected baseload generation capacity for 2006 and 2007. As of September 30, 2005 the combined company would have sold forward 68% of its baseload generation in the Texas (ERCOT) market for 2006 through 2009. As of the same date, the combined company would have sold approximately 83% of its expected annual baseload generation in the Southeastern Electric Reliability Council/ Entergy, or SERC— Entergy, market for 2006 through 2009, and approximately 70% of its expected annual baseload generation in the Northeast region for 2006. In addition, as of September 30, 2005, the combined company would have purchased forward under fixed price 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 September 30, 2005, approximately 38% of the combined company’s domestic generation capacity would have 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 that currently have substantially higher variable costs than our solid fuel baseload power plants. For example, in the ERCOT market, a 2004 report by Henwood found that natural gas-fired power plants set the market price of power more than 90% of the time. 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 combined company will have 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 others, selling power at prevailing market prices during periods of peak demand and providing ancillary services in support of system reliability.

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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 September 30, 2005, Texas Genco’s generation assets in the ERCOT market consisted of approximately 5,178 MW of baseload generation assets and approximately 5,941 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 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, as of September 30, 2005, 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, as of September 30, 2005, the ERCOT baseload forward power sales and natural gas swap agreements that extend beyond December 31, 2005 and were transacted through September 30, 2005.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	Annual Average for	 	 	Annual Average for	 	
 	 	2006	 	 	2007	 	 	2008	 	 	2009	 	 	2010	 	 	2006-2007	 	 	2006-2010	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Baseload Capacity (MW)(1)	 	 	5,294	 	 	 	5,340	 	 	 	5,340	 	 	 	5,340	 	 	 	5,340	 	 	 	5,317	 	 	 	5,331	 	
Total Baseload Sales (MW)(2)	 	 	4,274	 	 	 	4,271	 	 	 	4,152	 	 	 	3,428	 	 	 	1372	 	 	 	4,273	 	 	 	3,499	 	
Total Available Baseload Capacity Sold Forward	 	 	81	%	 	 	80	%	 	 	78	%	 	 	64	%	 	 	26	%	 	 	80	%	 	 	66	%	
Weighted Average Forward Price ($ per MWh) (3)	 	$	44	 	 	$	39	 	 	$	41	 	 	$	48	 	 	$	52	 	 	$	42	 	 	$	45	 	
Total Revenues Sold Forward ($ in millions)	 	$	1,654	 	 	$	1,445	 	 	$	1,505	 	 	$	1,434	 	 	$	621	 	 	$	1,553	 	 	$	1,333	 	

(1) 	Net Baseload Capacity represents nominal summer net megawatt capacity of power generation adjusted for ownership, known upgrades and excluding capacity from mothballed units as of September 30, 2005. Capacity verification is based upon independent system operator, or ISO, required annual or semi-annual testing requirements.	
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(2) 	Includes amounts under fixed price firm and non-firm power sales contracts and amounts financially hedged under natural gas swap contracts. The forward natural gas swap quantities are reflected in equivalent MW and are derived by first dividing the quantity of MMBtu of natural gas hedged by the forward market heat rate (in MMBtu/ MWh, mid-point of the bid and offer as quoted by brokers in the market of the relevant Electric Reliability Council of Texas zones as of September 19, 2005) to arrive at the equivalent MWh hedged which is then divided by 8,760 to arrive at MW hedged.	
 	 	
(3) 	Includes amounts under fixed price power sales contracts and amounts financially hedged under natural gas swap contracts.	
     Northeast
      As of September 30, 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 L.L.C., 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 September 30, 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.
     South Central
      As of September 30, 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. As of September 30, 2005, 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. As of September 30, 2005, approximately 2,140 MW of NRG’s generation capacity in the region was sold forward pursuant to long-term contracts. 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 as of September 30, 2005.
     Western
      As of September 30, 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. As of September 30, 2005, 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. The transaction, which is subject to regulatory approval, is expected to close in the first quarter of 2006.
      We plan to continue the operations of the existing plants and also to redevelop our sites with new facilities when economic, market and regulatory conditions are favorable. However, in the alternative, we also believe we could recover our investment by selling or redeveloping the properties for other uses.
     Other
      As of September 30, 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 owned, as of September 30, 2005, interests in power plants having a generation capacity of approximately 1,916 MW in Australia, Germany and Brazil, and interests in coal mines in Australia and Germany.

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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. The combined company will perform its own power marketing, which is focused on maximizing value and managing volatility through asset-based power and fuel marketing and trading activities in the spot, intermediate and long-term markets. Our principal objectives are the realization of the full market value of our asset base, including the capture of our 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.
      As of September 30, 2005, the combined company, after giving effect to the Acquisition and Financing Transactions, had collateral (including cash, letters of credit and junior liens) posted to support commercial operations totaling $3.66 billion. The following table summarizes, as of September 30, 2005, the combined company collateral posted by credit rating.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Credit Rating	 	Letters of Credit(2)	 	 	Cash(2)	 	 	Junior Liens	 	 	Collateral Posted	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
A- and above	 	$	633,034,400	 	 	$	570,323,548	 	 	$	2,179,220,554	 	 	$	3,382,578,502	 	
BBB- through BBB+	 	$	167,349,108	 	 	$	54,210,141	 	 	$	1,739,911	 	 	$	223,299,160	 	
Below BBB-	 	$	7,771,000	 	 	$	3,895,000	 	 	$	0	 	 	$	11,666,000	 	
Not Rated(1)	 	$	38,201,000	 	 	$	2,968,992	 	 	$	0	 	 	$	41,196,992	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	846,355,508	 	 	$	631,397,681	 	 	$	2,180,960,464	 	 	$	3,658,713,654	 	

 	 	
(1) 	Not Rated indicates that no rating has been issued, or that an external rating agency (for example, Standard & Poor’s or Moody’s) does not rate a particular obligation as a matter of policy. The Not Rated row above consists of collateral posted to 17 counterparties, mainly gas producers.	
 	 	
(2) 	As of September 30, 2005 WCP had collateral posted of $24.6 million, which is excluded from the table above. Of this amount, letters of credit totaled $10.7 million and cash totaled $13.9 million.	
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. Coal hedging is dynamic based on forecasted generation and market volatility.
      We arrange for the purchase, transportation and delivery of coal for our baseload coal plants via a range of coal purchase agreements, rail transportation agreements and rail car lease arrangements. Coal consumption in 2006 for the combined company is expected to be approximately 36 million tons, which would rank it as one of the top five coal purchasers in the United States. In addition, as of September 30, 2005, approximately 92% of the combined company’s coal-fired generation would have benefited from multiple sourcing and transportation alternatives. As of September 30, 2005, on a pro forma basis, the combined company would have had approximately 6,000 privately leased or owned rail cars in its transportation fleet. In addition, we intend to enter into contracts for delivery of an additional 2,695 rail cars within the next two years of which approximately 1,410 will replace a portion of our existing rail car fleet. The combined company has entered into rail transportation agreements that provide for substantially all of its rail transportation requirements through 2009.

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      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. Texas Genco is 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:
 	 	 	 	 	
Process	 	Supplier(s)	 	Procurement Status	
 	 	 	 	 	
Yellow cake U 3 O 8 (30-40% of total fuel cost)
Conversion to uranium hexafluoride (UF  6  ) (3-5% of total fuel cost)	 	Contracts with Cameco (Canada) and Cogema/Arriba (France) combine these steps.	 	100% covered under favorable contracts through mid-2011 and then 25% covered through 2021.	
Enrichment of U235 content (35-45%)	 	Urenco (Germany), Cogema/Arriba (France), Louisiana Enrichment Services, or LES (1)  (joint venture between Westinghouse & Urenco).	 	Urenco and Cogema contracts cover through mid-2008. Balance of current license period under contract with Urenco/LES.	
Fabrication of fuel rods (15-20%)	 	Westinghouse.	 	Contract covers life of operating license.	

(1) 	Enrichment by LES assumes successful completion of LES licensing and construction of facility in New Mexico.	
Credit Support and Collateral Arrangements
      In order to secure performance under our power purchase agreements, fuel supply contracts and hedging agreements, we are required to provide credit support to our counterparties from time to time. This credit support consists of a combination of letters of credit, cash, guarantees and junior liens on our assets. For a detailed description of our collateral arrangements, see “Description of Certain Indebtedness” and “Liquidity and Capital Resources Discussion.”
Significant Customers
      For the nine months ended September 30, 2005, the combined company derived approximately 52% of its total revenues from majority-owned operations from four customers: NYISO accounted for 19%, a subsidiary of Reliant Energy, Inc. accounted for 17%, BP Energy Company accounted for 9% and ISO-NE accounted for 7%. The combined company accounts for the revenues attributable to these customers as part of its North America power generation segment.
      ISO-NE and NYISO are ISOs or RTOs and are FERC-regulated entities that administer day-ahead and real-time energy markets, capacity and ancillary service markets and manage transmission assets collectively under their respective control to provide non-discriminatory access to the transmission grid. We anticipate that NYISO and ISO-NE will continue to be significant customers given the scale of our asset base in these areas.
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.
      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 also improved the operational flexibility and financial performance of these plants. During the same time period, NRG will invest approximately $32 million in its coal plants in the South Central region for NOx burners and over fired air,

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which have led to reductions in NOx. A significant portion of this investment may be recovered from NRG’s cooperative customers. Texas Genco has spent over $700 million on NO x  reduction initiatives since 1999 to ensure both regulatory compliance and continued performance.
      The following table summarizes the key existing and planned environmental controls on our coal-fired units:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	SO2	 	 	NOx	 	 	Hg	 	 	Particulate	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Install	 	 	 	 	Install	 	 	 	 	Install	 	 	Control	 	 	Install	 	
Units	 	Control Equipment	 	 	Date	 	 	Control Equipment	 	 	Date	 	 	Control Equipment	 	 	Date	 	 	Equipment	 	 	Date	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Huntley 67	 	 	Wet FGD(1)	 	 	 	2013	 	 	 	SNCR	 	 	 	2010	 	 	 	FF-ACI(2)	 	 	 	2011	 	 	 	ESP	 	 	 	1973	 	
Huntley 68	 	 	Wet FGD(1)	 	 	 	2013	 	 	 	SNCR	 	 	 	2011	 	 	 	FF-ACI(2)	 	 	 	2009	 	 	 	ESP	 	 	 	1973	 	
Dunkirk 1	 	 	None	 	 	 	—	 	 	 	SNCR	 	 	 	2010	 	 	 	FF-ACI(2)	 	 	 	2010	 	 	 	ESP	 	 	 	1974	 	
Dunkirk 2	 	 	None	 	 	 	—	 	 	 	SNCR	 	 	 	2011	 	 	 	FF-ACI(2)	 	 	 	2011	 	 	 	ESP	 	 	 	1974	 	
Dunkirk 3	 	 	None	 	 	 	—	 	 	 	SNCR	 	 	 	2010	 	 	 	FF-ACI(2)	 	 	 	2011	 	 	 	ESP	 	 	 	1975	 	
Dunkirk 4	 	 	None	 	 	 	—	 	 	 	SNCR	 	 	 	2011	 	 	 	FF-ACI(2)	 	 	 	2010	 	 	 	ESP	 	 	 	1976	 	
Indian River 1	 	 	In-Duct Scrubber	 	 	 	2012	 	 	 	SNCR & LNB(3)	 	 	 	2008	 	 	 	Co-Benefit of Scrubbers	 	 	 	2012	 	 	 	ESP (IR1-3)	 	 	 	1976	 	
Indian River 2	 	 	In-Duct Scrubber	 	 	 	2013	 	 	 	SNCR & LNB(3)	 	 	 	2008	 	 	 	Co-Benefit of Scrubbers	 	 	 	2013	 	 	 	ESP (IR1-3)	 	 	 	1976	 	
Indian River 3	 	 	In-Duct Scrubber	 	 	 	2012	 	 	LNB(3) & SNCR upgrade	 	 	2008	 	 	 	Co-Benefit of Scrubbers	 	 	 	2012	 	 	 	ESP (IR1-3)	 	 	 	1980	 	
Indian River 4	 	 	Dry Scrubber	 	 	 	2011	 	 	LNB(3) & SNCR upgrade	 	 	2008	 	 	 	Co-Benefit of Scrubbers	 	 	 	2011	 	 	 	ESP (IR1-3)	 	 	 	1980	 	
Big Cajun 2 U1	 	 	Dry Scrubber	 	 	 	2011	 	 	 	None	 	 	 	 	 	 	 	ACI(2)	 	 	 	2012	 	 	 	ESP	 	 	 	1981	 	
Big Cajun 2 U2	 	 	Dry Scrubber	 	 	 	2010	 	 	 	SCR(4)	 	 	 	2010	 	 	 	ACI(2)	 	 	 	2011	 	 	 	ESP	 	 	 	1981	 	
Big Cajun 2 U3	 	 	Dry Scrubber	 	 	 	2013	 	 	 	SCR(4)	 	 	 	2013	 	 	 	ACI(2)	 	 	 	2014	 	 	 	ESP	 	 	 	1983	 	
Limestone	 	 	FGD	 	 	 	1986-87	 	 	 	LNB/OFA(3)	 	 	 	2000-01	 	 	 	Co-Benefit of Scrubbers	 	 	 	—	 	 	 	ESP	 	 	 	1986-87	 	
WA Parish U 5-7	 	 	None	 	 	 	NA	 	 	 	SCR & LNB/OFA(3)	 	 	 	2000-04	 	 	 	None	 	 	 	—	 	 	 	FF	 	 	 	1988	 	
WA Parish U 8	 	 	FGD	 	 	 	1982	 	 	 	SCR & LNB/OFA(3)	 	 	 	2000-04	 	 	 	Co-Benefit of Scrubber	 	 	 	—	 	 	 	FF	 	 	 	1988	 	

(1) 	FGD stands for Flue Gas Desulfurization	
(2) 	FF-ACI stands for Fabric Filter with Activated Carbon Injection	
(3) 	LNB/ OFA stands for Low NOx Burner with Over Fire Air	
(4) 	SCR stands for Selective Catalytic Reduction	
Performance Improvement and Cost and Process Control Initiatives
      In 2005, NRG introduced a comprehensive, company-wide cost and revenue enhancement program with the goal of increasing its return on invested capital, or ROIC. This effort has been branded as “ FOR NRG,” 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 plants and regional and headquarters operations including forced outage reductions and heat rate improvements at NRG’s major base load facilities.
      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. Discussions are already underway to compare best practices and results between NRG and Texas Genco, to manage suppliers with our combined volumes and to incorporate existing and future Texas Genco processes under the  FOR NRG program.
Regional Business Descriptions
      The combined company will be organized into business units as described below, with each of our core regions operating as a separate unit.

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 	TEXAS (ERCOT)	
      The combined company’s largest business unit will be located in the Texas (ERCOT) region of the United States and will be comprised of investments in generation facilities located in the physical control areas of the ERCOT-ISO.
 	 	
 	Operating Strategy	
      Texas Genco’s 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 will be four pronged: (1) to ensure the availability of the baseload plants to fulfill their commercial obligations given the long-term forward sales 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.
      Given our strategy of selling forward up to 80% of Texas Genco’s solid-fuel baseload capacity under long-term contracts, our primary focus will be to keep Texas Genco’s solid-fuel baseload units running. The performances at STP, W. A. Parish and Limestone have been above broader industry averages for the recent five-year period as shown below:
 	 	 	 	 	 	 	 	 	
 	 	Average 5-Year	 	 	 	
 	 	Availability	 	 	Benchmark Average	 	
 	 	Factor	 	 	Availability Factor	 	
 	 	 	 	 	 	 	
Limestone	 	 	89.4	 	 	 	85.4	 	
W. A. Parish	 	 	87.8	 	 	 	83.6	 	
South Texas Project	 	 	87.8	 	 	 	88.9	 	
      The operations and maintenance teams will continue to focus on maintaining and improving these levels.
      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, Texas Genco offers a range of products including “virtual units” where the customer has the right to dispatch Texas Genco’s 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.
      Lastly, we believe that we can have a positive impact on the evolution of the regulatory environment and market structure in Texas. We take our responsibility to the market and the state seriously and will be focused on working broadly with the full suite of stakeholders including other market participants, the PUCT, ERCOT, and the legislature to make Texas attractive for energy infrastructure investment in a way that ensures reliability and increases stability.

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 	Facilities	
      The following table describes Texas Genco’s electric power generation plants and generation capacity as of September 30, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generation	 	 	 	
 	 	 	 	 	 	Capacity	 	 	 	
Generation Sites	 	Location	 	 	% Owned	 	 	(MW)(1)	 	 	Primary Fuel Type(2)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Solid Fuel Baseload Units:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
W. A. Parish(3)	 	 	Thompsons, TX	 	 	 	100	%	 	 	2,463	 	 	Low Sulfur Coal Lignite/Low Sulfur	
Limestone	 	 	Jewett, TX	 	 	 	100	%	 	 	1,614	 	 	 	Coal	 	
South Texas Project(4)	 	 	Bay City, TX	 	 	 	44	%	 	 	1,101	 	 	 	Nuclear	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Solid Fuel Baseload	 	 	 	 	 	 	 	 	 	 	5,178	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Natural Gas-Fired Units:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cedar Bayou	 	 	Chambers County, TX	 	 	 	100	%	 	 	1,498	 	 	 	Natural Gas	 	
T. H. Wharton	 	 	Houston, TX	 	 	 	100	%	 	 	1,025	 	 	 	Natural Gas	 	
W. A. Parish (Natural gas) (3)	 	 	Thompsons, TX	 	 	 	100	%	 	 	1,191	 	 	 	Natural Gas	 	
S. R. Bertron	 	 	Deer Park, TX	 	 	 	100	%	 	 	844	 	 	 	Natural Gas	 	
Greens Bayou	 	 	Houston, TX	 	 	 	100	%	 	 	760	 	 	 	Natural Gas	 	
P.H. Robinson(5)	 	 	Bacliff, TX	 	 	 	100	%	 	 	461	 	 	 	Natural Gas	 	
San Jacinto	 	 	LaPorte, TX	 	 	 	100	%	 	 	162	 	 	 	Natural Gas	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Operating Natural Gas-Fired	 	 	 	 	 	 	 	 	 	 	5,941	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Texas (ERCOT) Region	 	 	 	 	 	 	 	 	 	 	11,119	 	 	 	 	 	

 	 	
(1) 	Actual capacity can vary depending on factors including weather conditions, operational conditions and other factors. ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time. Excludes 3,378 MW of inactive capacity available for redevelopment of which 174 MW of available capacity was sold on November 14, 2005. An additional 461 MW was moved to inactive status after September 30, 2005.	
 	 	
(2) 	Low sulfur coal is coal mined from the Powder River Basin, a coal-producing area in northeastern Wyoming and southeastern Montana, which coal has low sulfur content relative to most coal from the eastern United States.	
 	 	
(3) 	W. A. Parish has nine units, four of which are baseload coal-fired units and five of which are natural gas-fired units.	
 	 	
(4) 	Generation capacity figure consists of our 44.0% undivided interest in the two units of STP.	
 	 	
(5) 	P.H. Robinson Unit 2 was placed into inactive status on October 29, 2005.	
     W. A. Parish. Texas Genco’s 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 September 30, 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 has invested approximately $430.0 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 SO 2 , emissions. Plant uprate projects to be completed by year end 2007 are expected to uprate the net generation capacity of W.A. Parish by 31 MW.

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      Limestone. Texas Genco’s Limestone plant is a lignite and coal-fired plant located approximately 140 miles northwest of Houston. This plant includes two steam generation units with an aggregate generation capacity of 1,614 MW as of September 30, 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. Texas Genco owns the mining equipment and facilities and a portion of the lignite reserves located at the mine. Mining operations are conducted by Texas Westmoreland Coal Co., a single purpose, wholly-owned subsidiary of Westmoreland Coal Company and the owner of a substantial portion of the remaining lignite reserves. Both units have installed low-NOx burners to reduce NO x  emissions and scrubbers to reduce SO 2  emissions. We plan to upgrade Limestone Unit 2 in the second quarter of 2006 by replacing the high pressure and intermediate pressure turbines, rewinding the generator and replacing the main generator step-up transformer. These upgrades are expected to cost approximately $33.0 million and are expected to increase the 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 upgrade projects to be completed by 2007 are expected to uprate the net generation capacity of STP by 74 MW (33 MW net to Texas Genco). 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 Texas Genco and two other co-owners. Texas Genco 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. Except for certain plant shutdown and decommissioning costs and NRC licensing liabilities, Texas Genco is severally liable, but not jointly liable, for the expenses and liabilities of STP. CenterPoint Energy, Inc., the prior owner of Texas Genco’s assets, and the other three original co-owners organized the 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 Texas Genco owns 44% of STP, Texas Genco 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 will remain in effect after the closing of the Acquisition.
      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

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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 September 30, 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. Texas Genco’s coal and nuclear fuel baseload plants represented approximately 5,178 MW, or 26%, of the total solid fuel baseload net generation capacity in the ERCOT market in 2004. ERCOT has established a target equilibrium reserve margin level of approximately 12.5%. Reserve margins will decrease to the extent demand growth exceeds new supply. Overcapacity from new construction could cause some less efficient natural gas-fired units to be retired or mothballed. Overcapacity has little impact on the dispatch of Texas Genco’s solid fuel baseload plants given their lower marginal cost relative to natural gas-fired assets.
      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, Texas Genco’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. Texas Genco’s W. A. Parish plant and all its natural gas-fired plants are located in the Houston zone, Texas Genco’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

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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
      Because Texas Genco’s generation assets were formerly owned indirectly by a vertically integrated utility, PUCT regulation required firm entitlements to 15% of Texas Genco’s operating installed generation capacity to be sold at auction through December 31, 2006, at opening bid prices well below Texas Genco’s cost for 2006. On December 7, 2005, Texas Genco filed an application with the PUCT requesting the PUCT to determine that Texas Genco was 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. A decision on this matter is expected by February 2006. In the event the PUCT does not grant Texas Genco’s request, Texas Genco’s obligation to sell capacity at auction based on this below-cost pricing will continue through December 31, 2006.
     J. Aron Power Purchase Agreement
      Texas Genco entered into the J. Aron PPA with J. Aron. Under the J. Aron PPA, Texas Genco sold forward, on a fixed price basis, a substantial portion of its expected ERCOT generation capacity beginning January 1, 2005 through December 31, 2010. As a result of the J. Aron PPA and certain power sales and gas swap transactions, approximately 26% of Texas Genco’s net baseload generation capacity in Texas, and approximately 16% of the combined company’s total net baseload capacity, as measured in MWh through 2010, has been sold on a fixed price basis to J. Aron, making J. Aron one of the combined company’s largest customers on a going forward basis.
      The J. Aron PPA is a firm, liquidated damages contract. Texas Genco has the flexibility of meeting its obligations to deliver power to specified delivery points under the J. Aron PPA either through sales of power from its plants, or through purchases of power from the market. In addition, if either Limestone in the North zone, or STP in the South zone, has an outage or is derated, Texas Genco is permitted to deliver the power that it is otherwise obligated to deliver in these zones into the Houston zone in satisfaction of its obligations. All Texas Genco’s natural gas-fired plants are located in the Houston zone. Additionally, under the J. Aron PPA, Texas Genco does not assume any pricing risk associated with the ERCOT market switching to a nodal pricing market design.
      As collateral for Texas Genco’s obligations under the J. Aron PPA and certain power sales and gas swap transactions, Texas Genco agreed to post letters of credit and grant a second lien on Texas Genco’s assets in favor of J. Aron. For a detailed description of these credit support arrangements, see “Description of Certain Indebtedness.” The obligations of J. Aron under the J. Aron PPA and a subsequent natural gas swap are supported by an unlimited guarantee from J. Aron’s parent, The Goldman Sachs Group, Inc.
      In the event power prices decline in the future and J. Aron fails to perform under the J. Aron PPA, Texas Genco would have the right to terminate the J. Aron PPA and collect from J. Aron an amount equal to the difference between the contract price and the lower market price; however, Texas Genco’s ability to collect would be dependent on the amount of collateral then posted and the creditworthiness of J. Aron and Goldman at the time. Conversely, in the event power prices rise and Texas Genco fails to perform, J. Aron would have the right to terminate and collect an amount equal to the difference between the contract price and the higher market price. In the event J. Aron terminates, it would have the right to draw on certain letters of credit Texas Genco has posted as collateral. To the extent such letters of credit do not cover the amount of the termination payment, J. Aron retains a second lien on Texas Genco’s assets as collateral. J. Aron’s right to enforce its lien is limited to higher priority debt having taken such action.
      Six other trading counterparties have similar arrangements with Texas Genco related to hedging agreements through December 31, 2010 collateralized by letters of credit and a retained second lien on the Texas Genco’s assets. These additional six counterparties comprise approximately 22% of Texas Genco’s net baseload capacity in Texas, and approximately 13% of the combined company’s total net baseload capacity, as

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measured in MWh through December 31, 2010. NRG expects that, at the closing of the Acquisition and the Financing Transactions, the collateral arrangements described above, including with respect to certain counterparties holding junior liens on the ERCOT assets, will remain in place or will be replaced with substitute collateral arrangements comprising an interest in a second lien position on substantially all of NRG’s assets. On a going forward basis, NRG intends to secure some or all of its commodity hedging activities with interests in a second lien position on substantially all of NRG’s assets. There can be no assurance that this second lien position will provide enough capacity to cover all commodity hedges that are necessary or desirable for adequately hedging NRG’s commodity risk. See “Risk Factors— Risks Related to the Operation of our Business— We may not have sufficient liquidity to hedge market risks effectively.”
     Joint Operating Agreement with the City of San Antonio
      Texas Genco has a joint operating agreement with the City Public Service Board of San Antonio, or CPS, to jointly dispatch Texas Genco’s portfolio of generation units with CPS’s portfolio of over 5,300 MW of generation capacity as a joint operating system. This agreement with CPS expires in 2009 and can be terminated at any time by either party with 90 days notice. Texas Genco has delivered a notice of termination to CPS that would have terminated the agreement effective December 31, 2005. However, the parties have since agreed to a short term extension not expected to extend beyond January 2006.
 	 	
 	NORTHEAST REGION	
      The combined company’s second largest asset base will be located in the Northeast region of the United States and will be 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. In the Northeast, 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.
      We continue to pursue enhancement of coal assets through continued low sulfur coal conversions, improvements in coal handling and logistics process, and securing adequate coal supplies and transportation commitments. Longer term, we are also focused on working with regulators to gain support and required permits for low sulfur coal conversions.
      We continuously work to hedge our baseload portfolio and trade our oil and gas peaking facilities to maximize their value and minimize the risk of being fundamentally long on generation.
      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. As discussed further below (see “— Regulatory Developments— Northeast Region— RMR Agreements”), the RMR agreements are subject to approval by the FERC. In addition to the Connecticut RMR agreements, 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.

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      We continue to evaluate opportunities to redevelop our existing sites as well as opportunities for greenfield development and 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, 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. In addition to redeveloping existing sites, we also have greenfield sites in the Northeast that continue to be evaluated for power plant development opportunities. 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 September 30, 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 as of September 30, 2005 are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generation	 	 	 	
 	 	 	 	 	 	Capacity	 	 	 	
Plant	 	Location	 	 	% Owned	 	 	(MW)*	 	 	Primary Fuel Type	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Oswego	 	 	Oswego, NY	 	 	 	100.0	%	 	 	1,634	 	 	 	Oil	 	
Arthur Kill	 	 	Staten Island, NY	 	 	 	100.0	%	 	 	841	 	 	 	Natural Gas	 	
Middletown	 	 	Middletown, CT	 	 	 	100.0	%	 	 	770	 	 	 	Oil	 	
Indian River	 	 	Millsboro, DE	 	 	 	100.0	%	 	 	737	 	 	 	Coal	 	
Astoria Gas Turbines	 	 	Queens, NY	 	 	 	100.0	%	 	 	553	 	 	 	Natural Gas	 	
Dunkirk	 	 	Dunkirk, NY	 	 	 	100.0	%	 	 	522	 	 	 	Coal	 	
Huntley	 	 	Tonawanda, NY	 	 	 	100.0	%	 	 	552	 	 	 	Coal	 	
Montville	 	 	Uncasville, CT	 	 	 	100.0	%	 	 	497	 	 	 	Oil	 	
Norwalk Harbor	 	 	So. Norwalk, CT	 	 	 	100.0	%	 	 	342	 	 	 	Oil	 	
Devon	 	 	Milford, CT	 	 	 	100.0	%	 	 	124	 	 	 	Natural Gas	 	
Vienna	 	 	Vienna, MD	 	 	 	100.0	%	 	 	170	 	 	 	Oil	 	
Somerset Power	 	 	Somerset, MA	 	 	 	100.0	%	 	 	127	 	 	 	Coal	 	
Connecticut Remote	 	 	Various locations	 	 	 	 	 	 	 	 	 	 	 	 	 	
Turbines	 	 	in CT	 	 	 	100.0	%	 	 	104	 	 	 	Oil	 	
Conemaugh	 	 	New Florence, PA	 	 	 	3.7	%	 	 	64	 	 	 	Coal	 	
Keystone	 	 	Shelocta, PA	 	 	 	3.7	%	 	 	63	 	 	 	Coal	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Northeast Region	 	 	 	 	 	 	 	 	 	 	7,099	 	 	 	 	 	

 	 	
* 	Excludes 382 MW of inactive capacity.	
     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. Both Units 20 and 30 were converted from steam engines in the early 1990s. Unit GT-1 produces an aggregate generation capacity of 15 MW and is

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activated when ConEd issues a “max generation alarm” on hot days and during thunderstorms. 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, NRG’s Astoria Gas Turbine 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 net generation capacity of 144 MW each; Units 5, 7 and 8, which are Class 2 turbine engines that have a net generation capacity of approximately 14 MW each; and Units 10, 11, 12 and 13, which are Class 3 turbine engines that have a net generation capacity of 20 MW each. The ten units are further classified into six main substation feeds, that provide power to the local New York City load pockets. The Class 1 and Class 2 turbines were installed in 1970 and the Class 3 turbines in 1971. The facility contains retired units, including Units 6 and 9 in Class 2. Units 5 through 8 and units 10 through 13 are expected to retire in 2015, while Units 2 through 4 are expected to be retired in 2022.
      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 77 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.
      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 85 MW each and were put in service between 1942 and 1954. Units 63 and 64 are inactive and were effectively retired at the end of 2004, and NRG plans to give notice to the New York Public Service Commission of its intent to retire Units 65 and 66 in early 2006 reducing the capacity at this site to approximately 380 MW. 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 percent and 86 percent, respectively. A large portion of these reductions will be achieved by switching to low sulfur western coal and related projects for which NRG has already expended or committed significant capital.
     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. The 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 consists 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

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curve and locational capacity reforms (which are intended to better reflect locational values of capacity resources). ISO-NE and PJM are following with 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.
 	 	
 	SOUTH CENTRAL REGION	
      As of September 30, 2005, NRG owned approximately 2,395 MW of generating capacity in the South Central region of the United States, and had obligations to provide up to approximately 2,140 MW of capacity under long-term contracts with 11 rural cooperatives that have terms extending in some cases through 2025. The region lacks a regional transmission organization, or RTO/ ISO and, therefore, remains a bilateral market, making it less efficient than a region with an RTO/ 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 allow us 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.
      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 are also evaluating repowering opportunities for the Big Cajun I power stations and 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. 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 September 30, 2005 are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net Generating	 	 	 	
 	 	 	 	 	 	Capacity	 	 	Primary	 	
Plant	 	Location	 	 	% Owned	 	 	(MW)	 	 	Fuel Type	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Big Cajun II(1)	 	 	New Roads, LA	 	 	 	86.0	%	 	 	1,489	 	 	 	Coal	 	
Bayou Cove	 	 	Jennings, LA	 	 	 	100.0	%	 	 	300	 	 	 	Natural Gas	 	
Big Cajun I— (Peakers) Units 3 & 4	 	 	New Roads, LA	 	 	 	100.0	%	 	 	210	 	 	 	Natural Gas	 	
Big Cajun I— Units 1 & 2	 	 	New Roads, LA	 	 	 	100.0	%	 	 	220	 	 	 	Natural Gas/Oil	 	
Sterlington	 	 	Sterlington, LA	 	 	 	100.0	%	 	 	176	 	 	 	Natural Gas	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total South Central	 	 	 	 	 	 	 	 	 	 	2,395	 	 	 	 	 	

 	 	
(1) 	NRG owns 100% of Units 1 & 2; 58% of Unit 3	
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     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 September 30, 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 overfire air. The Unit 1 generator has recently been rewound and was optimized with a modern turbine/exciter control system. Units 2 and 3 are planned for generator rewinds, turbine/exciter control replacements and 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 Corporation, 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 September 30, 2005, NRG had long-term all-requirements contracts with 11 Louisiana distribution cooperatives. The agreements are standardized into three types, Form A, B and C and have the terms, contract loads and customers as shown in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Term	 	 	Contract Load	 	 	Customers	 	
 	 	 	 	 	 	 	 	 	 	
Form A	 	 	25 yrs.	 	 	 	42	%	 	 	6	 	
Form B	 	 	25 yrs.	 	 	 	3	%	 	 	1	 	
Form C	 	 	9-14 yrs.	 	 	 	42	%	 	 	4	 	
      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.
      In August and September 2005, Hurricanes Katrina and Rita roiled the South Central region’s power markets. Although NRG recognized an impairment loss of approximately $1.3 million for hurricane-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. 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.
 	 	
 	WESTERN REGION	
      As of September 30, 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%

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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 eventually realizing the valuable real estate on which they are located. There are four 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 taking active steps to assess the value of our property for non-power generation purposes. Two of West Coast Power’s plants are situated at choice locations on the Pacific coast. Fourth, 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.
      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. NRG’s strategy is to negotiate with Nevada Power and the steam host to restructure their agreements to provide suitable economic benefits. Alternatively, we expect that we will negotiate a sale of our share of that plant.
     Facilities
      In May 1999, Dynegy and NRG formed WCP Holdings to serve as the holding company for a portfolio of operating companies that own generation assets in the Southern California market operated by the California ISO, or Cal ISO. This portfolio currently consists of the El Segundo Generating Station, the retired Long Beach Plant Site, the Encina Generating Station and 13 combustion turbines distributed throughout the San Diego area. WCP is directed by an executive committee comprised of two voting members from each of NRG and Dynegy. Under the direction of this executive committee, Dynegy provides power marketing, fuel procurement and accounting services to WCP and NRG provides operations and management services. 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. The transaction, which is subject to regulatory approval, is expected to close in the first quarter of 2006.

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      NRG’s power generation assets in the Western region as of September 30, 2005 are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generation	 	 	 	
 	 	 	 	 	 	Capacity	 	 	 	
Plant	 	Location	 	 	% Owned	 	 	(MW)	 	 	Primary Fuel Type	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
WCP(1)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Encina	 	 	Carlsbad, CA	 	 	 	50.0	%	 	 	483	 	 	 	Natural Gas	 	
 	El Segundo	 	 	El Segundo, CA	 	 	 	50.0	%	 	 	335	 	 	 	Natural Gas	 	
 	Cabrillo II	 	 	San Diego, CA	 	 	 	50.0	%	 	 	86	 	 	 	Natural Gas	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total WCP	 	 	 	 	 	 	 	 	 	 	904	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Western Region Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Saguaro	 	 	Henderson, NV	 	 	 	50.0	%	 	 	46	 	 	 	Natural Gas	 	
 	Chowchilla	 	 	Northern CA	 	 	 	100.0	%	 	 	49	 	 	 	Natural Gas	 	
 	Red Bluff	 	 	Northern CA	 	 	 	100.0	%	 	 	45	 	 	 	Natural Gas	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	140	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Western Region	 	 	 	 	 	 	 	 	 	 	1,044	 	 	 	 	 	

 	 	
(1) 	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. The transaction, which is subject to regulatory approval, is expected to close in the first quarter of 2006.	
     The following are descriptions of our most significant revenue generating plants in the Western region:
      El Segundo. The El Segundo plant, of which NRG currently owns 50%, is located in El Segundo, California and produces aggregate generation capacity of 670 MW from two gas-fired intermediate load units (Units 3 and 4). These units, which have a generation capacity of 335 MW each, were installed in 1964 and 1965, respectively. The plant also contains two retired gas-fired intermediate load units that were installed in 1955 and 1956 (Units 1 and 2). These units, retired in 2002, were capable of producing 175 MW each. WCP is currently in the process of developing a 630 MW combined cycle plant on the property where the retired Units 1 and 2 reside. See “—Regulatory Developments— Regional Businesses— Market Developments— Western Region.”
      Encina. The Encina Station, of which NRG currently owns 50%, is located in Carlsbad, California and has a combined generating capacity of 965 MW from five fossil-fuel steam-electric generating units and one combustion turbine. The five fossil-fuel steam-electric units, which all primarily use natural gas (and oil for emergency backup only under a gas supply force majeure condition), provide intermediate load services. The combustion turbine only provides peaking services of 14 MW. Units 1, 2 and 3 each have a generation capacity of approximately 107 MW and were installed in 1954, 1956 and 1958, respectively. Units 4 and 5 have a generation capacity of approximately 300 MW and 330 MW respectively, and were installed in 1973 and 1978. The combustion turbine was installed in 1966. Units 1, 2 and 3 are projected to be retired after 2010. Low NO x  burner modifications and selective catalytic reduction equipment has been installed on Units 1, 2, 3, 4 and 5.
      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

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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. The potential improvement in earnings for 2006 is expected to be approximately $6 million over the projected budget, depending upon market conditions. In addition, El Segundo Units 3 and 4 have been contracted by a load serving entity for May 1, 2006 through April 30, 2008 for a capacity payment and tolling the purchaser’s natural gas. The Cal ISO has indicated that load growth needs by 2007 may require the re-designation of Encina Unit 4 in 2007.
     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. In January 2006, FERC approved an increase in the “soft cap” 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. See “Regulatory Developments— Regional Businesses— Market Developments— Western Region.”
 	 	
 	OTHER	
     Other North American Assets
      As of September 30, 2005, NRG owned approximately 1,470 MW of generating capacity in other regions of the United States. NRG’s other North American power generation assets are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generating	 	 	 	
 	 	 	 	 	 	Capacity	 	 	Primary Fuel	
Plant	 	Location	 	% Owned	 	 	MW	 	 	Type	
 	 	 	 	 	 	 	 	 	 	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	 	 	
 	Audrain*	 	Vandalia, MO	 	 	100.0	%	 	 	577	 	 	Natural Gas	
 	Rockford I (Peaker)	 	Rockford, IL	 	 	100.0	%	 	 	310	 	 	Natural Gas	
 	Rocky Road Partnership*	 	East Dundee, IL	 	 	50.0	%	 	 	165	 	 	Natural Gas	
 	Rockford II (Peaker)	 	Rockford, IL	 	 	100.0	%	 	 	160	 	 	Natural Gas	
 	Dover	 	Dover, DE	 	 	100.0	%	 	 	104	 	 	Natural Gas/Coal	
 	Power Smith Cogeneration	 	Oklahoma City, OK	 	 	6.25	%	 	 	7	 	 	Natural Gas	
 	Ilion Cogeneration*	 	New York	 	 	100.0	%	 	 	58	 	 	Natural Gas	
 	James River	 	Virginia	 	 	50.0	%	 	 	55	 	 	Coal	
 	Cadillac*	 	Cadillac, MI	 	 	50.0	%	 	 	19	 	 	Wood	
 	Paxton Creek	 	Harrisburg, PA	 	 	100.0	%	 	 	12	 	 	Natural Gas	
 	 	 	 	 	 	 	 	 	 	 	
Other North American Assets	 	 	 	 	 	 	 	 	1,467	 	 	 	

 	 	
* 	Certain of the above projects are in a state of transition. The Audrain project is under contract for sale. Closing is expected in 2006. NRG is in advanced discussions regarding the transfer of the Cadillac project. NRG is currently performing under an agreement whereby the Ilion project will be disconnected and terminated. On December 27, 2005, NRG entered into a purchase and sale agreement with Dynegy through which NRG will sell to Dynegy its 50% ownership interest in the jointly held entity that owns the Rocky Road power plant. The transaction is conditioned upon NRG’s acquisition of Dynegy’s 50% interest in WCP Holdings and subject to regulatory approval, and is expected to close in the first quarter of 2006. See “Summary— Recent Developments.”	
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     Australia and All Other Generation and Non-Generation Assets
      As of September 30, 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 September 30, 2005 are summarized in the table below:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Net	 	 	 	
 	 	 	 	 	 	Generating	 	 	 	
 	 	 	 	 	 	Capacity	 	 	Primary Fuel	 	
Plant	 	Location	 	 	% Owned	 	 	MW	 	 	Type	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Flinders	 	 	Australia	 	 	 	100.0	%	 	 	700	 	 	 	Coal	 	
Gladstone	 	 	Australia	 	 	 	37.5	%	 	 	605	 	 	 	Coal	 	
Schkopau	 	 	Germany	 	 	 	41.9	%	 	 	400	 	 	 	Coal	 	
MIBRAG(1)	 	 	Germany	 	 	 	50.0	%	 	 	55	 	 	 	Coal	 	
Itiquira	 	 	Brazil	 	 	 	98.7	%	 	 	156	 	 	 	Hydro	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total International Assets	 	 	 	 	 	 	 	 	 	 	1,916	 	 	 	 	 	

 	 	
(1) 	Primarily a coal mining facility. Approximately 90% of MIBRAG’s revenues represent coal sales and 8% represent electricity sales. MIBRAG owns 110 MW of net exportable generation. Approximately two-thirds of that amount is sold to third parties and one-third is used to power mining and other MIBRAG operations. NRG equity in net exportable electricity is 55 MW.	

 	Australia	

 	Asset Management Strategy	
      Our strategy for maximizing our return on investment in our assets concentrates on effective contract management, operating the plant to ensure safe, efficient and sustainable operations and management of the equity investment, including cash flow and finances. NRG is currently considering strategic alternatives with respect to Australia either to reposition its assets more effectively within the National Electricity Market or to monetize its investment. NRG will seek to determine the best option, which may include a joint venture, equity spin-off, asset swap for U.S. generation assets or trade sale over the next few months.
      NRG Flinders Assets. NRG Flinders is a merchant generation business that derives revenue from bidding its generation output into the South Australian region of the National Electricity Market, or NEM, by trading the plant as a portfolio, selling derivative hedges that are not plant specific and supplying minor retail sales via contract. The bidding of the plant as a portfolio supports strategies for maximizing revenue of the entire portfolio both in terms of pool and derivative revenues and the most economic fuel use. 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% to 80% of the plant output. The current book is underpinned by a medium term hedge with a major South Australian retailer.
      The Gladstone Assets. The Gladstone assets are owned in partnership with other investors and NRG does not have unilateral control over management of the assets. Gladstone Power Station is fully contracted via a power purchase agreement and a capacity purchase agreement with Boyne Smelter Limited and Enertrade through 2029. Enertrade is a state owned company that trades the excess power in the NEM.
 	 	
 	Germany	

 	Asset Management Strategy	
      Our German assets are owned in partnership with other investors and NRG does not have direct control over operations. Our strategy for maximization of return on investment therefore concentrates on the following: contract management, monitoring of our facility operators to ensure safe, profitable and sustainable

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operations; management of cash flow and finances; and growth of our businesses through investments in projects related to our current businesses.
 	 	
 	Thermal and Chilled Water Businesses	
      NRG Thermal’s thermal and chilled water businesses have a steam and chilled water capacity of approximately 1,225 megawatt thermal equivalents, or MWt.
      As of September 30, 2005, NRG Thermal owned heating and cooling systems that provide steam heating to approximately 555 customers and chilled water to 95 customers in five different cities in the United States. In addition, as of that date, NRG Thermal owned and operated three projects that serve industrial/government customers with high-pressure steam and hot water, an 88 MW combustion turbine peaking generation facility and an 16 MW coal-fired cogeneration facility in Dover, Delaware and a 12 MW gas-fired project in Harrisburg, Pennsylvania. Approximately 34% of Thermal’s revenues are derived from its district heating and chilled water business in Minneapolis, Minnesota.
 	 	
 	Resource Recovery Facilities	
      NRG’s Resource Recovery business owns and operates fuel processing projects. The alternative fuel currently processed is municipal solid waste, approximately 85% of which is processed into refuse derived fuel, or RDF. NRG’s Resource Recovery business has municipal solid waste processing capacity of 3,000 tons per day. NRG’s Resource Recovery business owns and operates NRG Processing Solutions, which includes 14 composting and processing sites in Minnesota, of which five sites are permitted to operate as municipal solid waste transfer stations.
Competition
      Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete on the basis of the location of our plants and owning multiple plants in our regions, which increases the stability and reliability of our energy supply. Wholesale power generation is fundamentally a local business which, at present, is 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 we compete against from market to market.
Employees
      As of September 30, 2005, the combined company would have had 3,740 employees, approximately 1,751 of whom were covered by U.S. bargaining agreements. During 2005, neither NRG nor Texas Genco experienced any significant labor stoppages or labor disputes at their facilities.
Energy Regulatory Matters
      As operators of power plants and participants in wholesale energy markets, we are subject to regulation by various federal and state government agencies. These include the FERC, the NRC, PUCT and certain other state public utility commissions in which our generating assets are located. In addition, we are also subject to the market rules, procedures and protocols of the various ISO and RTO markets in which we participate.
      The plant operations of, and wholesale electric sales from, Texas Genco are not currently subject to regulation by FERC, as they are deemed to operate solely within the ERCOT and not in interstate commerce. As discussed below, Texas Genco’s operations are subject to regulations by PUCT as well as to regulation by the NRC with respect to its ownership interest in the STP.
 	 	
 	Federal Energy Regulatory Commission	
      FERC, among other things, regulates the transmission and wholesale sale of electricity in interstate commerce under the authority of the Federal Power Act, or FPA. In addition, under existing regulations, FERC determines whether a generation facility qualifies for Exempt Wholesale Generator, or EWG, status

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under the Public Utility Holding Company Act of 1935, or PUHCA of 1935. FERC also determines whether a generation facility meets the ownership and technical criteria of a Qualifying Facility, or QF, under Public Utility Regulatory Policies Act of 1978, or PURPA. Each of NRG’s U.S. generating facilities has either been determined by FERC to qualify as a QF, or the subsidiary owning the facility has been determined to be an EWG. This permits NRG to own and operate these electric generating facilities without becoming subject to regulation as a holding company under PUHCA of 1935, and in the case of NRG’s QFs, to make wholesale sales of electricity to electric utilities at the utility’s avoided cost that are not subject to regulation by FERC. FERC’s regulation of NRG under each of these statutes will be changed by the recent passage of the Energy Policy Act of 2005, or EPAct 2005.
      The Energy Policy Act of 2005. EPAct 2005 was enacted into law on August 8, 2005. Among other things, EPAct 2005 repealed PUHCA of 1935, amended PURPA to remove statutory restrictions on utility ownership of a QF and to remove a utility’s obligation to buy from a QF, provided certain market and transmission access conditions exist, and enacted the Public Utility Holding Company Act of 2005, or PUHCA of 2005. EPAct 2005’s PUHCA changes take effect February 8, 2006. EPAct 2005’s amendments to PURPA were effective as of August 8, 2005. Though generally supported by the industry and viewed as a positive development, EPAct 2005 remains subject to FERC interpretation, and FERC has issued several rulemakings and rules to implement EPAct, some of which are still ongoing. NRG is currently assessing the effect of EPAct 2005 and these rulemakings issued by FERC to implement it on the combined company’s regulatory environment and business.
      Federal Power Act. The FPA gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of electricity in interstate commerce. Under the FPA, FERC, with certain exceptions, regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as public utilities. The FPA also gives FERC jurisdiction to review certain transactions and numerous other activities of public utilities. With exceptions for certain small power production facilities (non-geothermal facilities greater than 30 MWs), QFs are currently exempt from the FERC’s FPA rate regulation to the extent that sales made from them are made pursuant to the exemptions established under PURPA and are not made under a market-based or cost-based rate authorization from FERC. Currently, all of NRG’s QF power sales are made pursuant to the PURPA established exemption or pursuant to FERC market-based rate authorization.
      Public utilities under the FPA are required to obtain FERC’s acceptance, pursuant to Section 205 of the FPA, of their rate schedules for wholesale sales of electricity. All of NRG’s non-QF generating companies, small power production QFs greater than 30 MWs and power marketing affiliates in the United States make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. FERC has granted each of these companies the authority to sell electricity at market-based rates. The FERC’s orders that grant NRG’s generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. In addition, our market-based sales are subject to certain market behavior rules and, if any of our generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. As a condition to the orders granting us market-based rate authority, every three years NRG is required to file a market update to show that it continues to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. NRG is also required to report to FERC any material changes in status that would reflect a departure from the characteristics that FERC relied upon when granting NRG’s various generating and power marketing companies’ market-based rates. On October 28, 2005, NRG filed such a notice of change in status regarding the Texas Genco acquisition. No party has filed any comments in response to this change in status filing.
      If NRG’s generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and would become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

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      In addition, Section 204 of the FPA gives FERC jurisdiction over a public utility’s issuance of securities or assumption of liabilities. However, FERC typically grants blanket approval for future securities issuances or assumptions of liabilities to entities with market-based rate authority. In the event that one of NRG’s public utility generating companies were to lose its market-based rate authority, such company’s future securities issuances or assumptions of liabilities could require prior approval of the FERC.
      Section 203 of the FPA also requires FERC’s prior approval for the transfer of control over assets subject to FERC’s jurisdiction. EPAct 2005 amended this prior approval authority in a number of ways. In particular, as proposed to be implemented by FERC, certain companies proposing to acquire foreign utilities or foreign operating companies would be required to obtain prior FERC approval. This proposed implementation, if unchanged, could impede NRG’s future acquisition of foreign assets. Also, depending on how the new law is interpreted, certain mergers or acquisitions involving holding companies owning generation assets only in Texas, which were formally exempt from FERC review under Section 203 of the FPA, may now be subject to such review under the EPAct 2005 amendments to the law. The provisions of EPAct 2005 relating to prior approval of asset acquisitions under the FPA become effective February 8, 2006.
      PUHCA. As discussed above, EPAct 2005 repeals PUHCA of 1935, effective February 8, 2006, and replaces it with PUHCA of 2005.
      PUHCA of 1935, among other things, provides for extensive regulation by the Securities and Exchange Commission, or SEC, of non-exempt public utility holding companies, limits their utility operations to a single, integrated utility system and requires divestiture of operations not functionally related to the operation of the utility system. PUHCA of 1935 applies to foreign utility operations unless such operations qualify as a Foreign Utility Company, or FUCO or EWG, as defined under the act.
      PUHCA of 2005 retains certain definitions from PUHCA of 1935 (such as the definitions of EWG and FUCO) and provides FERC with certain authority over and access to books and records of public utility holding companies not otherwise exempt by virtue of their ownership of EWGs, QFs or FUCOs. Because all of Texas Genco’s and NRG’s generating facilities have QF status or are owned through EWGs or FUCOs, neither company currently qualifies as a “holding company” under PUHCA of 1935 or PUHCA of 2005.
      Public Utility Regulatory Policies Act. PURPA was initially passed in 1978 in large part to promote increased energy efficiency and development of independent power producers. PURPA created QFs to further both goals, and FERC is primarily charged with administering PURPA as it applies to QFs. As discussed above, under current law, some categories of QFs may be exempt from regulation under the FPA as public utilities. PURPA incentives also initially included a requirement that utilities must buy and sell power to QFs.
      As noted above, EPAct 2005 has amended several provisions of PURPA. Among other things, EPAct of 2005 provides for the termination of the obligation to purchase power from QFs at an avoided cost rate under certain conditions. However, the purchase obligation is only terminated if FERC first finds that a QF has non-discriminatory access to wholesale energy markets having certain characteristics (including nondiscriminatory transmission and interconnection services provided by a regional transmission entity in certain circumstances). Certain of NRG’s QFs currently interconnect into markets that may meet the qualifications for elimination of the PURPA purchase requirement. If the obligation of the local utility to purchase from some or all of NRG’s QFs is terminated, NRG will need to find alternative purchasers for the output of these QFs once their current contracts expire. Such alternative purchases will be at prevailing market rates, which may not be as favorable as the terms of our PURPA sales arrangements under existing contracts. In addition, under proposed FERC rules implementing EPAct of 2005, QFs not making sales pursuant to state-approved avoided cost rates will become subject to FERC’s ratemaking authority under the FPA and be required to obtain market rate authority in order to be allowed to sell power at market-based rates.
 	 	
 	Nuclear Regulatory Commission	
      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, Texas Genco, LP is an NRC licensee and is subject to NRC regulation. Texas

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Genco, LP’s NRC license gives it the right only to possess an interest in STP but not to operate it. Operating authority under the NRC operating license for STP is held by STPNOC. Texas Genco, LP owns a related interest in 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 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 Texas Genco, LP primarily focuses on its ability to meet its financial and decommissioning funding assurance obligations. In connection with the acquisition by Texas Genco of a 30.8% interest in STP from CenterPoint Energy, the NRC required Texas Genco to enter into a support agreement with Texas Genco, LP to provide up to $120 million to Texas Genco, LP if necessary to support operations at STP. Texas Genco entered into that support agreement on April 13, 2005. The support agreement will remain in effect after closing of the Acquisition.
      Decommissioning Trusts. Upon expiration of the operating terms of the operation licenses for the two generating units at STP (currently scheduled for 2027 and 2028), the co-owners of STP are required under federal law to decontaminate and decommission STP. In May 2004, an outside consultant estimated a 44.0% share of the STP decommissioning costs to be approximately $650 million in 2004 dollars.
      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 periodic payments to the trust, plus allowable earnings, will equal the estimated decommissioning obligations needed by the time decommissioning is expected to begin. Currently, Texas Genco, LP’s funding against its decommissioning obligation is contained within two separate trusts. PUCT regulations provide for the periodic funding of Texas Genco’s decommissioning obligations through non-bypassable charges collected by CenterPoint Energy Houston Electric, LLC and AEP Texas Central Company, or CenterPoint Houston and AEP TCC, from their customers.
      In the event that the funds from the trusts are ultimately determined to be inadequate to decommission the STP facilities, the original owners of Texas Genco’s STP interests, CenterPoint Houston and AEP TCC, each will be required to collect, through their PUCT-authorized non-bypassable charges to customers, additional amounts required to fund the decommissioning obligations relating to Texas Genco’s 44.0% share, provided that Texas Genco has complied with the PUCT’s rules and regulations regarding decommissioning trusts. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective rate payers of CenterPoint Houston or AEP TCC (or their successors).
 	 	
 	Public Utility Commission of Texas	
      Texas Genco’s subsidiaries are registered as power generation companies with PUCT. PUCT also has jurisdiction over power generation companies with regard to the administration of nuclear decommissioning trusts, PUCT state-mandated capacity auctions and the implementation of measures to mitigate undue market power that a power generation company may have and to remedy market power abuses in the ERCOT market and, indirectly, through oversight of ERCOT.
Regulatory Developments
      In New England, New York, the Mid-Atlantic region, the Midwest and California, FERC has approved independent system operators, or regional transmission organizations, or ISOs or RTOs. Most of these ISOs or RTOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by FERC and associated ISO/ RTO market rules. These tariffs/market rules dictate how the day ahead and real-time markets operate, how market participants may make bilateral sales to one another, and how entities with market-based rates shall be compensated within those markets. The ISOs or RTOs in these regions also control access to and the operation of the transmission grid within their regions. In Texas, pursuant to a 1999

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restructuring statute, the PUCT has granted similar responsibilities to ERCOT. Except for sales within ERCOT and by certain of NRG’s QFs under PURPA, all of NRG’s sales, whether made into an ISO- or RTO-administered market or bilaterally negotiated, are made pursuant to market-based rate authorizations granted by FERC to our FPA public utility subsidiaries. Access to, pricing for and operation of the transmission grid in regions not controlled by such ISOs or RTOs is controlled by the local transmission owning utility according to its Open Access Transmission Tariff approved by FERC.
      Both Texas Genco and NRG are affected by rule/tariff changes that occur in the existing ISOs and RTOs. The ISOs and RTOs that oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms (in particular, market power mitigation rules) to address some of the volatility in these markets. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell energy into the wholesale power markets. In addition, the regulatory and legislative changes that have recently been enacted in a number of states in an effort to promote competition are novel and untested in many respects. These new approaches to the sale of electric power have very short operating histories, and it is not yet clear how they will operate in times of market stress or pressure given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price limitations by independent system operators.
     Regional Businesses— Market Developments
 	 	
 	Texas (ERCOT) Region	

 	Texas Nodal Protocols	
      At the direction of the PUCT, the ERCOT stakeholder process has developed the “Texas Nodal Protocols” that sets forth a complete and detailed revised wholesale market design based on locational marginal pricing (in place of the current ERCOT zonal market today). The stakeholder process took two years to complete and incorporates a variety of unique characteristics for a nodal market as the result of accommodations reached by parties in the stakeholder process. Major elements include bilateral energy and ancillary schedules, day-ahead energy market, resource specific energy and ancillary service bid curves, direct assignment of all congestion rents, nodal energy prices for generators, aggregation of nodal to zonal energy prices for loads, congestion revenue rights (including pre-assignment for public power entities), and pricing safeguards. The PUCT will consider approval of the Texas Nodal Protocols by early 2006 and has indicated January 1, 2009, as the date for full implementation of the new market design. Under the expedited schedule, the evidentiary hearing concluded December 13, 2005, and briefing by parties will conclude January 27, 2006.
 	 	
 	Northeast Region	

 	RMR Agreements	
      During 2005, NRG’s Devon, Middleton and Montville stations operated under RMR agreements with ISO-NE. With these RMR agreements set to expire at the end of 2005, on November 1, 2005, NRG filed new RMR agreements with FERC in order provide for the continued provision of reliability services from these resources. Following the filing of interventions and protests challenging the proposed rates and provisions of the filed RMR agreements, NRG entered into a settlement agreement with the Connecticut Department of Public Utility Control, the Connecticut Office of Consumer Counsel, and ISO-NE. This settlement agreement was filed as an Offer of Settlement, or Settlement, with FERC on December 20, 2005, in Docket No. ER06-118-000. NRG is not aware of any opposition to the Settlement and has requested FERC approve the settlement by January 31, 2006.
      Under the settlement, NRG is entitled to annual fixed revenue requirement of $98 million, allocated among the stations, subject to NRG meeting the availability requirements specified therein. In addition, NRG is also entitled to retain 35% of its market revenues from the subject stations, while crediting 65% of such revenues against the monthly availability payments under the RMR agreements. The settlement will allow NRG to maintain uninterrupted RMR service from its stations, without the regulatory litigation that

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Connecticut entities are pursuing against other RMR applicants. The settlement specifies a January 1, 2006 effective date and the parties have requested expedited approval of the settlement RMR agreements without modification. Pending FERC’s determination on the settlement, the ISO-NE has agreed to implement the settlement RMR agreements effective January 1, 2006. As part of the settlement, NRG and ISO-NE agreed on appropriate revisions to some of the operating characteristics, bid costs and operating characteristics, and with those changes, all of ISO-NE’s concerns with the November 1, 2005 filing have been resolved.
      The new RMR agreements will be in effect until LICAP is fully implemented or as FERC may otherwise determine if it approves a transition program for LICAP. In addition, the settlement RMR agreements contain some new termination provisions. For example, the Devon RMR agreement will terminate ninety days after the commencement of Locational Forward Reserve Market, but no earlier than January 1, 2007. In certain circumstances, after January 1, 2007, the Connecticut entities will be allowed to seek termination by filing a Section 206 complaint at FERC.
 	 	
 	LICAP Market Developments	
      On August 31, 2004, ISO-NE filed its proposal for LICAP with the FERC, which is deciding the issue in a litigated proceeding before an administrative law judge. Under the proposal, separate capacity markets would be created for distinct areas of New England, including southwest Connecticut, where several of NRG’s Connecticut plants are located, and the rest of the state of Connecticut. While NRG views this proposal as a positive development, as it is currently proposed it would not permit NRG to recover all of its fixed costs. In response, NRG has submitted testimony that includes an alternative proposal. On June 15, 2005, the FERC administrative law judge issued her recommended decision, which recommended FERC approve ISO-NE’s proposed LICAP design with few exceptions. On July 15, 2005, NRG and the other parties to the case filed briefs on exceptions to the decision with FERC. On August 10, 2005, FERC issued an order delaying the implementation of a LICAP market from January 1, 2006 until October 1, 2006, at the earliest, and conducted oral argument on September 20, 2005. On October 7, 2005, participants in NEPOOL filed a joint motion with the FERC for the expedited appointment of a settlement judge and the commencement of settlement negotiations regarding the establishment of a LICAP market. On October 12, 2005, in response to a motion filed by ISO-NE for clarification of the FERC’s order of August 10, 2005 delaying implementation of the LICAP market, the FERC delayed the implementation of a separate energy zone for southwest Connecticut.
 	 	
 	Connecticut	
      On September 12, 2005, Richard Blumenthal, Attorney General for the state of Connecticut, the Connecticut Office of Consumer Counsel, the Connecticut Municipal Electric Energy Cooperative and the Connecticut Industrial Energy Consumers filed a complaint against ISO-NE pursuant to sections 206 and 212 of the Federal Power Act, seeking to amend the ISO-NE’s Market Rule 1 to require all electric generation facilities not currently operating under an RMR agreement in Connecticut to be placed under cost-of-service rates. On October 20, 2005, NRG, among others, filed an answer requesting that the Commission dismiss the complaint. NRG’s Jet Power and Norwalk facilities are not currently operating under an RMR agreement.
 	 	
 	New York	
      NRG’s New York City generation is presently subject to price mitigation in the installed capacity market. When the capacity market is tight, the price NRG receives is capped by the mitigation price. However when the New York City capacity market is not tight, such as during the winter season, the proposed demand curve price levels should increase revenues from capacity sales over revenues obtained in previous capacity markets. On January 7, 2005, NYISO filed proposed installed capacity, or ICAP, demand curves for the following capacity years: 2005-06, 2006-07 and 2007-08. Under the NYISO proposal, the ICAP price for New York City generation would be $126 per KW-year for the capacity year 2006-07. On April 21, 2005, FERC accepted the NYISO’s proposed demand curves, with certain minor revisions. The existing in-city mitigation measures, however, will continue to apply to us when the capacity market is tight, preventing us from obtaining these higher prices.

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      On October 6, 2005, Niagara Mohawk Power Corporation, or NiMo, filed a complaint against NYISO and the New York State Reliability Council, or NYSRC, requesting that the FERC direct the NYSRC to modify its methodology for calculating the statewide installed reserve margin. NiMo’s complaint also alleges that the NYISO incorrectly calculates the installed capacity requirement.
 	 	
 	Mid Atlantic	
      On January 25, 2005, FERC issued an order approving the PJM Interconnection, L.L.C., or PJM, proposal to increase the compensation for generators that are located in load pockets and are mitigated at least 80% of their running time. Specifically, when a generator would be subject to mitigation, the generator would have the option of recovering its variable cost plus $40 or a negotiated rate with PJM based on the facility’s going forward costs. If the generator declines both options, it could file for an alternative rate with FERC. FERC also substantially revised the exemption of facilities built after 1996 from the energy price capping mitigation rule. Several of NRG’s facilities are presently mitigated 80% of the time and, therefore, are impacted by the change and may benefit from the increased compensation provided for such generators.
      On August 31, 2005, PJM filed a proposed reliability pricing model, or RPM, that, if accepted by FERC, would modify the capacity obligations imposed on load, and related market mechanisms within PJM. The primary features of the RPM proposal are the establishment of locational capacity markets using a downward-sloping demand curve similar to the demand curve model adopted in New York; a four-year-forward commitment of capacity resources; establishing separate obligations and auction procurement mechanisms for quick start and load following resources; allowing certain planned resources, transmission upgrades and demand resources to compete with existing generation resources to satisfy capacity requirements; and market power mitigation rules (which are primarily applied to existing generation resources, such as NRG’s). On October 19, 2005, NRG filed an intervention and protest in response to the PJM RPM proposal. On December 8, 2005, FERC issued a notice establishing a technical conference on the issues raised by PJM’s RPM filing. The outcome of this proceeding is not possible to predict with certainty, nor is the timing of any implementation of PJM’s proposed RPM model.
 	 	
 	South Central Region	
      On January 3, 2005, Entergy submitted a petition for declaratory order requesting guidance on issues associated with its proposal to establish an independent coordinator of transmission, or ICT. Entergy requested FERC’s guidance on whether the functions to be performed by the ICT will cause it to become a public utility under the Federal Power Act or the transmission provider under Entergy’s Open Access Transmission Tariff, or OATT, and whether Entergy’s transmission pricing proposal satisfies FERC’s transmission pricing policy. On May 23, 2005, FERC issued an order granting rehearing for further consideration but has not yet acted on rehearing.
      On March 22, 2005, FERC granted Entergy’s Petition for declaratory order, stating that the implementation of the ICT proposal on an experimental basis will permit a transmission decision-making process that is independent of control by any market participant or class of participants. On May 27, 2005, Entergy submitted a Section 205 filing detailing the enhanced functions that the ICT will perform. Numerous interventions and protests were filed in response, a technical conference has been held and the proceeding is ongoing.
 	 	
 	Western Region	
      NRG has negotiated RMR agreements with the Cal ISO for one-year terms for all of the WCP capacity. NRG has filed these RMR agreements with FERC, with an effective date of January 1, 2006, for each of our Encina and Cabrillo II plants. Cal ISO did not designate the El Segundo plant as an RMR for 2006. A tolling agreement for the total capacity of the El Segundo plant has been executed with a major load serving entity for the period May 2006 through April 2008.
      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

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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 $1.0 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. 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.

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Environmental Matters
      NRG and Texas Genco are subject to a broad range of environmental and safety laws and 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 or during operation of power plants. Environmental laws have become increasingly stringent over time, particularly the regulation of air emissions from power generators. Such laws generally require regular capital expenditures for power plant upgrades, modifications and the installation of certain pollution control equipment. It is not possible at this time to determine when or to what extent additional facilities, or modifications to existing or planned NRG or Texas Genco facilities, will be required due to potential changes to environmental and safety laws and regulations, regulatory interpretations or enforcement policies. In general, future laws and regulations are expected to require the addition of emissions control or other environmental quality equipment or the imposition of certain restrictions on the operations of the combined company. We expect that future liability under, or compliance with, environmental requirements could have a material effect on our operations or competitive position.
 	 	
 	U.S. Federal Environmental Initiatives	

 	Air	
      On May 18, 2005, the US Environmental Protection Authority, or USEPA, published the Clean Air Mercury Rule, or CAMR, to permanently cap and reduce mercury emissions from coal-fired power plants. CAMR imposes limits on mercury emissions from new and existing coal-fired plants and creates a market-based cap-and-trade program that will reduce nationwide utility emissions of mercury in two phases (2010 and 2018). Consistent with the significant debate on whether the USEPA has authority to regulate mercury emissions through a cap-and-trade mechanism (as opposed to a command-and-control requirement to install “maximum achievable control technology”, or MACT, on a unit basis), 14 states, together with five environmental organizations, have filed petitions for reconsideration of CAMR. The states (including California, Connecticut, Delaware, Illinois, Maine, Massachusetts, New Hampshire, New Jersey, New Mexico, New York, Pennsylvania, Rhode Island, Vermont and Wisconsin) allege that the rule violates the Clean Air Act, or CAA, because it fails to treat mercury as a hazardous air pollutant. On August 4, 2005, the U.S. Court of Appeals for the District of Columbia Circuit denied the environmental petitioners’ request for a stay of CAMR. On October 28, 2005, the USEPA published notices of reconsideration of seven specific aspects of CAMR (including state allocations). Each of our coal-fired electric power plants will be subject to mercury regulation. However, since the rule has yet to be implemented by individual states and given the USEPA’s pending reconsideration of the rule, it is difficult to assess with certainty how CAMR will affect our operations. Nevertheless, we continue to actively review emerging mercury monitoring and mitigation strategies and technologies to identify the most cost-effective options for NRG in implementing required mercury emission controls on the stipulated schedule.
      On May 12, 2005, the USEPA published the Clean Air Interstate Rule, or CAIR. This rule applies to 28 Eastern States and the District of Columbia and caps SO2 and NO x  emissions from power plants in two phases (2010 and 2015 for SO2 and 2009 and 2015 for NO x ). CAIR will apply to certain of the combined company’s power plants in New York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois, Pennsylvania, Maryland and Texas. States must achieve the required emission reductions through: (a) requiring power plants to participate in a USEPA-administered interstate cap-and-trade system; or (b) measures to be selected by individual states. On August 24, 2005, the USEPA published a proposed Federal Implementation Plan, or FIP, to ensure that generators affected by CAIR reduce emissions on schedule. In addition, on December 20, 2005, the USEPA signed proposed revisions to the National Ambient Air Quality Standards (“NAAQS”) for fine particulates (PM2.5) and inhalable coarse particulates (PM10-PM2.5), that would require affected states to implement further rules to address SO 2  and NO x  emissions (as precursors of fine particulates in the atmosphere). Further, on November 22, 2005, the USEPA granted requests to reconsider four specific aspects of CAIR (including the inclusion of certain states) with final action or reconsideration expected by March 15, 2006. While our current business plans include initiatives to address emissions (for example, the conversion of Huntley and Dunkirk to burn low sulfur coal), until the final CAIR rule and

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NAAQS for PM2.5, PM10-2.5 and ozone are actually implemented by specific state legislation, it is not possible to identify with greater specificity the effect of CAIR on us. As noted below, certain states in which we operate have already announced plans to implement emissions reductions that go beyond the CAIR requirements. It is possible that investments in additional backend control technologies will be required and we continue to evaluate these issues.
      Although we recognize the uncertainties regarding how CAMR and CAIR will be implemented, we expect to incur a substantial increase in our environmental capital expenditures between 2009 and 2012 in order to ensure compliance with CAMR and CAIR. We have currently estimated expenditures of around $540 million for CAMR and CAIR compliance during this period for the NRG facilities, most of which would be incurred at our various coal-fired plants in the Northeast region and South Central region. We have currently estimated our total capital expenditures for compliance with air pollution control regulations from 2006 to 2014 at the NRG facilities at approximately $675 million.
      Since 1999, Texas Genco has invested approximately $700 million for NOx emissions controls at its plants. These emissions controls were installed to comply with regulations adopted by the Texas Commission on Environmental Quality to attain the one-hour national ambient air quality standard for ozone, as well as provisions of the Texas electric restructuring law. As a result, emissions from its plants in the Houston-Galveston area have been reduced by approximately 88% from 1998 levels and its fleet overall operates at one of the lowest NO x  emissions rates in the country. In aggregate, the Texas Genco plants are in compliance with current NO x  emission limits and are not expected to incur material environmental capital expenditures to ensure NO x  emissions compliance in the next several years. The Texas Commission on Environmental Quality has, however, initiated a rulemaking process for establishing lower NO x  emissions limits to assure compliance with the USEPA 8-hour ozone standard in the Houston-Galveston and Dallas-Fort Worth areas. It is possible that any new regulations implemented may require additional NO x  emission controls on Texas Genco plants in 2009 or beyond. We have currently estimated approximately $70 million in additional capital expenditures with respect to compliance with air pollution control requirements (primarily replacement of catalyst for NO x  emission controls) between 2006 and 2014.
      The USEPA had also proposed MACT standards for nickel from oil-fired units that would essentially require the installation of electrostatic precipitators on certain oil-fired units. These proposed requirements were originally included in drafts of CAMR. However, reflecting further dialogue with generation industry participants and additional scientific review, the nickel MACT provisions were omitted from CAMR. In fact, the USEPA issued a delisting rule on March 29, 2005 effectively removing the MACT standards for nickel (i.e., specific control technologies to be installed at each affected plant) at oil-fired power plants. A number of environmental groups lodged legal challenges to the USEPA’s delisting rule and the agency has agreed to reconsider this delisting, although it has not specified which issues will be reconsidered. As the delisting challenge relates to both nickel from oil-fired power plants and mercury from coal-fired plants, it is not possible to predict the outcome of the pending legal action.
      NRG’s facilities in the eastern United States are subject to a cap-and-trade program governing NOx emissions during the “ozone season” (May 1 through September 30). These rules essentially require that one NO x  allowance be held for each ton of NO x  emitted from fossil fuel-fired stationary boilers, combustion turbines, or combined cycle systems. Each of NRG’s facilities that is subject to these rules has been allocated NO x  emissions allowances. NRG currently estimates that the portfolio total is currently sufficient to generally cover operations at these facilities through 2009. However, if at any point allowances are insufficient for the anticipated operation of each of these facilities, NRG must purchase NO x  allowances. Any obligation to purchase a substantial number of additional NO x  allowances could have a material adverse effect on NRG’s operations.
      The Clean Air Visibility Rule (or so-called BART rule) was published by the USEPA on July 6, 2005. This rule is designed to improve air quality in national parks and wilderness areas. The rule requires regional haze controls (by targeting SO 2  and NO x  emissions from sources including power plants of a certain vintage) through the installation of Best Available Retrofit Technology, or BART, in certain cases. States must develop implementation plans by December 2007 which may be satisfied through an emissions trading program for BART sources. Although the BART rule will apply to many of the Company’s facilities, sources that are also

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subject to CAIR (which include most of our facilities) will likely be able to satisfy their obligations under the BART rule through compliance with the more stringent CAIR. Accordingly, no material additional expenditures are anticipated for compliance with the Clean Air Visibility Rule, beyond those required by CAIR.
      In addition to federal regulation, national legislation has been proposed that would impose annual caps on U.S. power plant emissions of NO x , SO 2 , mercury, and, in some instances, CO 2 . While the Administration’s proposed Clear Skies Act (which would regulate the aforementioned pollutants except for CO 2 ) stalled in Senate Committee on March 9, 2005, the Bush Administration continues to support this legislation. Clear Skies overlaps significantly with CAIR and CAMR, and would likely modify or supersede those rules if enacted as federal legislation as proposed.
      Twelve states and various environmental groups filed suit against the USEPA seeking confirmation that the USEPA has an existing obligation to regulate greenhouse gases, or GHGs, under the CAA. On July 15, 2005, the US Court of Appeals for the District of Columbia Circuit (in  Commonwealth of Massachusetts v. EPA ) supported the USEPA’s refusal to regulate GHG emissions from motor vehicles, although avoiding the broader issue of whether USEPA has authority, or an obligation, to regulate GHGs under the CAA. On September 1, 2005, five states requested reconsideration of this dismissal. While the specific issue under consideration is the USEPA’s obligation to require GHG cuts from mobile sources, any decision implying that the USEPA has an obligation to regulate GHGs nationally has wider implications for the power generation sector. In 2004, eight states and the City of New York filed suit in the U.S. District Court for the Southern District of New York against American Electric Power Company, Southern Company, Tennessee Valley Authority, Xcel Energy, Inc. and Cinergy Corporation, alleged to be the nation’s five largest emitters of GHGs and all of which are owners of electric generation ( Connecticut v. AEP ). An injunction was sought against each defendant to force it to abate its contribution to the “global warming nuisance” by requiring CO 2  emissions caps and annual reductions in those caps for at least a decade. On September 15, 2005, the public nuisance case was dismissed on the basis that the claims made raised “political questions” reserved to the legislative and executive branches of the federal government. On September 20, 2005, plaintiffs filed an appeal of this decision with the U.S. Court of Appeals for the Second Circuit. The initiation of GHG-related litigation and proposed legislation is becoming more frequent, although the outcomes of such suits or proposed litigation cannot be predicted. Although NRG has not been named as a defendant in any related suits, the outcome of such suits could affect the overall regulation of GHGs under the CAA. Our compliance costs with any mandated GHG reductions in the future could be material. See also “Regional U.S. Environmental Regulatory Initiatives,” below.
      In the 1990s, the USEPA commenced an industry-wide investigation of coal-fired electric generators to determine compliance with environmental requirements under the CAA associated with repairs, maintenance, modifications and operational changes made to facilities over the years. As a result, the USEPA and several states filed suits against a number of coal-fired power plants in mid-western and southern states alleging violations of the CAA NSR/ Prevention of Significant Deterioration, or PSD, requirements. In one of the more prominent suits of this type, involving Ohio Edison, a subsidiary of First Energy, the USEPA reached settlement on March 18, 2005 for NSR issues with respect to all coal-fired plant located in Ohio, obligating First Energy to spend $1.1 billion to install pollution control equipment through 2010. In another similar suit, on June 15, 2005 the USEPA appeal in the Duke Energy case was heard with the U.S. Court of Appeals for the Fourth Circuit holding in favor of Duke’s position as to what type of modification triggers NSR and PSD provisions. Rehearing petitions filed in this matter by the Department of Justice and some environmental groups were denied on August 30, 2005. On December 28, 2005, further petitions were filed by environmental groups requesting Supreme Court review of this decision. On June 3, 2005, the U.S. District Court for the Northern District of Alabama reached conclusions favorable to Alabama Power through the court’s interpretation of NSR rules relating to “routine maintenance, repair and replacement,” or RMRR, and the correct test for determining a significant net emissions increase. However, divergent rulings exist on NSR issues across the country, with courts in Ohio and Indiana providing interpretations of the NSR provisions different from those in the Duke and Alabama cases. For example, on August 29, 2005, U.S. District Court for the Southern District of Indiana ruled in  U.S. v. Cinergy  in favor of the USEPA and specifically rejected the conclusion in the Duke case.

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      In an effort to revise the legal requirements as to what amounts to a major modification and what emissions tests apply, USEPA issued its NSR Reform Rule on December 31, 2002, although its implementation was stayed by court order on December 24, 2003. There have been a number of legal challenges to different aspects of the proposed rule. On October 13, 2005 USEPA proposed changes to its NSR permitting program to stipulate an emissions test standard based on hourly emission rates, rather than aggregate annual emissions. The proposed change is subject to a 60-day public comment through February 17, 2006.
      Given the divergent cases and rules in this area (at both the federal and state levels), it is difficult to predict with certainty the parameters of the final NSR/ PSD regime. However, in October 2005, the USEPA announced that due to the promulgation of programs such as CAIR and the Clean Air Visibility Rule, it is placing a lower priority on continued enforcement of suspected NSR/ PSD violations. In the meantime, we continue to analyze all proposed projects at our facilities to ensure ongoing compliance with the applicable legal requirements.
 	 	
 	Water	
      In July 2004, USEPA published rules governing cooling water intake structures at existing power facilities (the Phase II 316(b) Rules). The Phase II 316(b) Rules specify certain location, design, construction and capacity standards for cooling water intake structures at existing power plants using the largest amounts of cooling water. These rules will require implementation of the Best Technology Available, or BTA, for minimizing adverse environmental impacts unless a facility shows that such standards would result in very high costs or little environmental benefit. The Phase II 316(b) Rules require our facilities that withdraw water in amounts greater than 50 million gallons per day (and utilize at least 25% for cooling purposes) to submit certain surveys, plans and operational and restoration measures (with wastewater permit applications or renewal applications) that would minimize certain adverse environmental impacts of impingement or entrainment. The Phase II 316(b) Rules affect a number of NRG’s and Texas Genco’s plants, specifically those with once-through cooling systems. Compliance options include the addition of control technology, modified operations, restoration or a combination of these, and are subject to a comparative cost and cost/benefit justification. While NRG and Texas Genco have conducted a number of the requisite studies, until all the needed studies throughout our fleet have been completed and consultations on the results have occurred with USEPA (or its delegated state or regional agencies), it is not possible to estimate with certainty the capital costs that will be required for compliance with the Phase II 316(b) Rules, although current estimates for the combined company’s facilities involve capital expenditures and related costs of around $80 million between 2006 and 2012. In addition, the Phase II Rules have been challenged by industrial and environmental groups and the outcome of this litigation could affect our obligations pursuant to these rules. Further, Phase III rules, which were proposed in November 2004, may be applicable to some of our smaller power plants when finalized.
 	 	
 	Nuclear Waste	
      Under the U.S. Nuclear Waste Policy Act of 1982, the federal government must remove and ultimately dispose of spent nuclear fuel and high-level radioactive waste from nuclear plants such as STP. Consistent with the Act, owners of nuclear plants, including Texas Genco and the other owners of STP, entered into contracts setting out the obligations of the owners and the U.S. Department of Energy, or DOE, including the fees being paid by the owners for DOE’s services. Since 1998, the DOE has been in default on its obligations to begin removing spent nuclear fuel and high-level radioactive waste from reactors. On January 28, 2004, Texas Genco LP and the other owners of STP filed a breach of contract suit against the DOE in order to protect against the running of a statute of limitations.
      Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The state of Texas has agreed to a compact with the states of Maine and Vermont for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by President Clinton in 1998. In 2003, the state of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal. We intend to continue to ship

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low-level waste material from STP off-site for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will then be stored on-site. STP’s on-site storage capacity is expected to be adequate for STP’s needs until other off-site facilities become available.
 	 	
 	Regional U.S. Environmental Regulatory Initiatives	
      Texas (ERCOT) Region. The USEPA’s Region VI (which includes Texas, Louisiana, and three other states) indicated in September 2004 that it intends to evaluate 75%-80% of the coal-fired power plants in its region over the next several years for potential violations of the NSR program or PSD. During air emissions inspections of Texas Genco’s Limestone plant in November 2004, a USEPA inspector informally advised Texas Genco that the USEPA has drafted, but not yet sent, an information request letter pursuant to Section 114 of the CAA concerning potential NSR or PSD issues at the Limestone plant. As of January 3, 2006, Texas Genco has not received this letter and has not had any further communications on this issue with the USEPA.
      Northeast Region. Massachusetts air regulations prescribe schedules under which six existing coal-fired power plants in-state are required to meet stringent emission limits for NO x , SO 2 , mercury, and CO 2 . The state has reserved the issue of control of carbon monoxide and particulate matter emissions for future consideration. NRG’s Somerset plant is subject to these regulations. NRG has installed natural gas reburn technology to meet the NO x  and SO 2  limits. On June 4, 2004, the Massachusetts Department of Environmental Protection, or MADEP, issued its regulation on the control of mercury emissions. The effect of this regulation is that starting October 1, 2006, Somerset will be capped at 13.1 lbs/year of mercury and as of January 1, 2008, Somerset must achieve a reduction in its mercury inlet-to-outlet concentration of 85%. We plan to meet the requirements through the management of our fuels and the use of early and off-site reduction credits. Additionally, NRG has entered into an agreement with MADEP to retire or repower the Somerset station by the end of 2009.
      The Massachusetts carbon regulation 310 CMR 7.29 “Emissions Standards for Power Plants” requires coal-fired generation located within the state to comply with CO 2  emission restrictions. A carbon emissions cap applies beginning January 1, 2006, while a rate requirement will apply in 2008. This regulation means that if CO 2  emissions at NRG’s Somerset facility exceed the annual cap from 2006, then the excess must be offset with approved CO 2  credits. However, since there are currently no approved CO 2  credits for use in Massachusetts and no general implementing regime, MADEP has proposed that generators annually report overages, starting in 2006, and at the time that there is a an established CO 2  market operating in the state, NRG would be required to purchase or generate sufficient CO 2  credits to offset the balance. On December 20, 2005, Massachusetts issued proposed revisions to the CO 2  regulations, including a proposed implementing regime which could allow the use of on-site and off-site generated CO 2  credits, with a price backstop of $10/ton. Comments are due by the end of January 2006 and MADEP expects to finalize these revisions in spring 2006. Massachusetts was involved in the initial negotiations regarding the Regional Greenhouse Gas Initiative, or RGGI, which is discussed below, but did not enter into the recent Memorandum of Understanding with other northeastern states. Given the regulatory uncertainty surrounding implementation of Massachusetts’s carbon market and the corresponding costs of CO 2  allowances when that market exists, Somerset could be materially affected if it does not retire by the end of 2009.
      Pursuant to New York State Department of Environmental Conservation, or NYSDEC, rules (the Acid Deposition Reduction Program, ADRP) fossil-fuel-fired combustion units in New York must reduce SO2 emissions to 25% below the levels allowed in the federal Acid Rain Program starting January 2005 and to 50% below those levels starting in January 2008. In addition, under ADRP generators now also have to meet the ozone season NO x  emissions limit year-round. Our strategy for complying with the ADRP is to generate early reductions of SO 2  and NO x  emissions associated with fuel switching and use such reductions to extend the timeframe for implementing technological controls, which could ultimately include the addition of flue gas desulfurization, or FGD, and selective catalytic reduction, or SCR, equipment. On January 11, 2005, NRG reached an agreement with the State of New York and the NYSDEC in connection with voluntary emissions reductions at the Huntley and Dunkirk facilities, as discussed below in Legal Proceedings. The Consent

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Decree was entered by the U.S. District Court for the Western District of New York on June 3, 2005. NRG does not anticipate that any additional material capital expenditures, beyond those already spent, will be required for our Huntley and Dunkirk plants to meet the current compliance standards under the Consent Decree through 2010, although, this does not reflect any additional capital expenditures that may be required to satisfy other federal and state laws.
      Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC entered into a Consent Order with NYSDEC, effective March 31, 2004, regarding certain alleged opacity exceedances. The Consent Order required the respondents to pay a civil penalty of $1.0 million which was paid in April 2004. The Order also stipulates penalties (payable quarterly) for future violations of opacity requirements and a compliance schedule. NRG recently resolved a dispute with NYSDEC over the method of calculation for stipulated penalties. NRG paid NYSDEC $1.3 million at the end of 2005 to cover the stipulated penalty payments that had been withheld pending resolution of the dispute.
      While no rules affecting NRG’s existing facilities have been formally proposed, Delaware has recently issued a “Start Action Notice” to impose emissions standards for SO 2 , NO x  and mercury. Delaware is pursuing such rule-making based on recent determinations that portions of the state are in non-attainment for NAAQS for fine particulates, and all of the state is in non-attainment for the NAAQS for 8-Hour Ozone. We are evaluating emissions reduction opportunities which may include blending low sulfur western coals. NRG will actively participate in the Delaware rule-making as a stakeholder and will continue to be involved in environmental policy-making efforts in Delaware through the Governor’s Energy Task Force and interactions with legislators, the PSC and the Delaware Department of Natural Resources and Environmental Control, or DNREC.
      The Ozone Transport Commission, or OTC, was established by Congress and governs ozone and the NOx budget program in certain eastern states, including Massachusetts, Connecticut, New York and Delaware. In January 2005, the OTC redoubled its efforts to develop a multi-pollutant regime (SO 2 , NO x , mercury and CO 2 ) that is expected to be completed by mid-2006 (with individual state implementation to follow). On June 8, 2005, the OTC members unanimously resolved to implement “CAIR-Plus” emissions regulations, based on concerns that the USEPA’s CAIR fails to achieve attainment of 8-hour ozone and fine particulate matter. As a result, the OTC proposes to implement a regional plan containing emissions reduction targets for power plants that exceed those under CAIR. The OTC targets and timelines are as follows: (a) through September 2006: write model rule, with participating states signing a Memorandum of Understanding; (b) by December 2006 states file their implementation plans or reduction regulations; (c) 2008 Phase I reductions of NO x  (to 1.87 million tons) and SO 2 (to 3.0 million tons) apply; (d) 2012 Phase II reductions of NO x  (to 1.28 million tons) and SO 2  (to 2.0 million tons) apply; and (e) 2015 90% mercury removal required. OTC’s proposed CAIR-Plus involves emissions reductions which are both sooner and more aggressive than CAIR (e.g., aggregate NO x  reductions would be 25% greater than CAIR, while SO 2  reductions would be 33% greater than CAIR). NRG continues to be engaged in the OTC stakeholder process. While it is not possible to predict the outcome of this regional legislative effort, to the extent that the OTC is successful in implementing emissions requirements that are more stringent than existing regimes (including the recently reached New York settlement), NRG could be materially impacted.
      On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create a regional initiative to establish a cap-and-trade GHG program for electric generators, referred to as the Regional Greenhouse Gas Initiative, or RGGI. The model RGGI rule is scheduled to be announced within the next few months, with an estimate of two to three years for participating states to finalize implementing regulations. The current proposal is for the program to start in 2009, with a review in 2015 and an assessment of further reductions after 2020. The proposal involves an overall RGGI cap (with state sub-caps) based on CO 2  emissions for the period 2000 to 2004. That cap, referred to as “stabilization,” will remain the same through 2015, with a 10% reduction between 2015 and 2020. Decisions on allowance allocations will be made by each state, although at least 25% of the state allocations will be set aside for public purposes, suggesting that from implementation, generators in the RGGI region may receive an allocation of allowances that is materially less than required to cover existing emissions, potentially having a significant effect on the cost of operations. While the details of the model rule are still under development, when RGGI is implemented, our

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plants in New York, Delaware and Connecticut may be materially affected. If Massachusetts, which was originally involved in the development of RGGI, decides to participate, NRG’s plant in that state may also be affected.
      South Central Region. The Louisiana Department of Environmental Quality, or LADEQ, has promulgated State Implementation Plan revisions to bring the Baton Rouge ozone non-attainment area into compliance with applicable NAAQS. NRG participated in development of the revisions, which require the reduction of NO x  emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 lbs/ MMBtu and 0.21 lbs/ MMBtu NO x , respectively (both based on heat input). This revision of the Louisiana air rules would constitute a change-in-law covered by agreement between Louisiana Generating, LLC and the electric cooperatives (power offtakers), allowing the costs of added combustion controls to be passed through to the cooperatives. The combustion controls required at the Big Cajun II Generating Station to meet the state’s NO x  regulations have been installed.
      On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the CAA from USEPA seeking information primarily related to physical changes made at Big Cajun II and subsequently received a notice of violation, or NOV, based on alleged NSR violations. See “—Legal Proceedings” for a discussion of this matter. NRG is up-to-date with all USEPA information requests it has received in connection with this matter and has not been contacted by USEPA pursuant to the NOV since May 2005.
      Western Region. The El Segundo Generating Station is regulated by the South Coast Air Quality Management District, or SCAQMD. Before its retirement as of January 1, 2005, the Long Beach Generating Station was also regulated by SCAQMD. SCAQMD approved amendments to its Regional Clean Air Incentives Market, or RECLAIM, NO x  regulations on January 7, 2005. RECLAIM is a regional emission-trading program targeting NO x  reductions to achieve state and federal ambient air quality standards for ozone. Among other changes, the amendments reduce the NO x  RECLAIM Trading Credit, or RTC, holdings of El Segundo Power, LLC and Long Beach Generation LLC facilities by certain amounts. Notwithstanding these amendments, retained RTCs are expected to be sufficient to operate El Segundo Units 3 and 4 as high as 100% capacity factor for the life of those units.
      On October 6, 2005, the California Public Utilities Commission, or CPUC, adopted a policy statement on GHG Performance Standards as part of a focus on emissions from conventional fossil-fuel resources. The adopted policy statement directs the CPUC to investigate a GHG emissions performance standard for energy procurement by the state’s Investor-Owned Utilities, or IOUs, that is no higher than the GHG emissions levels of a combined-cycle natural gas turbine for all energy procurement contracts longer than three years in length and for all new IOU owned generation. While this policy statement does not impose new requirements at this time, instead requiring CPUC staff to investigate possible new requirements that would apply to all IOU procured energy and capacity, including in and out-of-state generation, it gives some basis for expecting the development of carbon constrained standards within the California wholesale power market.
 	 	
 	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. We may also be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, or SARA, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault) and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills or other occurrences during our operations. Although both

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NRG and Texas Genco have been involved in on-site contamination matters, to date, neither has been named as a potentially responsible party with respect to any off-site waste disposal matter.
      Texas (ERCOT) Region. The lignite used to fuel the Limstone facility is obtained from a surface mine adjacent to the facility under an amended long-term contract with Texas Westmoreland Coal Co., or TWCC, entered into in August 1999. 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, Texas Genco is responsible for final mine reclamation obligations. The Railroad Commission of Texas has imposed a bond obligation of approximately $70 million on TWCC for the reclamation of this lignite mine. Final reclamation activity is expected to commence in 2015. Pursuant to the contract with TWCC, an affiliate of CenterPoint Energy, Inc. has guaranteed $50 million of this obligation until 2010. The remaining sum of approximately $20 million has been bonded by the mine operator, TWCC. Under the terms of Texas Genco’s agreement, Texas Genco is required to post a corporate guarantee in the amount of $50 million of TWCC’s reclamation bond when CenterPoint’s obligation lapses. As of December 31, 2005, Texas Genco has accrued $10 million related to the mine reclamation obligation.
      Northeast Region. Significant amounts of ash are contained in landfills at on and off-site locations. At Dunkirk, Huntley, Somerset and Indian River, ash is disposed of at landfills owned and operated by NRG. NRG maintains financial assurance to cover costs associated with landfill closure, post-closure care and monitoring activities. NRG has funded a trust in the amount of approximately $6.0 million to provide such financial assurance in New York and $6.9 million in Delaware. NRG must also maintain financial assurance for closing interim status “RCRA (Resource Conservation and Recovery Act) facilities” at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations and has funded a trust in the amount of $1.5 million accordingly.
      NRG inherited historical clean-up liabilities when it acquired the Somerset, Devon, Middletown, Montville, Norwalk Harbor, Arthur Kill and Astoria Generating Stations. During installation of a sound wall at Somerset Station in 2003, oil contaminated soil was encountered. NRG has delineated the general extent of contamination, determined it to be minimal, and has placed an activity use limitation on that section of the property. Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Harbor Stations have been identified. NRG has proposed a remedial action plan to be implemented over the next two to eight years (depending on the station) to address historical ash contamination at the facilities. The total estimated cost is not expected to exceed $1.5 million. Remedial obligations at the Arthur Kill generating station have been established in discussions between NRG and the NYSDEC and are estimated to be approximately $1.1 million. Remedial investigations continue at the Astoria generating station with long-term clean-up liability expected to be approximately $2.9 million. While installing groundwater-monitoring wells at Astoria to track our remediation of an historical fuel oil spill, the drilling contractor encountered deposits of coal tar in two borings. NRG reported the coal tar discovery to the NYSDEC in 2003 and delineated the extent of this contamination. NRG may also be required to remediate the coal tar contamination and/or record a deed restriction on the property if significant contamination is to remain in place.
      In September 2001, we experienced an underground fuel line leak at our Vienna Generating Station, resulting in a small release of oil free product, which was contained. NRG promptly reported the event to the relevant state agencies and continues to work with the Maryland Department of the Environment, or DEP, to develop any remediation requirements. Ongoing monitoring has indicated that the product is stable. NRG submitted a site assessment report and proposed remediation plan to Maryland DEP but the agency has not formally responded to those documents. Based upon work completed by a remediation contractor retained by NRG, long-term clean up liability in connection with this matter is not expected to exceed $0.5 million.
      South Central Region. Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated on site at the Big Cajun II Generating Station are addressed through the use of a trust fund maintained by NRG in the amount of approximately $5.0 million. Annual payments are made to the fund in the amount of $0.12 million.

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      Western Region. The Asset Purchase Agreements for the Long Beach, El Segundo, Encina, and San Diego gas turbine generating facilities provide that SCE and San Diego Gas & Electric, or SDG&E, as sellers retain liability, and indemnify NRG, for existing soil and groundwater contamination that exceeds remedial thresholds in place at the time of closing. NRG and its business partner identified existing contamination and provided the results to the sellers. SCE and SDG&E agreed to address this identified contamination and are undertaking corrective action at the Encina and San Diego gas turbine generating sites. NRG could incur related costs if SCE and SDG&E did not complete their corrective action responsibilities. Spills and releases of various substances have occurred at these sites since NRG established the historical baseline, all of which have been, or will be, completely remediated. An oil leak in 2002 from underground piping at the El Segundo Generating Station contaminated soils adjacent to and underneath the Unit 1 and 2 powerhouse. NRG excavated and disposed of contaminated soils to the greatest extent permitted by existing laws. Following NRG’s formal request, the Los Angeles Regional Water Quality Control Board agreed to allow the remaining contaminated soils to stay underneath the building foundation until the building is demolished.
      A diesel fuel spill to on-site surface containment occurred at the Cabrillo Power II LLC Kearny Combustion Turbine facility (San Diego) in February 2003. Emergency response and subsequent remediation activities were completed. Confirmation sampling for the site was completed in 2004 and submitted to the San Diego County Department of Environmental Health. Three San Diego Combustion Turbine facilities, formerly operating pursuant to land leases with the U.S. Navy, are currently being decommissioned with equipment being removed from the sites and remediation activities occurring where necessary. All remedial activities are being completed pursuant to the requirements of the U.S. Navy and the San Diego County Department of Environmental Health. Remediation activities were completed in 2004 at the Naval Training Center and North Island facilities. At the 32nd Street Naval Station facility, additional contamination delineation is necessary and additional unquantified remediation in inaccessible areas may be required in the future. Given the current uncertainties at this facility, it is difficult to accurately estimate the resultant clean up liability.
 	 	
 	International Environmental Matters	
      Most of the foreign countries in which NRG owns or may acquire or develop independent power projects have environmental and safety laws or regulations relating to the ownership or operation of electric power generation facilities. These laws and regulations, like those in the U.S., are constantly evolving and have a significant impact on international wholesale power producers. In particular, NRG’s international power generation facilities will likely be affected by emissions limitations and operational requirements imposed by the Kyoto Protocol, which is an international treaty related to greenhouse gas emissions which entered into force on February 16, 2005, and country-based restrictions pertaining to global climate change concerns.
      We retain appropriate advisors in foreign countries and seek to design our international asset management strategy to comply with each country’s environmental and safety laws and regulations. There can be no assurance that changes in such laws or regulations will not adversely effect our international operations.
      Australia. With respect to Australia, climate change is considered a long-term issue (e.g. 2010 and beyond) and the Australian government’s response to date has included a number of initiatives, all of which have had no or minimal impact on our operations. The Australian government has stated that Australia will achieve its Kyoto Protocol target of 8% below 1990 greenhouse gas emission levels for the 2008 to 2012 reporting period, but that Australia will not ratify the Kyoto Protocol. Each Australian state government is considering implementing a number of climate change initiatives that will vary considerably state to state, with the possible exception of an interjurisdictional state-led carbon trading proposal (which is not supported by the federal government).
      NRG Flinders disposes of ash to slurry ponds at Port Augusta in South Australia. At the end of life of the power station, NRG Flinders will have an obligation to remediate these ponds in accordance with a plan accepted by the South Australian Environment Protection Agency and confirmed in the Environment Compliance Agreement between the South Australian Minister for Environment and Heritage and NRG Flinders dated September 20, 2000, or the EC Agreement. The estimated cost of remediation including

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contingencies according to the plan is AUD 2.0 million. There is no timeline associated with the obligation, but the EC Agreement extends to 2025. Under these arrangements, required remediation relates to surface remediation and does not entail any groundwater remediation.
      MIBRAG / Schkopau, Germany. While CO2 emissions trading began in Germany in 2005, pursuant to European Union obligations under the Kyoto Protocol, we do not currently expect the CO 2  trading program to be a material constraint on our business in Germany. Changes to the German Emission Control Directive will result in lower NO x  emission limits for plants firing conventional fuels (Section 13 of the Directive) and co-firing waste products (Section 17 of the Directive). The new regulations will require the Mumsdorf and Deuben Power stations to install additional controls to reduce NO x  emissions in 2006. These plant modifications are proceeding on schedule.
      The European Union’s Groundwater Directive and Mine Wastewater Management Directive are in the rule-making stage with the final outcome still under debate. Given the uncertainty regarding the possible outcome of the debate on these directives, we cannot quantify at this time the effect such requirements would have on our future coal mining operations in Germany.
      A new law specifically dealing with the relocation of the residents of Heuersdorf from the path of the mining plan was enacted by the legislature of Saxony in 2004. On November 25, 2005, the Saxony Constitutional Court upheld the constitutionality of the Heuersdorf act. This ruling cannot be appealed. Nuisance suits remain a possibility, but the court’s ruling brings the matter closer to final resolution.
      The supply contracts under which MIBRAG mines lignite from the Profen mine expire on December 31, 2021. The contracts under which MIBRAG mines lignite from the Schleenhain mine expire in 2041. At the end of each mine’s productive lifetime, MIBRAG will be required to reclaim certain areas. MIBRAG accrues for these eventual expenses and estimates the cost of the final reclamation to approach approximately €176 million in the instance of the Schleenhain mine and €132 million for Profen.
Insurance
 	 	
 	General	
      Both NRG and Texas Genco carry insurance coverage consistent with companies engaged in similar commercial operations with similar properties, including business interruption insurance for the coal and lignite plants. However, both NRG’s and Texas Genco’s insurance policies are subject to certain limits and deductibles as well as policy exclusions. Adequate insurance coverage in the future may be more expensive or may not be available on commercially reasonable terms. Also, the insurance proceeds received for any loss of or any damage to any of our generation plants may not be sufficient to restore the loss or damage without negative impact on our financial condition, results of operations or cash flows.
      We expect to receive a report from Moore-McNeil LLC, an internationally recognized independent insurance consulting firm, which concludes that the insurance program that is presently in effect for NRG and Texas Genco is consistent with prudent industry practice.
 	 	
 	Nuclear	
      Texas Genco and the other owners of STP maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of STP currently maintain $2.75 billion in property damage insurance coverage, which is above the legally required minimum. STPNOC currently carries accidental outage coverage with a 17 week deductible and a six week indemnity at a rate of $3,500,000 per week. This coverage may not be available on commercially renewable terms or may be more expensive in the future and any proceeds from such insurance may not be sufficient to indemnify the owners of STP for their losses. By the date of closing of the Acquisition, Texas Genco would have also purchased additional accidental outage coverage for its ownership percentage in STP. This coverage will provide maximum weekly indemnity of $1,980,000 for 52 weeks and $1,584,000 per week for the next 104 weeks after the 17-week waiting period and six-week indemnity period have been met.

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These figures are per unit and if more than one unit experiences an outage from the same accident, the weekly indemnity is limited to 80% of the single unit recovery when both units are out of service.
      The Price-Anderson Act, as amended by the Energy Policy Act of 2005, requires owners of nuclear power plants in the U.S. 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. For such claims in excess of $300 million per reactor, Texas Genco and the other owners of STP are liable for any single incident, whether it occurs at STP or at another nuclear power plant not owned by it, up to a cap of $95.8 million per reactor in retrospective premiums for such incident but not to exceed $15 million per year in each case as adjusted for future inflation. These amounts are assessed per each licensed reactor. STP is a two reactor facility and our liability is capped at 44.0% of these amounts due to our 44.0% interest in STP. 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 our financial condition, results of operations or cash flows.
Legal Proceedings
      We are, from time to time, a party to litigation or legal proceedings arising in the ordinary course of our business, most of which involves contract disputes or claims for personal injury, including exposure to asbestos and property damage incurred in connection with our operations. We believe that we have valid defenses to the legal proceedings and investigations described below and we intend 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 us or our subsidiaries in the future, asserting similar or different legal theories and seeking similar or different types of damages and relief. Unless specified below, we are unable to predict the outcome of these legal proceedings. An unfavorable outcome in one or more of these proceedings could have a material impact on our consolidated financial position, results of operations or cash flows. We also have indemnity rights for some of these proceedings to reimburse us for certain legal expenses and to offset certain amounts deemed to be owed in the event of an unfavorable litigation outcome.
 	 	
 	Texas Commercial Energy Litigation	
      In July 2003, Texas Commercial Energy filed in federal court in Corpus Christi, Texas a lawsuit against, as the lawsuit was subsequently amended, Texas Genco, LP, CenterPoint Energy, Inc., Reliant Energy, Inc., Reliant Electric Solutions, LLC, several other CenterPoint Energy, Inc. and Reliant Energy, Inc. subsidiaries and a number of other participants in the ERCOT market. The plaintiff, a retail electricity provider in the Texas market served by ERCOT, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws and committed fraud and negligent misrepresentation. The lawsuit sought damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys’ fees. In June 2004, the federal court dismissed plaintiff’s claims on jurisdictional grounds and, in July 2004, the plaintiff filed an appeal that Texas Genco, LP contested. The court of appeals affirmed the lower court’s decision in June 2005. The plaintiff moved for a rehearing en banc which was subsequently denied. On January 9, 2006, plaintiff’s petition for certiorari to the U.S. Supreme Court was denied.
 	 	
 	The Valence Litigation	
      On February 20, 2004, Texas Genco, LP filed an injunction and declaratory judgment lawsuit in a Freestone County, Texas state district court seeking to enjoin Valence Operating Company, or Valence, from drilling or engaging in work to prepare for drilling a natural gas well (Well 8) in Texas Genco, L.P.’s Class II Industrial Solid Waste Facility, which we refer to as the Landfill, adjacent to Texas Genco’s Limestone Plant. The Landfill is used to dispose of ash byproducts from the combustion of coal and lignite at the Limestone Plant. Following a hearing in March 2004, the court granted Texas Genco, LP’s request and enjoined Valence

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from drilling the well in the Landfill. In connection with that injunction, the court ordered, and Texas Genco, LP posted, a bond in the amount of $1.0 million to secure payment of any damages suffered by Valence should it be found to have been wrongfully enjoined. Valence filed a counter-claim against Texas Genco, LP for wrongful injunction and sought to recover the full amount of the bond. Trial on the merits in this case was held in November 22, 2004. The jury found, among other things, that Texas Genco, LP had an existing use that would be precluded or substantially impaired if Valence drilled Well 8. The jury also found damages in the amount of $400,000 as compensation to Valence for the issuance of the temporary restraining order and temporary injunction. Both Texas Genco, LP and Valence moved to disregard certain of the jury’s findings and for judgment in their respective favors. On October 24, 2004, the court accepted the jury’s findings and entered judgment that Texas Genco, LP take nothing on its claim for permanent injunction, and that Valence recover $400,000 in damages, together with pre- and post-judgment interest and costs. The court also reinstated the temporary injunction pending resolution of Texas Genco, LP’s appeal and also ordered, and Texas Genco posted, a bond in the amount of approximately $860,000 in connection with the temporary injunction. The bond shall be increased on a monthly basis after February 2006. Texas Genco, LP filed a timely appeal to the Waco County Court of Appeals. On January 18, 2006, the court reversed the trial court’s decision ordering that Valence take nothing on its counterclaim and remanding the case back to trial court for entry of a permanent injunction enjoining Valence from drilling Well 8.
      In addition, a separate lawsuit was filed by Texas Genco, LP in the same court, to enjoin Valence from drilling another well (Well 9) in the Landfill. On October 26, 2004, Texas Genco, LP also obtained a temporary restraining order against drilling this other well. The court ordered, and Texas Genco, LP posted, a bond in the amount of approximately $2.0 million to secure payment of any damages suffered by Valence should it be found to have been wrongfully enjoined in this second lawsuit. The court recently increased the bond amount to $2.8 million, and has rescheduled this case to February 6, 2006 for trial on the merits.
      Valence currently has two active applications with the Railroad Commission of Texas for drilling permits for two additional wells that would be drilled in the Landfill, one of which would be drilled through the closed cells in Texas Genco, LP’s Landfill. Texas Genco, LP has filed a protest with the Railroad Commission of Texas over these applications, and a hearing was held at the Railroad Commission in April 2005. The hearing examiners recommended denying the permit for one well and granting the other. A ruling by the Railroad Commission is expected in the next few weeks. Texas Genco, LP is vigorously contesting these attempts to drill into the Landfill because such drilling activity impairs Texas Genco, LP’s use of its property for the Landfill.
 	 	
 	Texas Genco Asbestos Litigation	
      The Texas Genco plants are the subject of a number of lawsuits filed against numerous defendants in addition to Texas Genco Holdings, Inc., by a large number of individuals who claim personal injury due to alleged exposure to asbestos while working at plant sites in Texas. Most of these claimants have been third party contractor or sub-contractor employees who participated in the construction, renovation or repair of various industrial plants, including power plants. While many of the claimants have never worked at or near Texas Genco’s plants, some of the claimants have worked at locations owned by Texas Genco. We anticipate that additional claims like those that have been asserted to date may be asserted in the future. Texas Genco defends these claims aggressively, and, thus, has incurred and expects to continue to incur defense costs as a result of such claims. In addition, while Texas Genco has been dismissed from many of these lawsuits without having to make any payment to claimants, it has incurred and expects to continue to incur some costs associated with the settlement of certain claims. Texas Genco intends to continue its practice of vigorously contesting claims that it does not consider to have merit. To date, costs of settlement and defense have not materially affected Texas Genco, and a portion of the payments in respect of these claims have been offset by insurance recoveries.
      The Texas legislature recently adopted amendments to state law that will make it more difficult for persons claiming personal injuries due to alleged exposure to asbestos to continue to pursue their claims when there is no medical evidence of an actual physical impairment caused by exposure to asbestos. This new legislation, which was signed into law by the Governor of Texas on May 19, 2005, precludes persons whose claims have not been adjudicated by September 1, 2005 from pursuing or advancing their claims until they have produced a report by a board-certified physician that confirms that the claimant has met the standards

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for an actual physical impairment caused by exposure to asbestos, as specified in the legislation. This amendment to state law resulted in some increased claim activity prior to September 1, 2005, but after that date is expected to result in fewer new claims and overall lower costs of defending and settling claims not adjudicated by that date. As of December 31, 2005, there were 3,803 claims pending against Texas Genco Holdings, Inc., a wholly-owned subsidiary of Texas Genco LLC. For the twelve months ended December 31, 2005, there were 268 claims filed against Texas Genco Holdings, Inc., 146 claims settled, 1,261 claims dismissed or otherwise resolved with no payment and the average settlement amount for each claim was approximately $3,600. Under the terms of the separation agreement between Texas Genco Holdings, Inc. and CenterPoint Energy, ultimate financial responsibility for uninsured losses relating to such claims has been assumed by Texas Genco Holdings, Inc., and under the terms of CenterPoint Energy’s agreement to sell Texas Genco Holdings, Inc. to Texas Genco LLC, CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from Texas Genco LLC.
      In addition, Congress is currently considering the proposed Fairness in Asbestos Injury Resolution Act of 2005, which, if it becomes law, would require asbestos defendants and insurers to make payments into a privately-funded national asbestos compensation fund. Under the bill as currently drafted, payments made by us would not be offset by any insurance recoveries. The proposed legislation remains subject to negotiation and modification.
 	 	
 	California Wholesale Electricity Litigation and Related Investigations	
      NRG, WCP, WCP’s four operating subsidiaries, Dynegy, Inc. and numerous other unrelated parties are the subject of numerous lawsuits arising based on events occurring in the California power market. The complaints primarily allege that the defendants engaged in unfair business practices, price fixing, antitrust violations, and other market “gaming” activities. Certain of these lawsuits originally commenced in 2000 and 2001, which seek unspecified treble damages and injunctive relief, were consolidated and made a part of a Multi-District Litigation proceeding before the U.S. District Court for the Southern District of California. In December 2002, the district court found that federal jurisdiction was absent and remanded the cases back to state court. On December 8, 2004, the U.S. Court of Appeals for the Ninth Circuit affirmed the district court in most respects. On March 3, 2005, the Ninth Circuit denied a motion for rehearing. On May 5, 2005, the case was remanded to California state court and, under a scheduling order, defendants filed their objections to the pleadings. On July 22, 2005, based upon the filed rate doctrine and federal preemption, the court dismissed NRG Energy, Inc. without prejudice, leaving only subsidiaries of WCP remaining in the case. On October 3, 2005, the court sustained defendants’ demurrer dismissing the case against all remaining defendants. On December 2, 2005, the plaintiffs filed their notice of appeal from the dismissal.
      In 2002, a number of cases similar to those described above were filed against defendants, including WCP or one or more of its operating subsidiaries and/or Dynegy, Inc., which we refer to as the Northern California cases. On February 25, 2005, the Ninth Circuit affirmed the district court’s decision to dismiss all of the defendants’ Northern California cases. No appeal was taken from this decision.
      In addition to the cases discussed above, other cases, including putative class actions, have been filed in state and federal court on behalf of business and residential electricity consumers that name NRG and/or WCP and/or certain subsidiaries of WCP, in addition to numerous other defendants. The complaints allege the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades, and violated California’s antitrust law and unfair business practices law. The complaints seek restitution and disgorgement, civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. Motion practice is proceeding in these cases and dispositive motions have been filed in several of these proceedings. In the above referenced cases relating to natural gas, Dynegy is defending WCP and/or its subsidiaries pursuant to an indemnification agreement and will be the responsible party for any loss. In cases relating to electricity, Dynegy’s counsel is representing it and WCP and/or its subsidiaries with each party responsible for half of the costs and each party shall be responsible for half of any loss. Where NRG is named as a party in an electricity case, it is defending the case and bears its own costs of defense.

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 	FERC Proceedings	
      There are proceedings in which WCP and WCP subsidiaries are parties, which either are pending before FERC or on appeal from FERC to various U.S. Courts of Appeal. These cases involve, among other things, allegations of physical withholding, a FERC-established price mitigation plan determining maximum rates for wholesale power transactions in certain spot markets, and the enforceability of, and obligations under, various contracts with, among others, the Cal ISO, the California Department of Water Resources, or CDWR, and the State of California. The CDWR claim involves a February 2002 complaint filed by the State of California demanding that FERC abrogate the CDWR contract between the State and subsidiaries of WCP and seeking refunds associated with revenues collected from CDWR. In 2003, FERC rejected this demand and denied rehearing. The case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held December 8, 2004.
 	 	
 	California Attorney General	
      The California Attorney General has undertaken an investigation entitled “In the Matter of the Investigation of Possibly Unlawful, Unfair, or Anti-Competitive Behavior Affecting Electricity Prices in California.” Dynegy, NRG and subsidiaries of WCP have responded to interrogatories, document requests and to requests for interviews.
     Canadian Claim
      On June 30, 2005, three individuals filed a lawsuit with the Ontario Superior Court of Justice against more than 20 power generating entities in the U.S. and Canada, including the Keystone and Conemaugh facility ownership groups. Two of NRG’s subsidiaries own less than four percent of each of these Pennsylvania coal-fired plants. The plaintiffs, on behalf of a purported class of Ontario residents, have alleged air pollution and associated health effects and asserted damages in excess of CA$50 billion (US $43.1 billion, based on conversion rates as of September 30, 2005). The claim was not served on any defendant by December 30, 2005. Accordingly, the claim is inactive and may be revived only if plaintiffs file a motion to extend the time for service and the court grants the motion. Alternatively, plaintiffs could seek to file a new claim.
     New York Operating Reserve Markets
      Consolidated Edison and others petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of FERC’s refusal to order a re-determination of prices in the New York Independent System Operator, or NYISO, operating reserve markets for a two month period in 2000. On November 7, 2003, the court found that NYISO’s method of pricing spinning reserves violated the NYISO tariff. On March 4, 2005, FERC issued an order favorable to NRG stating that no refunds would be required for the tariff violation associated with the pricing of spinning reserves. In the order, FERC also stated that the exclusion of the Blenheim-Gilboa facility and western reserves from the non-spinning market was not a market flaw and NYISO was correct not to use its authority to revise the prices in this market. A motion for rehearing of the order was filed before the April 3, 2005 deadline and on November 17, 2005, FERC denied rehearing. On January 13, 2006, the petitioners filed an appeal with the U.S. Court of Appeals for the District of Columbia Circuit.
     Connecticut Congestion Charges
      On November 28, 2001, Connecticut Light & Power, or CL&P, sought recovery in the U.S. District Court for Connecticut for amounts it claimed were owed for congestion charges under the October 29, 1999 Standard Offer Services Contract. CL&P withheld approximately $30 million from amounts owed to PMI under contract and PMI counterclaimed. CL&P’s motion for summary judgment, which PMI opposed, remains pending. We cannot estimate at this time the overall exposure for congestion charges for the term of the contract prior to the implementation of standard market design, which occurred on March 1, 2003; however, such amount has been fully reserved as a reduction to outstanding accounts receivable.
     New York Environmental Settlement
      In January 2002, the New York Department of Environmental Conservation, or NYSDEC, sued Niagara Mohawk Power Corporation, or NiMo, and NRG in federal court in New York, asserting that projects

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undertaken at NRG’s Huntley and Dunkirk plants by NiMo, the former owner of the facilities, violated federal and state laws. On January 11, 2005, NRG reached an agreement to settle this matter whereby NRG will reduce levels of sulfur dioxide by over 86 percent and nitrogen oxide by over 80 percent in aggregate at the Huntley and Dunkirk plants. NRG is not subject to any penalty as a result of the settlement. Through the end of the decade, NRG expects that its ongoing compliance with the emissions limits set out in the settlement will be achieved through capital expenditures already planned. This includes NRG’s conversion to low sulfur western coal at the Huntley and Dunkirk plants, which will be completed by spring 2006. On April 7, 2005, NYSDEC filed a motion with the court to enter the Consent Decree, and on April 19, 2005, NRG filed a supporting motion. On June 3, 2005, the U.S. District Court for the Western District of New York entered the Consent Decree permitting the settlement and ending the case.
      On October 24, 2005, the U.S. Court of Appeals for the Second Circuit issued its opinion in New York Public Interest Research Group (NYPIRG) v. Stephen L. Johnson, Administrator, U.S. Environmental Protection Agency . In 2000, the NYSDEC issued a NOV to the prior owner of the Huntley and Dunkirk stations. After an unsuccessful challenge to the stations’ Title V air quality permits by NYPIRG, it appealed. The Second Circuit held that, during the Title V permitting process for the two stations, the 2000 NOV should have been sufficient for the NYSDEC to have made a finding that the stations were out of compliance. Accordingly, the court stated that the EPA should have objected to the Title V permits on that basis and the permits should have included compliance schedules. As discussed above, on June 3, 2005, the consent decree among NYSDEC, NiMo, and NRG was entered, settling the substantive issues discussed by the Second Circuit in its decision. NYSDEC is in the process of incorporating the consent decree obligations into the Huntley and Dunkirk Title V permits so as to make them permit conditions, an action we believe is supported by the decision. On January 12, 2006, the NYSDEC, the EPA and NRG filed individual petitions for rehearing with the Second Circuit.
     Station Service Disputes
      On October 2, 2000, NiMo commenced an action against NRG in New York state court seeking damages related to NRG’s alleged failure to pay retail tariff amounts for utility services at the Dunkirk Plant between June 1999 and September 2000. The parties agreed to consolidate this action with two other actions against the Huntley and Oswego Plants. On October 8, 2002, by stipulation and order, this action was stayed pending submission to FERC of some or all of the disputes in the action. The contingent loss from this case is approximately $24.9 million, and at this time we believe we are adequately reserved. In a companion action at FERC, NiMo asserted the same claims and legal theories, and on November 19, 2004, FERC denied NiMo’s petition and ruled that the NRG facilities could net their service obligations over each 30 calendar day period from the day NRG acquired the facilities. In addition, FERC ruled that neither NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG facilities because they are interconnected to transmission and not to distribution. On April 22, 2005, FERC denied NiMo’s motion for rehearing. NiMo appealed to the U.S. Court of Appeals for the D.C. Circuit which, on May 12, 2005, consolidated the appeal with several pending station service disputes involving NiMo. All parties filed their briefs prior to the January 17, 2006 deadline.
      On December 14, 1999, NRG acquired certain generating facilities from CL&P. A dispute arose over station service power and delivery services provided to the facilities. On December 20, 2002, as a result of a petition filed at FERC by Northeast Utilities Services Company on behalf of itself and CL&P, FERC issued an order finding that, at times when NRG is not able to self-supply its station power needs, there is a sale of station power from a third-party and retail charges apply. In August 2003, the parties agreed to submit the dispute to binding arbitration, however, the parties have yet to agree on a description of the dispute and on the appointment of a neutral arbitrator. The contingent loss from this case could exceed $4.8 million, and at this time we believe we are adequately reserved.
     U.S. Environmental Protection Agency
      On January 27, 2004, our subsidiaries, Louisiana Generating, LLC and Big Cajun II, received an initial and, thereafter, subsequent requests under Section 114 of the federal Clean Air Act from EPA Region 6

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seeking information primarily relating to physical changes made at Big Cajun II. Louisiana Generating, LLC and Big Cajun II submitted several responses to the USEPA. On February 15, 2005, Louisiana Generating, LLC received a NOV alleging violations of the NSR provisions of the Clean Air Act at Big Cajun II Units 1 and 2 from 1998 through the NOV date. On April 7, 2005, a meeting was held with USEPA and the Department of Justice and additional information was provided to the agency.
     Itiquira Energetica, S.A.
      NRG’s Brazilian project company, Itiquira Energetica S.A., or Itiquira, the owner of a 156 MW hydro project in Brazil, is in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes, or Inepar. The dispute was commenced in arbitration by Itiquira in September of 2002 and pertains to certain matters arising under the engineering procurement and construction contract between the parties. Itiquira sought Real 140 million and asserted that Inepar breached the contract. Inepar sought Real 39 million and alleged that Itiquira breached the contract. On September 2, 2005, the arbitration panel ruled in favor of Itiquira, awarding it Real 139 million (US $62.3 million, based on conversion rates as of September 30, 2005) and Inepar Real 4.7 million (US $2.1 million, based on conversion rates as of September 30, 2005). Due to interest accrued from the commencement of the arbitration to the award date, Itiquira’s award is increased to approximately Real 227 million (U.S. $100 million, based on conversion rates as of September 30, 2005). Itiquira has commenced the lengthy process in Brazil to execute on the arbitral award. We are unable to predict the outcome of this execution process. On October 14, 2005, Inepar filed with the arbitration panel a request for clarifications of the ruling and Itiquira objected. On December 21, 2005, Inepar’s request for clarifications was denied. Due to the uncertainty of the collection process, NRG is accounting for receipt of any amounts as a gain contingency.
CFTC Trading Litigation
      On July 1, 2004, the Commodities Futures Trading Commission, or CFTC, filed a civil complaint against NRG in Minnesota federal district court, alleging false reporting of natural gas trades from August 2001 to May 2002, and seeking an injunction against future violations of the Commodity Exchange Act. On November 17, 2004, a bankruptcy court hearing was held on the CFTC’s motion to reinstate its expunged bankruptcy claim, and on NRG’s motion to enforce the provisions of the NRG plan of reorganization, thereby precluding the CFTC from continuing its federal court action. The bankruptcy court has yet to schedule a hearing or rule on the CFTC’s pending motion to reinstate its expunged claim. On December 6, 2004, a federal magistrate judge issued a report and recommendation that NRG’s motion to dismiss be granted. That motion to dismiss was granted by the federal district court in Minnesota on March 16, 2005. On May 13, 2005 the CFTC filed a notice of appeal with the U.S. Court of Appeals for the Eighth Circuit. The CFTC filed its brief on August 9, 2005, and on September 29, 2005 NRG filed its brief. On October 28, 2005, the CFTC filed its reply brief.
Disputed Claims Reserve
      As part of the NRG plan of reorganization confirmed on November 24, 2003, NRG has funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, to the extent such claims are resolved now that NRG has emerged from bankruptcy, the claimants will be paid from the reserve on the same basis as if they had been paid out in the bankruptcy. That means that their allowed claims will be reduced to the same recovery percentage as other creditors would have received and will be paid in pro rata distributions of cash and common stock. We believe we have funded the disputed claims reserve at a sufficient level to settle the remaining unresolved proofs of claim we received during the bankruptcy proceedings. However, to the extent the aggregate amount of these payouts of disputed claims ultimately exceeds the amount of the funded claims reserve, we are obligated to provide additional cash, notes and common stock to the claimants. We will continue to monitor our obligation as the disputed claims are settled. If excess funds remain in the disputed claims reserve after payment of all obligations, such amounts will be reallocated to the creditor pool. NRG has contributed common stock and cash to an escrow agent to complete the distribution and settlement process.

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Since NRG has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from its balance sheet. Similarly, NRG removed the obligations relevant to the claims from its balance sheet when the common stock was issued and cash contributed.
Properties
      For a description of our interests in independent power production and cogeneration facilities, see “—Regional Business Descriptions— Texas (ERCOT)— Facilities,” “—Regional Business Descriptions—Northeast Region— Facilities,” “—Regional Business Descriptions—South Central Region— Facilities,” “—Regional Business Descriptions—Western Region— Facilities,” “—Regional Business Descriptions—Other— Other North American Assets” and “—Regional Business Descriptions—Other— Australia and All Other Generation and Non-Generation Assets.”
      Listed below are descriptions of our interests in thermal and chilled water facilities as of September 30, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	%	 	 	 	
 	 	Date of	 	 	 	 	Ownership	 	 	Thermal Energy	
Name and Location of Facility	 	Acquisition	 	 	Generating Capacity(1)	 	Interest	 	 	Purchaser/MSW Supplier	
 	 	 	 	 	 	 	 	 	 	 	
NRG Energy Center
Minneapolis, MN	 	 	1993	 	 	Steam: 1,203 mmBtu/hr. (353 MWt) Chilled Water: 41,630 tons (146 MWt)	 	 	100	%	 	Approx. 100 steam customers and 47 chilled water customers	
NRG Energy Center
San Francisco, CA	 	 	1999	 	 	Steam: 482 mmBtu/Hr. (141 MWt)	 	 	100	%	 	Approx. 165 steam customers	
NRG Energy Center
Harrisburg, PA	 	 	2000	 	 	Steam: 440 mmBtu/hr. (129 MWt) Chilled water: 2,400 tons (8 MWt)	 	 	100	%	 	Approx. 265 steam customers and 3 chilled water customers	
NRG Energy Center
Pittsburgh, PA	 	 	1999	 	 	Steam: 266 mmBtu/hr. (78 MWt) Chilled water: 12,580 tons (44 MWt)	 	 	100	%	 	Approx. 25 steam and 25 chilled water customers	
NRG Energy Center
San Diego, CA	 	 	1997	 	 	Chilled water: 7,425 tons (26 MWt)	 	 	100	%	 	Approx. 20 chilled water customers	
NRG Energy Center
St. Paul , MN	 	 	1992	 	 	Steam: 430 mmBtu/hr. (126 MWt)	 	 	100	%	 	Rock-Tenn Company	
Camas Power Boiler,
Washington	 	 	1997	 	 	Steam: 200 mm Btu/hr. (59 MWt)	 	 	100	%	 	Georgia-Pacific Corp.	
NRG Energy Center
Dover, DE	 	 	2000	 	 	Steam: 190 mmBtu/hr. (56 MWt)	 	 	100	%	 	Kraft Foods Inc.	
NRG Energy Center
Oak Park Heights, MN	 	 	1992	 	 	Steam: 200 mmBtu/Hr. (59 MWt)	 	 	100	%	 	Andersen Corp., MN
Correctional Facility	

(1) 	Thermal production and transmission capacity is based on 1,000 Btus per pound of steam production or transmission capacity. The unit mmBtu is equal to one million Btus.	
     Listed below are descriptions of our significant resource recovery assets as of September 30, 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	%	 	 	 	
Name and Location	 	Date of	 	 	 	 	Ownership	 	 	 	
of Facility	 	Acquisition	 	 	Processing Capacity(1)	 	Interest	 	 	MSW Supplier	
 	 	 	 	 	 	 	 	 	 	 	
Newport, MN(1)	 	 	1993	 	 	MSW: 1,500 tons/day	 	 	100	%	 	Ramsey and Washington Counties	
Elk River, MN(2)	 	 	2001	 	 	MSW: 1,500 tons/day	 	 	85	%	 	Anoka, Hennepin and Sherburne Counties; Tri-County Solid Waste Management Commissioner	

(1) 	The Newport facilities are strictly related to garbage-sorting facilities.	

(2) 	For the Elk River facility, NRG’s 85% interest is related strictly to garbage-sorting facilities.	
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     In addition, we own various real property and facilities relating to our generation assets, other vacant real property unrelated to our generation assets, interests in other construction projects in various states of completion and properties not used for operational purposes. We believe we have satisfactory title to our plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in our opinion, would not have a material adverse effect on the use or value of our portfolio.
      We lease our corporate offices at 211 Carnegie Center, Princeton, New Jersey 08540 and various other office spaces, including a 66 month lease of approximately 50,000 square feet in Houston, Texas, which serves as our regional headquarters for the ERCOT market.

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MANAGEMENT
Directors and Certain Officers of NRG
      The following table sets out the names and ages of each of our directors and certain of our officers, after giving effect to the Acquisition, followed by a description of their business experience:
 	 	 	 	 	 	 	
Name	 	Age	 	 	Position	
 	 	 	 	 	 	
Directors	 	 	 	 	 	 	
Howard E. Cosgrove	 	 	62	 	 	Director, Chairman of the Board	
John F. Chlebowski	 	 	60	 	 	Director and Chair, Audit Committee	
Lawrence S. Coben	 	 	47	 	 	Director and Chair, Compensation Committee	
David Crane	 	 	47	 	 	President, Chief Executive Officer and	
 	 	 	 	 	 	Director	
Stephen L. Cropper	 	 	55	 	 	Director and Chair, Commercial Operations Oversight Committee	
Maureen Miskovic	 	 	47	 	 	Director	
Anne C. Schaumburg	 	 	56	 	 	Director	
Herbert H. Tate	 	 	52	 	 	Director	
Thomas H. Weidemeyer	 	 	58	 	 	Director	
Walter R. Young	 	 	61	 	 	Director and Chair, Governance and Nominating Committee	
Officers	 	 	 	 	 	 	
David Crane	 	 	47	 	 	President, Chief Executive Officer and Director	
Robert C. Flexon	 	 	47	 	 	Executive Vice President and Chief Financial Officer	
Caroline Angoorly	 	 	41	 	 	Vice President, Environmental and New Business	
John P. Brewster	 	 	52	 	 	Executive Vice President, International Operations and President, South Central Region	
Scott J. Davido	 	 	44	 	 	Executive Vice President and President, Northeast Region	
Kevin T. Howell	 	 	48	 	 	Executive Vice President, Commercial Operations	
James J. Ingoldsby	 	 	48	 	 	Vice President and Controller	
Christine A. Jacobs	 	 	53	 	 	Vice President, Plant Operations	
Timothy W.J. O’Brien	 	 	47	 	 	Vice President and General Counsel	
George P. Schaefer	 	 	55	 	 	Vice President and Treasurer	
Steve Winn	 	 	40	 	 	Executive Vice President and President, Texas Region	
Board of Directors
      The Board is divided into three classes serving staggered three-year terms. Directors for each class are elected at our annual meeting of stockholders held in the year in which the term for their class expires. There are no family relationships among our officers and directors.
Class I Directors (Terms expire in 2007)
     David Crane
     Member of Commercial Operations Oversight Committee
      Mr. Crane has served as the President, Chief Executive Officer and a director of NRG since December 2003. Prior to joining NRG, Mr. Crane served as Chief Executive Officer of International Power PLC, a UK-

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domiciled wholesale power generation company, from January 2003 to November 2003, and as Chief Operating Officer from March 2000 through December 2002. Mr. Crane was Senior Vice President— Global Power New York at Lehman Brothers Inc., an investment banking firm, from January 1999 to February 2000, and was Senior Vice President— Global Power Group, Asia (Hong Kong) at Lehman Brothers from June 1996 to January 1999.
     Stephen L. Cropper
     Chair of Commercial Operations Oversight Committee
      Mr. Cropper has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Mr. Cropper spent 25 years with The Williams Companies, an energy company, before retiring in 1998 as President and Chief Executive Officer of Williams Energy Services. Mr. Cropper is a director of Berry Petroleum Company, Sunoco Logistics Partners L.P. and Rental Car Finance Corporation, a subsidiary of Dollar Thrifty Automotive Group and QuikTrip Corporation.
     Maureen Miskovic
     Member of Commercial Operations Oversight Committee
      Ms. Miskovic has been a Director of NRG since September 2005. She currently serves as Chief Operating Officer of the Eurasia Group, a research and consulting firm focusing on political-risk analysis and industry research for global markets, where she oversees the firm’s continued expansion and serves as chief advisor for the company’s political risk services. She also acts as the principal liaison for Eurasia Group’s joint venture with Deutsche Bank, which includes the DESIX, the first global political risk index on Wall Street. Miskovic joined Eurasia Group in September 2002 after six years with Lehman Brothers, where she was Managing Director and Chief Global Risk Officer. Prior to joining Lehman Brothers, Miskovic was Treasurer at Morgan Stanley in London and before that she held various positions with SG Warburg, also in London.
     Thomas H. Weidemeyer
     Member of Compensation Committee
      Mr. Weidemeyer has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Until his retirement in December 2003, Mr. Weidemeyer served as Director, Senior Vice President and Chief Operating Officer of United Parcel Service, Inc., the world’s largest transportation company and President of UPS Airlines. Mr. Weidemeyer became Manager of the Americas International Operation in 1989, and in that capacity directed the development of the UPS delivery network throughout Central and South America. In 1990, Mr. Weidemeyer became Vice President and Airline Manager of UPS Airlines and in 1994 was elected its President and Chief Operating Officer. Mr. Weidemeyer became Senior Vice President and a member of the Management Committee of United Parcel Service, Inc. that same year, and he became Chief Operating Officer of United Parcel Service, Inc. in 2001. Mr. Weidemeyer also serves as a director of Goodyear Tire & Rubber Co. and Waste Management, Inc.
Class II Directors (Terms expire in 2008)
     Lawrence S. Coben
     Chair of Compensation Committee
      Mr. Coben has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. He is Chairman and CEO of Tremisis Energy Acquisition Corporation. From January 2001 to January 2004, he was a Senior Principal of Sunrise Capital Partners, a private equity firm. From 1997 to 2001, Mr. Coben was an independent consultant. From 1994 to 1996, Mr. Coben was Chief Executive Officer of Bolivian Power Company. Mr. Coben is also a director of Prisma Energy.

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     Herbert H. Tate
     Member of Governance and Nominating Committee
      Mr. Tate has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Mr. Tate joined NiSource, Inc. as Corporate Vice President, Regulatory Strategy in July 2004. He was Of Counsel of Wolf & Samson P.C., a law firm, since September 2002 to July 2004. Mr. Tate was Research Professor of Energy Policy Studies at the New Jersey Institute of Technology from April 2001 to September 2002 and President of New Jersey Board of Public Utilities from 1994 to March 2001. Mr. Tate is also a director of IDT Capital and IDT Spectrum. Previously, Mr. Tate was a member of the Board of Directors for Central Vermont Public Service from April 2001 to June 2004, where he was a member of the Audit Committee.
     Walter R. Young
     Chair of Governance and Nominating Committee
      Mr. Young has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Mr. Young was Chairman, Chief Executive Officer and President of Champion Enterprises, Inc., an assembler and manufacturer of manufactured homes, from May 1990 to June 2003. Mr. Young has held senior management positions with The Henley Group, The Budd Company and BFGoodrich.
Class III Directors (Terms expire in 2006)
     John F. Chlebowski
     Chair of Audit Committee
     Member of Governance and Nominating Committee
      Mr. Chlebowski has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Mr. Chlebowski served as the President and Chief Executive Officer of Lakeshore Operating Partners, LLC, a bulk liquid distribution firm, from March 2000 until his retirement in December 2004. From July 1999 until March 2000, Mr. Chlebowski was a senior executive and cofounder of Lakeshore Liquids Operating Partners, LLC, a private venture firm in the bulk liquid distribution and logistics business, and from January 1998 until July 1999, he was a private investor and consultant in bulk liquid distribution. Prior to that, he was employed by GATX Terminals Corporation, a subsidiary of GATX Corporation, as President and Chief Executive Officer from 1994 until 1997. Mr. Chlebowski is a director of Laidlaw International Inc.
     Howard E. Cosgrove
     Chairman of the Board
     Member of Audit Committee
      Mr. Cosgrove has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization, and Chairman of the Board since December 2003. He was Chairman and Chief Executive Officer of Conectiv and its predecessor Delmarva Power and Light from December 1992 to August 2002. Prior to December 1992, Mr. Cosgrove held various positions with Delmarva Power and Light including Chief Operating Officer and Chief Financial Officer. Mr. Cosgrove serves as Chairman of the Board of Trustees at the University of Delaware.
     Anne C. Schaumburg
     Member of Audit Committee
      Ms. Schaumburg has been a director of NRG since April 2005. From 1984 until her retirement in 2002, she was at Credit Suisse First Boston in the Global Energy Group, where she last served as Managing Director. From 1979 to 1984, she was in the Utilities Group at Dean Witter Financial Services Group, where she last served as Managing Director. From 1971 to 1978, she was at The First Boston Corporation in the Public Utilities Group.

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Certain Officers
      Our officers are elected by our board of directors annually to hold office until their successors are elected and qualified.
     David Crane
     President and Chief Executive Officer
      For biographical information for David Crane, see “— Board of Directors.”
     Robert C. Flexon
     Executive Vice President and Chief Financial Officer
      Mr. Flexon has been Executive Vice President and Chief Financial Officer of NRG since March 2004. In this capacity, he manages NRG’s corporate finance, accounting, tax, risk management, information technology, and overall internal control program. Prior to joining NRG, Mr. Flexon was Vice President, Corporate Development & Work Process and Vice President, Business Analysis and Controller of Hercules, Inc. for four years. Mr. Flexon also held various financial management positions, including General Auditor, Franchise Manager and Controller, during his 13 years with Atlantic Richfield Company. Mr. Flexon began his career with the former Coopers & Lybrand public accounting firm.
     Caroline Angoorly
     Vice President, Environmental and New Business
      Ms. Angoorly has served as Vice President, Environmental & New Business for NRG since May 2004. She is responsible for our strategy and initiatives in the environmental and green business arenas. Prior to joining NRG, Ms. Angoorly served as Vice President and General Counsel at Enel North America, Inc., a Director and the Chief Financial Officer at Line56Media, and a partner in the Global Project Finance Group at Milbank, Tweed, Hadley & McCloy. Ms. Angoorly holds a Bachelor of Science degree in Geology and a Bachelor of Laws degree from Monash University in Melbourne, Australia. She also holds a Master of Business Administration degree, with an emphasis on international finance and economics, from Melbourne and Columbia Business Schools.
     John P. Brewster
     Executive Vice President, International Operations and President, South Central Region
      Mr. Brewster has been Executive Vice President, International Operations and President, South Central Region of NRG since March 2004. He is responsible for managing the asset portfolio for NRG’s South Central Region and international operations. Previously, he served as Vice President, Worldwide Operations of NRG, Vice President, North American Operations and Vice President of Production for NRG Louisiana Generating, Inc. Prior to joining NRG, Mr. Brewster spent 22 years with Cajun Electric Power Cooperative where he served as Vice President of Production, Manager of Power System Operations and Assistant Plant Manager.
     Scott J. Davido
     Executive Vice President and President, Northeast Region
      Mr. Davido has been Executive Vice President and President, Northeast Region of NRG since March 2004 and served as Senior Vice President, General Counsel and Secretary from October 2002 to March 2004. Mr. Davido also served as Chairman of the Board from May 2003 to December 2003, the period in which NRG was reorganizing under chapter 11 of the bankruptcy code. He served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary of the Elder-Beerman Stores Corp., a department store retailer, from March 1999 to May 2002 and Senior Vice President, General Counsel from January 1998 to March 1999. Mr. Davido was a Partner, Business Practice Group with Jones, Day, Reavis & Pogue, a law firm, in Pittsburgh, Pennsylvania, from January 1997 to December 1997 and an Associate, Business Practice

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Group from September 1987 to December 1996. On January 25, 2006, Mr. Davido submitted his resignation effective January 31, 2006.
     Kevin T. Howell
     Executive Vice President, Commercial Operations
      Mr. Howell has been Executive Vice President, Commercial Operations since August 2005 and is responsible for the commercial management of the North America asset portfolio. Prior to joining NRG, he served as President of Dominion Energy Clearinghouse since 2001. From 1995 to 2001, Mr. Howell held various positions within Duke Energy companies including Senior Vice President of Duke Energy Trading and Marketing, Senior Vice President of Duke Energy International, and most recently, Executive Vice President of Duke Energy Merchants where he managed a global trading group dealing in refined products, LNG and coal. Prior to his five years at Duke, Mr. Howell worked in a variety of trading, marketing and operations functions at MG Natural Gas Corp., Associated Natural Gas and Panhandle Eastern Pipeline.
     James J. Ingoldsby
     Vice President and Controller
      Mr. Ingoldsby has been Vice President and Controller of NRG since May 2004. He is responsible for directing NRG’s financial accounting and reporting activities, as well as ensuring our compliance with Sarbanes-Oxley legislation. Mr. Ingoldsby, who led the Sarbanes-Oxley implementation at chemical company Hercules, Inc., previously held various executive positions at GE Betz, formerly BetzDearborn from May 1993 to April 2003, including serving as Controller and Director of Business Analysis and Director of Financial Reporting. He also held various staff and managerial accounting and auditing positions at Mack Trucks, Inc from February 1982 to May 1993. Mr. Ingoldsby began his career with Deloitte and Touche where he became a Certified Public Accountant.
     Christine A. Jacobs
     Vice President, Plant Operations
      Ms. Jacobs has been Vice President, Plant Operations of NRG since September 2004. She is responsible for domestic plant operations, including safety, physical security, engineering and procurement, and application of best operating practices. Ms. Jacobs has more than 30 years of diverse operating and commercial management experience. Prior to joining NRG, she served as Executive Vice President, Facility Services/ Healthcare Management for Aramark Corporation from 2003 to 2004. Additionally, Ms. Jacobs served as Senior Vice President, Exelon Generation, and President, Exelon Power from 2000 to 2002.
     Timothy W.J. O’Brien
     Vice President and General Counsel
      Mr. O’Brien has been Vice President and General Counsel of NRG since April 2004. He is responsible for legal affairs at the Company. He served as Secretary from April 2004 to July 2005, as Deputy General Counsel of NRG from 2000 to 2004 and Assistant General Counsel from 1996 to 2000. Prior to joining NRG, Mr. O’Brien was an associate at Sheppard, Mullin, Richter & Hampton in Los Angeles and San Diego, California.
     George P. Schaefer
     Vice President and Treasurer
      Mr. Schaefer has been Vice President and Treasurer since December 2002. He is responsible for all treasury functions, including bank relations and corporate and project finance activities. Prior to joining NRG, Mr. Schaefer served as Senior Vice President, Finance and Treasurer for PSEG Global, Inc., an operator of power plants and utilities, for one year, Vice President of Enron North America in its independent energy unit from June 2000 to April 2001 and Vice President and Treasurer of Reliant Energy International, an operator of power plants and utilities, from June 1995 to June 2000. Prior to 1995, he was the Vice President, Business

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Development for Entergy Power Group and held the Senior Vice President, Structured Finance Group position with General Electric Capital Corporation.
     Steve Winn
     Executive Vice President and President, Texas Region
      Mr. Winn was named Executive Vice President of NRG and, upon the closing of the Acquisition, President, Texas Region. He served as Vice President, Mergers and Acquisitions from April 2005 to December 2005 and as Director, Mergers and Acquisitions from November 2004, when he joined NRG, to April 2005. Prior to joining NRG, Mr. Winn worked in Power and Energy Investment Banking at Lehman Brothers and Salomon Brothers. He has a Masters of Business Administration from Cornell University’s Johnson School of Management, and a Bachelor of Arts in Economics from the University of California at Berkeley.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Acquisition Agreement
      Pursuant to the Acquisition Agreement, the direct and indirect owners of equity units of Texas Genco, or the Sellers, will receive approximately $6.121 billion comprised of $4.399 billion in cash, subject to adjustment, a minimum of 35,406,320 shares of NRG common stock and, at NRG’s election, either an additional 9,038,125 shares of NRG common stock, additional cash, shares of NRG preferred stock or a combination of the foregoing. We have elected to pay this amount in cash. The Sellers will be prohibited from transferring the shares of common stock and preferred stock that they receive in connection with the Acquisition for 180 days following the closing date of the Acquisition.
Investor Rights Agreement
      NRG and the Sellers will enter into an Investor Rights Agreement, dated the closing date of the Acquisition, pursuant to which NRG will file an “evergreen” shelf registration statement, registering for resale upon expiration of the 180-day lock-up period by the Sellers the shares of common stock and preferred stock that they will receive pursuant to the Acquisition Agreement on or before the date 120 days from the closing date of the Acquisition. Any Seller or group of Sellers holding in excess of 3% of the aggregate number of shares of NRG common stock issued and outstanding, or 20% of the aggregate number of shares of preferred stock originally issued pursuant to the Acquisition Agreement, may request that a resale under the shelf registration statement involve an underwritten offering, and NRG will use its commercially reasonable efforts to make its executive officers available to participate in “road shows” or other selling efforts reasonably requested by the Sellers, not to exceed one “road show” per 180-day period. The Sellers will also be entitled to include shares of NRG common stock and preferred stock they receive pursuant to the Acquisition Agreement on any registration statement filed by NRG that would permit registration of such shares of common stock and preferred stock for sale to the public.
      In addition, until the second anniversary of the closing date of the Acquisition, the Sellers will agree not to acquire any additional voting securities of NRG (subject to certain exceptions), make any public announcement with respect to, or submit any proposal for, any merger, dissolution or restructuring involving NRG or any of its subsidiaries, solicit proxies to vote any voting security of NRG or seek to influence the vote of any voting securities of NRG, join, form or participate in any group with respect to voting securities of NRG, seek to call a meeting or execute a written consent of the stockholders of NRG, seek representation on NRG’s board of directors or seek removal of a director from the board. Certain Sellers will have the right to consult with and advise management of NRG on matters relating to its operation. NRG will agree to consider in good faith the reasonable recommendations of such Sellers, but ultimate discretion with respect to all matters will remain with NRG.

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DESCRIPTION OF CAPITAL STOCK
      The description below summarizes the more important terms of our capital stock and does not purport to be complete. We have previously filed with the SEC copies of our amended and restated certificate of incorporation, our amended and restated by-laws, our registration statement on Form 8-A and certificates of designations for each series of our outstanding preferred stock. See “Where You Can Find More Information.” You should refer to those documents for the complete terms of our capital stock.
Authorized Capital
      Our amended and restated certificate of incorporation provides that we have authority to issue 500,000,000 shares of common stock, par value $0.01, of which approximately 80,701,888 shares were outstanding on January 3, 2006, and 10,000,000 shares of preferred stock, par value $0.01 per share, of which 670,000 shares were outstanding on January 3, 2006. After giving effect to the Financing Transaction, we will have 101,556,945 shares of common stock outstanding (104,685,204 shares of common stock outstanding if the underwriters in this offering exercise their over-allotment option in full). In addition, after giving affect to the concurrent offering of mandatory convertible preferred stock, we will have 2,670,000 shares of preferred stock outstanding (2,970,000 shares of preferred stock outstanding if the underwriters exercise their over-allotment option in full). On January 3, 2006, 4,000,000 shares of common stock were reserved for issuance under stock incentive plans or pursuant to individual option grants or stock awards.
Common Stock
 	 	
 	Dividends	
      Except as otherwise provided by the Delaware General Corporation Law, or the DGCL, or our amended and restated certificate of incorporation, the holders of our common stock, subject to the rights of holders of any series of preferred stock, share ratably in all dividends as may from time to time be declared by our board of directors in respect of our common stock out of funds legally available for the payment thereof and payable in cash, stock or otherwise, and in all other distributions (including, without limitation, our dissolution, liquidation and winding up), whether in respect of liquidation or dissolution (voluntary or involuntary) or otherwise, after payment of liabilities and liquidation preference on any outstanding preferred stock.
 	 	
 	Voting Rights	
      Except as otherwise provided by the DGCL or our amended and restated certificate of incorporation and subject to the rights of holders of any series of preferred stock, all the voting power of our stockholders is vested in the holders of our common stock, and each holder of our common stock has one vote for each share held by such holder on all matters voted upon by our stockholders.
      Subject to the rights of holders of any outstanding shares of preferred stock to act by written consent, our stockholders may not take any action by written consent in lieu of a meeting and must take any action at a duly called annual or special meeting of stockholders.
      The affirmative vote of holders of at least two-thirds of the combined voting power of our outstanding shares eligible to vote in the election of directors is required to alter, amend or repeal provisions in the amended and restated certificate of incorporation regarding indemnification, classification of directors, action by written consent and changes to voting requirements applicable to such provisions.
 	 	
 	Other	
      Our common stock is not convertible into, or exchangeable for, any other class or series of our capital stock. Holders of our common stock have no preemptive or other rights to subscribe for or purchase additional securities of ours. We are subject to Section 203 of the DGCL. Shares of our common stock are not subject to calls or assessments. No personal liability will attach to holders of our common stock under the laws of the State of Delaware (our state of incorporation) or of the State of New Jersey (the state in which our principal place of business is located). All of the outstanding shares of our common stock are fully paid and nonassessable.

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 	Listing and Transfer Agent	
      Our common stock is listed and traded on the New York Stock Exchange under the symbol “NRG.” The transfer agent for the common stock is Wells Fargo Bank, N.A., 1-800-468-9716, or reachable, via email at website www.wellsfargo.com/shareownerservices.
Preferred Stock
 	 	
 	4% Convertible Perpetual Preferred Stock	
      On December 27, 2004, NRG completed the sale of 420,000 shares of Convertible Perpetual Preferred Stock with a dividend coupon rate of 4%. The 4% Preferred Stock has a liquidation preference of $1,000 per share. Holders of 4% Preferred Stock are entitled to receive, when declared by NRG’s board of directors, cash dividends at the rate of 4% per annum, payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year, commencing on March 15, 2005. The 4% Preferred Stock is convertible, at the option of the holder, at any time into shares of NRG common stock. On or after December 20, 2009, NRG may redeem, 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.
      If NRG is subject to a fundamental change, as defined in the Certificate of Designation of the 4% Preferred Stock, each holder of shares of 4% Preferred Stock has the right, subject to certain limitations, to require NRG to purchase any or all of its shares of 4% Preferred Stock at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends, including liquidated damages, if any, to the date of purchase. Final determination of a fundamental change must be approved by NRG’s board of directors or the board of directors must decide to take a neutral position with respect to such fundamental change.
      Each holder of 4% Preferred Stock has one vote for each share of 4% Preferred Stock held by the holder on all matters voted upon by the holders of NRG’s common stock, as well as voting rights specifically provided for in NRG’s amended and restated certificate of incorporation or as otherwise from time to time required by law. In addition, whenever (1) dividends on the 4% Preferred Stock or any other class or series of stock ranking on a parity with the 4% Preferred Stock with respect to the payment of dividends are in arrears for dividend periods, whether or not consecutive, containing in the aggregate a number of days equivalent to six calendar quarters, or (2) NRG fails to pay the redemption price on the date shares of 4% Preferred Stock are called for redemption or the purchase price on the purchase date for shares of 4% Preferred Stock following a fundamental change, then, in each case, the holders of 4% Preferred Stock (voting separately as a class with all other series of preferred stock upon which like voting rights have been conferred and are exercisable) are entitled to vote for the election of two of the authorized number of NRG’s directors at the next annual meeting of stockholders and at each subsequent meeting until all dividends accumulated or the redemption price on the 4% Preferred Stock have been fully paid or set apart for payment. The term of office of all directors elected by holders of the 4% Preferred Stock will terminate immediately upon the termination of the rights of the holders of the 4% Preferred Stock to vote for directors. Upon election of any additional directors, the number of directors that comprise NRG’s board of directors will be increased by the number of such additional directors.
      The 4% Preferred Stock is senior to all classes of common stock, on a parity with the 3.625% Preferred Stock and upon issuance, the Mandatory Convertible Preferred Stock and junior to all of NRG’s existing and future debt obligations and all of NRG’s subsidiaries’ existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries. The proceeds of $406.4 million, net of issuance costs of approximately $13.6 million, were used to redeem $375.0 million of Second Priority Notes on February 4, 2005.
 	 	
 	3.625% Convertible Perpetual Preferred Stock	
      On August 11, 2005, NRG issued 250,000 shares of its 3.625% Convertible Perpetual Preferred Stock, or 3.625% Preferred Stock, to Credit Suisse First Boston Capital LLC, or CSFB, in a private placement. The 3.625% Preferred Stock has a liquidation preference of $1,000 per share. Holders of the 3.625% Preferred

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Stock are entitled to receive, out of funds legally available, cash dividends at the rate of 3.625% per annum, payable in cash quarterly in arrears commencing on December 15, 2005. Each share of 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 cash and common stock. NRG may elect to make cash payment in lieu of delivering shares of 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.
      If NRG is subject to a fundamental change, as defined in the Certificate of Designation of the 3.625% Preferred Stock, each holder of shares of 3.625% Preferred Stock has the right, subject to certain limitations, to require NRG to purchase any or all of its shares of 3.625% Preferred Stock at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends, including liquidated damages, if any, to the date of purchase.
      The 3.625% Preferred Stock is senior to all classes of common stock, on a parity with the 4% Preferred Stock and upon issuance, the Mandatory Convertible Preferred Stock and junior to all of NRG’s existing and future debt obligations and all of NRG’s subsidiaries’ existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries. Title to the 3.625% Preferred Stock, may not be transferred to an entity that is not an affiliate of CSFB without the consent of NRG, such consent not to be unreasonably withheld. The proceeds were used to redeem $228.8 million of Second Priority Notes on September 12, 2005.
 	 	
 	Mandatory Convertible Preferred Stock	
      Concurrently with this offering, NRG is offering $500 million of its 5.75% Mandatory Convertible Preferred Stock, or Mandatory Convertible Preferred Stock, subject to the underwriters’ overallotment option. The Mandatory Convertible Preferred Stock is expected to have a liquidation preference of $250 per share. Dividends will accrue and cumulate on the Mandatory Convertible Preferred Stock from the date of issuance and, to the extent that we are legally permitted to pay dividends and our board of directors, or an authorized committee of our board of directors, declares a dividend payable, we will pay dividends in cash on March 15, June 15, September 15 and December 15 of each year prior to March 15, 2009 or the following business day if the 15th is not a business day. Each share of Mandatory Convertible Preferred Stock is expected to automatically convert on March 15, 2009 into a number of shares of common stock determined based on the price of our common stock at such time, and holders are expected to be entitled to receive an amount of cash equal to all accrued, cumulated and unpaid dividends. It is expected that, upon the occurrence of certain market conditions, NRG will be able to cause the conversion of all, but not less than all, shares of Mandatory Convertible Preferred Stock into shares of NRG common stock plus an amount of cash equal to all accrued, cumulated and unpaid dividends and the present value of all remaining future dividend payments on the Mandatory Convertible Preferred Stock through March 15, 2009. In addition, holders of the Mandatory Convertible Preferred Stock are expected to have the right to convert, at any time, the Mandatory Convertible Preferred Stock into shares of NRG common stock at the minimum conversion rate of 4.1356 shares of NRG common stock per share of Mandatory Convertible Preferred Stock plus an amount of cash equal to all accrued, cumulated and unpaid dividends. Holders are also expected to have the right to convert the Mandatory Convertible Preferred Stock upon certain merger events.
      Whenever dividends on the Mandatory Convertible Preferred Stock or any other class or series of stock ranking on a parity with the Mandatory Convertible Preferred Stock with respect to the payment of dividends are in arrears for dividend periods, whether or not consecutive, containing in the aggregate a number of days equivalent to six calendar quarters, then the holders of Mandatory Convertible Preferred Stock (voting separately as a class with all other series of preferred stock upon which like voting rights have been conferred and are exercisable) are entitled to vote for the election of two of the authorized number of NRG’s directors at the next annual meeting of stockholders and at each subsequent meeting until all dividends accumulated on the Mandatory Convertible Preferred Stock have been fully paid or set apart for payment. The term of office of all directors elected by holders of the Mandatory Convertible Preferred Stock will terminate immediately upon the termination of the rights of the holders of the Mandatory Convertible Preferred Stock to vote for

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directors. Upon election of any additional directors, the number of directors that comprise NRG’s board of directors will be increased by the number of such additional directors.
      The Mandatory Convertible Preferred Stock will be senior to all classes of common stock, on parity with the 4% Preferred Stock and the 3.625% Preferred Stock and junior to all of NRG’s existing and future debt obligations and all of NRG’s subsidiaries’ existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries.
Board of Directors; Classification of Directors
      Except as otherwise provided in our amended and restated certificate of incorporation or any duly authorized certificate of designations of any series of preferred stock, directors are elected by a plurality of the votes of the shares entitled to vote in the election of directors present in person or represented by proxy at the meeting of the stockholders at which directors are elected.
      At each annual meeting of stockholders, our directors are elected to hold office until the expiration of the term for which they are elected, and until their successors have been duly elected and qualified; except that if any such election is not so held, such election will take place at a stockholders’ meeting called and held in accordance with the DGCL. Our directors are divided into three classes as nearly equal in size as is practicable, designated Class I, Class II and Class III. At each annual meeting, directors to replace those of a class whose terms expire at such annual meeting will be elected to hold office until the third succeeding annual meeting and until their respective successors have been duly elected and qualified. If the number of directors is changed, any newly created directorships or decrease in directorships will be so apportioned among the classes as to make all classes as nearly equal in number as practicable.

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DESCRIPTION OF CERTAIN INDEBTEDNESS
New Senior Secured Credit Facility
      We plan to enter into a new senior secured credit facility for up to an aggregate amount of $5.575 billion to replace NRG’s existing senior secured credit facility. The new senior secured credit facility is expected to consist of a $3.575 billion senior first priority secured term loan facility, a $1.0 billion senior first priority secured revolving credit facility and a $1.0 billion senior first priority secured synthetic letter of credit facility.
      We plan to use initial borrowings under our new senior secured credit facility, together with the net proceeds from this offering, the offerings of common stock and mandatory convertible preferred stock and cash on hand, to finance the Acquisition, to repay certain of our and Texas Genco’s outstanding indebtedness and to pay related premiums, fees and expenses. See “Use of Proceeds.”
      The following is a summary description of the principal terms and conditions of the new senior secured credit facility. This description is not intended to be exhaustive and is qualified in its entirety by reference to the provisions that will be contained in the definitive credit agreement. As the final terms of the senior secured credit facility have not been agreed upon, the final terms may differ from those set forth herein and such differences may be significant.
      The senior secured credit facility’s $3.575 billion term facility will mature on the seventh anniversary of its closing date, and will amortize in 27 consecutive equal quarterly installments in an aggregate annual amount equal to 1.0% of the original principal amount of the term facility during the first 6 3 / 4  years thereof with the balance payable on the seventh anniversary thereof. The $1.0 billion synthetic letter of credit facility will mature on the seventh anniversary of the closing date of the senior secured credit facility. The $1.0 billion revolving facility will mature on the fifth anniversary of the closing date of the senior secured credit facility, and no amortization will be required in respect thereof. Up to $50 million of the revolving credit facility will be available as a swing-line facility; the full amount of the revolving facility is available for the issuance of letters of credit.
      The revolving credit facility is expected to be undrawn at the time of closing.
 	 	
 	Guarantees and Collateral	
      The senior secured credit facility will be guaranteed by substantially all of our existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries and certain other subsidiaries. In addition, it will be secured by liens on substantially all of the assets of NRG and the assets of its 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 our subsidiaries, with certain exceptions for unrestricted subsidiaries, foreign subsidiaries and project subsidiaries, will be pledged for the benefit of the senior secured credit facility lenders.
      In addition to the foregoing, the senior secured credit facility will be secured by a first-priority perfected security interest in all of the property and assets owned at-any time or acquired by NRG and its subsidiaries, other than (a) the assets of certain unrestricted subsidiaries excluded project subsidiaries, foreign subsidiaries and certain other subsidiaries, and (b) (i) any lease, license, contract, property right or agreement of NRG or any subsidiary guarantor, if and only for so long as the grant of a security interest under the security documents would result in a breach, termination or default under that lease, license, contract, property right or agreement; (ii) certain interests in real property owned or leased by NRG and certain subsidiary guarantors; (iii) equity interests in certain of NRG’s project affiliates that have non-recourse debt financing; (iv) any voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of our foreign subsidiaries; and (v) certain other limited exceptions.

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 	Interest	
      At NRG’s option, loans under the senior secured credit facility will be available as “Alternate Base Rate” loans or “Eurodollar” loans, as follows:
 	 	 	
 	• 	Alternate Base Rate loans. Interest is expected to be at a spread (the “Applicable Margin”) over the Alternate Base Rate for term loans and for revolving loans and swing-line loans, calculated on a 365-day or 366-day basis, as the case may be, when the Alternate Base Rate is determined by reference to the prime rate, and on a 360-day basis at all other times. The “Alternate Base Rate” shall mean, for any day, a rate per annum equal to the greater of (a) the “prime rate” publicly announced from time to time by The Wall Street Journal as the “base rate on corporate loans posted by at least 75% of the nation’s 30 largest banks” and (b) the federal funds effective rate in effect on such day plus 1 / 2  of 1%.	
 	 	 	
 	• 	Eurodollar loans. Interest will be determined for periods to be selected by NRG, or “interest periods,” of seven days, one, two, three or six months and, to the extent available to all of the lenders, nine or twelve months, and is expected be at a spread (the “Applicable Margin”) over the Adjusted LIBO Rate for term loans and for revolving loans and swing-line loans, calculated on a 360-day basis. The “Adjusted LIBO Rate” shall mean, with respect to any Eurodollar loan for any interest period and as determined from time to time, an interest rate per annum equal to the product of (a) the rate per annum determined by the Administrative Agent at approximately 11:00 a.m., London time, on the date that is two business days prior to the commencement of the relevant interest period by reference to the British Bankers’ Association Interest Settlement Rates for deposits in dollars (as set forth by the Bloomberg Information Service or any successor thereto or any other service selected by the Administrative Agent which has been nominated by the British Bankers’ Association as an authorized information vendor for the purpose of displaying such rates) for a period equal to the relevant interest period and (b) certain statutory reserves as agreed upon in the senior secured credit facility.	
      The “Applicable Margin” shall mean, for any day, for each type of loan, the rate per annum set forth under the relevant column heading below based upon the consolidated senior leverage ratio of NRG as of the relevant date of determination:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Consolidated Senior	 	Eurodollar Term	 	 	 	 	Eurodollar	 	 	ABR Revolving Loans	 	
Leverage Ratio	 	Loans	 	 	ABR Term Loans	 	 	Revolving Loans	 	 	and Swingline Loans	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Category 1	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Greater than 3.50 to 1.00	 	 	2.0	%	 	 	1.0	%	 	 	2.00	%	 	 	1.00	%	
Category 2	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Greater than 3.00 to 1.00 but less than or equal to 3.50 to	 	 	1.75	%	 	 	0.75	%	 	 	1.75	%	 	 	0.75	%	
Category 3	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Less than or equal to 3.00 to 1.00	 	 	1.75	%	 	 	0.75	%	 	 	1.50	%	 	 	0.50	%	
      Interest on the loans will be payable (a) with respect to any Alternate Base Rate Loan (other than a Swingline Loan), on the last business day of each March, June, September and December (beginning with March 31, 2006), (b) with respect to any Eurodollar Loan, the last day of the interest period applicable to such loan is a part and, in the case of a Eurodollar Loan with an interest period of more than three months’ duration, each day that would have been an interest payment date had successive interest periods of three months’ duration been applicable to such loan, and (c) with respect to any swingline loan, the day that such loan is required to be repaid. Until NRG delivers certain financial statements and certificates for the period ended on the first fiscal quarter after the closing date of the senior secured credit agreement, category 1 will apply for purposes of determining the Applicable Margin.
      The synthetic letters of credit will be issued by an issuing bank. The synthetic letter of credit issuing bank will invest amounts in a “synthetic L/ C account” in certain agreed upon permitted investments. On the last

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business day of March, June, September and December of each year (beginning with March 31, 2006): (i) the synthetic letter of credit issuing bank will distribute to each lender under the synthetic letter of credit facility its pro rata share of any interest accrued on funds held in the synthetic L/C Account and (ii) NRG will pay to the synthetic letter of credit issuing bank for pro rata remittance to each lender under the synthetic letter of credit facility a fee based on such lender’s total commitment (without regard to actual amount of letters of credit outstanding) times the interest rate applicable to the loans under the term facility (assuming one-month LIBOR) as specified in above (net of the amounts received by such lender pursuant to clause (i) above). In addition, NRG will pay the synthetic letter of credit issuing bank a fronting fee in an amount to be agreed and customary issuance and administrative fees.
 	 	
 	Default Interest and Fees	
      If NRG defaults on the payment of the principal of or interest on any loan or any other amount becoming due and payable hereunder or under any other loan document related to the senior secured credit facility, then NRG shall on demand from time to time pay interest, to the extent permitted by law, on such defaulted amount (a) in the case of overdue principal, at the rate otherwise applicable to such loan plus 2.00% per annum and (b) in all other cases, at a rate per annum equal to the rate that would be applicable to an Alternate Base Rate term loan plus 2.00%.
 	 	
 	Commitment and Letter of Credit Fees	
      Commitment fees equal to 0.5% per annum times the daily average undrawn portion of the revolving facility will accrue from the closing date and shall be payable quarterly in arrears.
      A fee equal to (i) the Applicable Margin then in effect for loans bearing interest at the Adjusted LIBO Rate made under the revolving facility, times (ii) the average daily maximum aggregate amount available to be drawn under all letters of credit, will be payable quarterly in arrears to the lenders under the revolving facility. In addition, a fronting fee, to be agreed upon between the issuer of each letter of credit and NRG, will be payable to such issuer, as well as certain customary fees.
 	 	
 	Covenants	
      The senior secured credit facility will contain affirmative and negative covenants customary for a transaction of this type which, among other things, require us to meet certain financial tests, including a minimum interest coverage ratio and a maximum leverage ratio, each at the NRG level and on a consolidated basis. The senior secured credit facility will also contain covenants which, among other things, limit:
 	 	 	
 	•	indebtedness (including guarantees and other contingent obligations);	
 	 	 	
 	•	liens;	
 	 	 	
 	•	sale and lease-back transactions;	
 	 	 	
 	•	investments, loans and advances;	
 	 	 	
 	•	mergers, acquisitions, consolidations and asset sales;	
 	 	 	
 	•	dividends and other restricted payments;	
 	 	 	
 	•	transactions with affiliates;	
 	 	 	
 	•	business activities and hedging agreements;	
 	 	 	
 	•	limitations on debt payments;	
 	 	 	
 	•	capital expenditures;	
 	 	 	
 	•	changes to the terms of any material indebtedness that materially increase the obligations of the obligor or confer additional material rights to the holder of such indebtedness; and	
 	 	 	
 	•	other matters customarily restricted in such agreements.	
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 	Events of Default	
      Events of default under the senior secured credit facility include, but are not limited to:
 	 	 	
 	•	breaches of representations and warranties;	
 	 	 	
 	•	payment defaults;	
 	 	 	
 	•	noncompliance with covenants;	
 	 	 	
 	•	bankruptcy;	
 	 	 	
 	•	judgments in excess of a specified amount;	
 	 	 	
 	•	any confirmation order that is reversed, amended or modified in any material respects, vacated or stayed;	
 	 	 	
 	•	any event that could result in our liability under the Employee Retirement Income Security Act of 1974 in excess of a specified amount;	
 	 	 	
 	•	failure of any guarantee or pledge agreement supporting the senior secured credit facility to be in full force and effect;	
 	 	 	
 	•	failure of any lien created in favor of the loan parties to be a valid, perfected and first priority lien on any material collateral securing the senior secured credit facility; and	
 	 	 	
 	•	a change of control, as such term is defined in the senior secured credit facility.	
Bridge Loan Facility
      NRG has entered into the commitment letter with the bridge lenders pursuant to which the bridge lenders have committed to provide NRG with up to $5.1 billion in bridge financing to fund all necessary amounts not provided for under the new senior secured credit facility. NRG does not intend to draw down on the bridge loan facility unless this offering, the common stock offering and/or the mandatory convertible preferred stock offering are not consummated at the time of the closing of the Acquisition.
      The bridge loans will mature one year from the date they are issued. Upon the maturity date, if any bridge loan has not been repaid in full, and provided no payment or bankruptcy default has occurred under the bridge loans or the new senior secured credit facility, the bridge loan will automatically be converted into a term loan due on the 10-year anniversary of the closing date of the Acquisition. Subject to certain exceptions, the net proceeds from (i) any public offering or private placement of securities of NRG or its subsidiaries, (ii) any future bank borrowings under the new senior secured credit facility or (iii) any future asset sale will be used to repay the bridge loans at a price equal to 100% of the principal amount plus accrued and unpaid interest. The bridge loans may be prepaid at any time at the option of NRG at a price equal to 100% of the principal amount plus accrued and unpaid interest. Subject to customary exceptions, the bridge loans will be guaranteed on a senior first priority basis by each of NRG’s current and future domestic subsidiaries, excluding certain foreign, project and immaterial subsidiaries. The bridge loans will initially bear interest at a per annum rate equal to (a) at NRG’s option (i) the reserve adjusted Eurodollar rate or (ii) the base rate, as in effect from time to time, in each case, calculated on the basis of the actual number of days elapsed in a year of 360 days (365/366 day year with respect to loans bearing interest with reference to the base rate), plus (b) a spread of 500 basis points in the case NRG elects the Eurodollar option and 400 basis points in the case NRG elects the base rate option. If the bridge loans are not repaid in whole within six months following the closing date of the Acquisition, the spread will increase by 100 basis points at the end of such six-month period and will increase by an additional 50 basis points at the end of each three-month period thereafter.
      The bridge loans will contain customary events of default and covenants by NRG. Certain terms of the bridge loan facility may vary after the date of this prospectus supplement to facilitate the syndication of the facility. The commitment letter is subject to customary conditions to consummation, including the absence of any event or circumstance that would have a material adverse effect on the business, assets, properties,

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liabilities, condition (financial or otherwise) or results of operations, taken as a whole, of Texas Genco, or Texas Genco and NRG combined, since June 30, 2005.
Xcel Note
      On December 5, 2003, we entered into a $10.0 million promissory note with Xcel Energy. The note accrues interest at a rate of 3% per year, payable quarterly in arrears. All principal is due at maturity on June 5, 2006.
New Senior Notes
      Concurrently with this offering, NRG intends to offer an aggregate principal amount of $3.6 billion of New Senior Notes which will consist of 7.250% senior notes due 2014, and 7.375% senior notes due 2016. The net proceeds of the New Senior Notes offering (after payment of underwriting discounts and commissions) will be placed into an escrow account held by the trustee of the New Senior Notes, as escrow agent, until the consummation of the Acquisition. The New Senior Notes will be general unsecured obligations of NRG guaranteed jointly and severally by each of NRG’s current and future restricted subsidiaries, excluding certain foreign, project and immaterial subsidiaries.
      The New Senior Notes will rank pari passu in right of payment with all existing and future unsecured senior indebtedness of NRG and senior in right of payment to any future subordinated indebtedness of NRG. Because the New Senior Notes will be guaranteed by only certain of NRG’s subsidiaries, they will be structurally subordinated to all indebtedness and other liabilities, including trade payables, of those subsidiaries that do not guarantee the New Senior Notes.
      Interest on the 2014 fixed rate notes and 2016 fixed rate notes will be payable semi-annually in arrears. NRG may redeem some or all of the 2014 fixed rate notes at any time prior to February 1, 2010 at a price equal to 100% of the principal amount of the notes redeemed plus a “make-whole” premium and accrued and unpaid interest. NRG may redeem some or all of the 2016 fixed rate notes at any time prior to February 1, 2011 at a price equal to 100% of the principal amount of the notes redeemed plus a “make-whole” premium and accrued and unpaid interest. Prior to February 1, 2009, NRG may redeem up to 35% of the 2014 fixed rate notes issued under the applicable indenture with the net cash proceeds of certain equity offerings, provided at least 65% of the aggregate principal amount of the 2014 fixed rate notes issued in the concurrent offering of 2014 fixed rate notes remains outstanding after the redemption. Prior to February 1, 2009, NRG may redeem up to 35% of the 2016 fixed rate notes issued under the applicable indenture with the net cash proceeds of certain equity offerings, provided at least 65% of the aggregate principal amount of the 2016 fixed rate notes issued in the concurrent offering of 2016 fixed rate notes remains outstanding after the redemption. On or after February 1, 2010, NRG can redeem some or all of the 2014 fixed rate notes at specified redemption prices plus accrued interest. On or after February 1, 2011, NRG can redeem some or all of the 2016 fixed rate notes at specified redemption prices plus accrued interest. Upon the occurrence of a change of control, holders of the New Senior Notes will have the right, subject to certain conditions, to require NRG to repurchase their notes at a price equal to 101% of their principal amount plus accrued and unpaid interest to the date of repurchase. The New Senior Notes are also subject to a special mandatory redemption, at a redemption price equal to 100% of the aggregate principal amount of the New Senior Notes plus accrued interest to, but not including, the redemption date if the Acquisition is not consummated by September 30, 2006.
      The indenture governing the New Senior Notes contains covenants, which, among other things, limit NRG’s ability and the ability of NRG’s restricted subsidiaries to: (i) incur additional debt; (ii) declare or pay dividends, redeem stock or make other distributions to stockholders; (iii) create liens; (iv) make certain restricted investments; (v) enter into transactions with affiliates; (vi) sell or transfer assets; and (vii) consolidate or merge.
      Events of default under the indenture governing the New Senior Notes include, among other things, non-payment of interest of principal, bankruptcy, non-compliance with covenants, failure by NRG to comply with any material term of the escrow agreement or security agreement, failure of a subsidiary guarantee, escrow

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agreement, security agreement or lien to be held enforceable in a court of law or denial of obligations under a guarantee by a significant subsidiary, cross defaults on other indebtedness in the aggregate of $100 million or more and judgments for the payment of money in the aggregate of more than $100 million rendered against NRG, any restricted subsidiary or a combination thereof.
Credit Support and Collateral Arrangements
      In connection with our power generation business, we manage the commodity price risk associated with our supply activities and our electric generation facilities. This includes forward power sales, fuel and energy purchases and emission credits. In order to manage these risks, we enter into financial instruments to hedge the variability in future cash flows form forecasted sales of electricity and purchases of fuel and energy. We utilize a variety of instruments including forward contracts, futures contracts, swaps and options. Certain of these contracts allow counterparties to require the combined company to provide credit support. This credit support consists of letters of credit, cash, guarantees and junior liens on the ERCOT assets. As of September, 30, 2005, the combined company balances of the credit support provided in support of these contracts were $846 million for letters of credit, $631.4 million for cash margin, $152.4 million for parental guarantees and $2,181 million for junior liens on the assets in the ERCOT market.
      The following table shows the breakdown of the combined, after giving effect to the Acquisition and Financing Transactions, company balances of the credit support provided in support of the hedging contracts described above:
 	 	 	 	 	 	 	 	 	
 	 	September 30, 2005	 	December 31, 2005	
 	 	($ in millions)	 	($ in millions)	
 	 	 	 	 	
Letters of Credit(1)	 	$	846	 	 	$	831	 	
Cash Margin(1)	 	 	   631.4	 	 	 	   432.5	 	
Parental Guarantees(2)	 	 	   142.1	 	 	 	   167.1	 	
Junior Liens on ERCOT Assets	 	 	2,181	 	 	 	2,221	 	

(1) 	At December 31, 2005 and September 30, 2005, West Coast Power’s collateral posted totaled $48.4 million and $24.6 million, respectively and is not included in the table above. Of these amounts, letters of credit totaled $0 and $10.7 million, respectively and cash totaled $48.4 million and $13.9 million, respectively.	
 	 	
(2) 	Parental guarantees were provided by either NRG Energy, Inc. or Texas Genco LLC on behalf of their subsidiaries.	
     NRG expects that, at the closing of the Acquisition and the Financing Transactions, the collateral arrangements described above, including their respect to certain counterparties holding junior liens on the ERCOT assets, will remain in place or will be replaced with substitute collateral arrangements comprising an interest in a second lien position on substantially all of the NRG’s assets. On a going forward basis, NRG intends to secure some or all of its commodity hedging activities with interests in a second lien position on substantially all of NRG’s assets. There can be no assurance that this second lien position will provide enough capacity to cover all commodity hedges that are necessary or desirable for adequately hedging NRG’s commodity risk. See “Risk Factors—Risks Related to the Operation of our Business—We may not have sufficient liquidity to hedge market risks effectively.”

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MATERIAL U.S. FEDERAL TAX CONSIDERATIONS
FOR NON-U.S. HOLDERS OF OUR COMMON STOCK
      The following is a general discussion of the material U.S. federal income and estate tax considerations applicable to non-U.S. holders with respect to their ownership and disposition of shares of our common stock. This discussion is for general information only and is not tax advice. Accordingly, all prospective non-U.S. holders of our common stock should consult their own tax advisors with respect to the U.S. federal, state, local and non-U.S. tax consequences of the acquisition, ownership and disposition of our common stock. A “non-U.S. holder” means a beneficial owner of our common stock who is not for U.S. federal income tax purposes:
 	 	 	
 	•	an individual citizen or resident of the United States,	
 	 	 	
 	•	a corporation, partnership, or any other organization taxable for U.S. federal income tax purposes as a corporation or partnership created or organized in the United States or under the laws of the United States, any state thereof, or the District of Columbia,	
 	 	 	
 	•	an estate the income of which is included in gross income for U.S. federal income tax purposes regardless of its source, or	
 	 	 	
 	•	a trust if (1) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust or (2) a valid election is in place to treat the trust as a U.S. person.	
      This discussion is based on current provisions of the United States Internal Revenue Code of 1986, as amended, existing and proposed United States Treasury Regulations promulgated thereunder, current administrative rulings and judicial decisions, all of which are in effect as of the date of this prospectus and all of which are subject to change or to differing interpretation. Any change, which may or may not be retroactive, could alter the tax consequences to non-U.S. holders described in this prospectus. We assume in this discussion that a non-U.S. holder holds shares of our common stock as a capital asset (generally property held for investment).
      This discussion does not address all aspects of U.S. federal income and estate taxation that may be relevant to a particular non-U.S. holder in light of that non-U.S. holder’s individual circumstances nor does it address any aspects of U.S. state, local or non-U.S. taxes. This discussion also does not consider any specific facts or circumstances that may apply to a non-U.S. holder and does not address the special tax rules applicable to particular non-U.S. holders, such as:
 	 	 	
 	•	banks, insurance companies, or other financial institutions;	
 	 	 	
 	•	tax-exempt organizations;	
 	 	 	
 	•	controlled foreign corporations or passive foreign investment companies;	
 	 	 	
 	•	brokers or dealers in securities or currencies;	
 	 	 	
 	•	pass-through entities (e.g. partnerships) or persons who hold our common stock through pass-through entities;	
 	 	 	
 	•	regulated investment companies;	
 	 	 	
 	•	pension plans;	
 	 	 	
 	•	owners of more than 5% of our common stock;	
 	 	 	
 	•	persons that hold our common stock as part of a straddle, hedge, conversion transaction, synthetic security or other integrated investment; and	
 	 	 	
 	•	certain U.S. expatriates.	
      In addition, if a partnership holds our common stock, the tax treatment of a partner generally will depend on the status of the partner and upon the activities of the partnership. Accordingly, partnerships that are prospective investors in our common stock, and partners in such partnerships, should consult their tax advisors.

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      There can be no assurance that the Internal Revenue Service, or the IRS, will not challenge one of the tax consequences described herein, and we have not obtained, nor do we intend to obtain, an opinion of counsel with respect to the U.S. federal income or estate tax consequences to a non-U.S. holder of the purchase, ownership, or disposition of our common stock. We urge prospective investors to consult with their own tax advisors regarding the U.S. federal, state, local and non-U.S. income and other tax considerations of acquiring, holding and disposing of shares of our common stock.
Distributions on Our Common Stock
      NRG has not declared or paid distributions on its new common stock, although, subject to certain restrictions, we may do so in the future. In the event we do pay distributions on our common stock, these distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. If a distribution exceeds our current and accumulated earnings and profits, the excess will be treated as a tax-free return of the non-U.S. holder’s investment, up to such holder’s tax basis in the common stock. Any remaining excess will be treated as capital gain, subject to the tax treatment described below in “Gain on Sale or Other Disposition of Our Common Stock.”
      Dividends paid to a non-U.S. holder generally will be subject to withholding of U.S. federal income tax at a 30% rate or such lower rate as may be provided by an applicable income tax treaty. If we determine, at a time reasonably close to the date of payment of a distribution on our common stock, that the distribution will not qualify as a dividend because we do not anticipate having current or accumulated earnings and profits, we intend not to withhold any U.S. federal income tax on the distribution as permitted by United States Treasury Regulations. If we or another withholding agent withholds tax on such a distribution, a non-U.S. holder may be entitled to a refund of the tax withheld which the non-U.S. holder may claim by filing a United States tax return with the IRS.
      Dividends that are treated as “effectively connected” with a trade or business conducted by a non-U.S. holder within the United States (and, if an applicable income tax treaty so provides, are also attributable to a permanent establishment of such non-U.S. holder), known as “United States trade or business income,” are generally exempt from the 30% withholding tax if the non-U.S. holder satisfies applicable certification and other requirements. However, such United States trade or business income, net of specified deductions and credits, is taxed at the same graduated U.S. federal income tax rates applicable to United States persons. Any United States trade or business income received by a non-U.S. holder that is a corporation may also, under certain circumstances, be subject to an additional “branch profits tax” at a 30% rate or such lower rate as specified by an applicable income tax treaty.
      A non-U.S. holder of our common stock who claims the benefit of an applicable income tax treaty generally will be required to satisfy applicable certification and other requirements. Non-U.S. holders are urged to consult their tax advisors regarding their entitlement to benefits under a relevant income tax treaty.
      A non-U.S. holder that is eligible for a reduced rate of United States withholding tax or other exclusion from withholding under an income tax treaty may obtain a refund or credit of any excess amounts withheld by timely filing an appropriate claim with the IRS.
Gain on Sale or Other Disposition of Our Common Stock
      In general, a non-U.S. holder will not be subject to any U.S. federal income tax or withholding tax on any gain realized upon such holder’s sale or other disposition of shares of our common stock unless:
 	 	 	
 	•	the gain is United States trade or business income, in which case such holder (i) will be subject to tax on the net gain derived from the sale or disposition under the graduated United States federal income tax rates applicable to United States persons and (ii) if a corporation, may be subject to the branch profits tax, both as described above in “Distributions on Our Common Stock;”	
 	 	 	
 	•	the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and meets certain other requirements in which case the holder will be	
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 	 	subject to a flat 30% tax on the amount by which the gain derived from the sale, and certain other United States source capital gains realized during such year exceed certain United States source capital losses realized during such year; or	
 	 	 	
 	•	certain rules (described below) relating to “United States real property holding corporation” status apply to such sale or other disposition.	
      Gain recognized on a sale or other disposition of our common stock may be subject to U.S. federal income tax (and, in certain circumstances, to withholding tax) if (1) our common stock has ceased to be traded on an established securities market prior to the beginning of the calendar year in which the sale or disposition occurs and (2) we are, or have been, a United States real property holding corporation during the shorter of the five-year period ending on the date of such sale or other disposition or the period that the non-U.S. holder held our common stock. Generally, a corporation is a United States real property holding corporation if the fair market value of its “United States real property interests” equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests plus its other assets used or held for use in a trade or business. Although there can be no assurance, we do not believe that we are, or have been, a United States real property holding corporation, or that we are likely to become one in the future.
United States Federal Estate Tax
      Shares of our common stock that are owned or treated as owned by an individual non-U.S. holder at the time of death will be included in the individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax or other treaty provides otherwise, and therefore may be subject to U.S. federal estate tax.
Backup Withholding, Information Reporting and Other Reporting Requirements
      We must report to the IRS and to each non-U.S. holder the gross amount of the dividends on our common stock paid to such holder and the tax withheld, if any, with respect to such dividends. Dividends paid to non-U.S. holders subject to the United States withholding tax, as described above in “Distributions on Our Common Stock,” generally will be exempt from United States backup withholding.
      Information reporting and backup withholding (currently at a rate of 28%) will generally apply to the proceeds of a disposition of our common stock by a non-U.S. holder effected by or through the United States office of a broker unless the holder certifies its status as a non-U.S. holder and satisfies certain other qualifications, or otherwise establishes an exemption. Generally, information reporting and backup withholding will not apply to a payment of disposition proceeds where the transaction is effected outside the United States through a non-U.S. office of a non-U.S. broker. However, for information reporting purposes, certain brokers with substantial United States ownership or operations generally will be treated in a manner similar to United States brokers. Non-U.S. holders should consult their own tax advisors regarding the application of the information reporting and backup withholding rules to them.
      Copies of information returns may be made available under the provisions of a specific treaty or agreement to the tax authorities of the country in which the non-U.S. holder resides or is incorporated.
      Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules from a payment to a non-U.S. holder can be refunded or credited against the non-U.S. holder’s U.S. federal income tax liability, if any, provided that an appropriate claim is timely filed with the IRS.

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UNDERWRITING
      Under the terms and subject to the conditions contained in an underwriting agreement dated as of the date of this prospectus supplement, the underwriters named below have severally agreed to purchase and we have agreed to sell to them, severally, the respective number of shares of common stock set forth opposite their names below:
 	 	 	 	 	
 	 	Number	 	
Underwriter	 	of Shares	 	
 	 	 	 	
Morgan Stanley & Co. Incorporated	 	 	7,768,508	 	
Citigroup Global Markets Inc. 	 	 	7,768,508	 	
Lehman Brothers Inc. 	 	 	1,564,129	 	
Banc of America Securities LLC	 	 	938,478	 	
Deutsche Bank Securities Inc. 	 	 	938,478	 	
Goldman, Sachs & Co. 	 	 	938,478	 	
Merrill Lynch, Pierce, Fenner & Smith
Incorporated	 	 	938,478	 	
 	 	 	 	
Total	 	 	20,855,057	 	
 	 	 	 	
      The underwriters are offering the shares of common stock subject to their acceptance of the shares from us and subject to prior sale. The underwriting agreement provides that the obligations of the several underwriters to pay for and accept delivery of the shares of common stock offered by this prospectus supplement and the accompanying prospectus are subject to the approval of legal matters by their counsel and to other conditions. The underwriters are obligated to take and pay for all of the shares of common stock offered by this prospectus supplement if any such shares are taken. However, the underwriters are not required to take or pay for the shares covered by the underwriters’ overallotment described below unless and until the overallotment is exercised.
      The underwriters initially propose to offer part of the shares of common stock directly to the public at the public offering price listed on the cover page of this prospectus supplement and part to certain dealers at a price that represents a concession not in excess of $0.88 per share less than the public offering price. After the initial offering of the shares of common stock, the offering price and other selling terms may from time to time be varied by the underwriters. The total price to the public will be $1,016,684,029, the total underwriting discount will be $30,500,521 and the total net proceeds to us will be $985,083,508.
      We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus supplement, to purchase up to 3,128,259 additional shares of common stock at the public offering price set forth on the cover page of this prospectus supplement, less the underwriting discount. The underwriters may exercise this option solely for the purpose of covering overallotments, if any, made in connection with the offering of the shares of common stock offered by this prospectus supplement. To the extent that the option is exercised, each underwriter will become obligated, subject to certain conditions, to purchase about the same percentage of the additional shares of our common stock as the number listed opposite the underwriter’s name in the preceding table bears to the total number of shares of our common stock listed opposite the names of all underwriters in the preceding table. If the overallotment option is exercised in full, the total price to the public would be $152,502,626, the total underwriting discount would be $4,575,079 and the total proceeds to us would be $147,927,547.
      The estimated offering expenses payable by us are approximately $1,100,000, not including the underwriting discount, which includes legal, accounting and printing costs and various other fees associated with registering and listing the common stock.
      Our common stock is listed on the New York Stock Exchange under the symbol “NRG.”

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      We and each of our executive officers and directors have agreed, with exceptions, not to sell or transfer any common stock for 90 days after the date of this prospectus supplement without first obtaining the written consent of Morgan Stanley & Co. Incorporated and Citigroup Global Markets Inc.
      Specifically, we and these other individuals and entities have agreed not to directly or indirectly:
 	 	 	
 	•	offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant for the sale of, or otherwise dispose of or transfer any shares of common stock or any securities convertible into or exercisable or exchangeable for common stock or file any registration statement with respect to any of the foregoing; or	
 	 	 	
 	•	enter into any swap or any other agreement or any transaction that transfers, in whole or in part, directly or indirectly, the economic consequence of ownership of the common stock, whether any such swap or transaction described above is to be settled by delivery of common stock or such other securities, in cash or otherwise.	
      This lockup provision applies to common stock and to securities convertible into or exchangeable or exercisable for common stock owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition.
      In order to facilitate the offering of the common stock, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common stock. Specifically, the underwriters may sell more shares than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is covered if the short position is no greater than the number of shares available for purchase by the underwriters under the overallotment option. The underwriters can close out a covered short sale by exercising the overallotment option or purchasing shares in the open market. In determining the source of shares to close out a covered short sale, the underwriters will consider, among other things, the open market price of shares compared to the price available under the overallotment option. The underwriters may also sell shares in excess of the overallotment option, creating a naked short position. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market after pricing this offering that could adversely affect investors who purchase shares in this offering. In addition, in order to cover any overallotments or to stabilize the price of our common stock, the underwriters may bid for, and purchase, shares of our common stock in the open market. Finally, the underwriting syndicate may reclaim selling concessions allowed to an underwriter or a dealer for distributing our common stock in this offering, if the syndicate repurchases previously distributed shares of our common stock to cover syndicate short positions, in stabilization transactions or otherwise. Any of these activities may raise or maintain the market price of the common stock above independent market levels or prevent or retard a decline in the market price of the common stock. The underwriters are not required to engage in these activities, and may end any of these activities at any time.
      This prospectus supplement and the accompanying prospectus in electronic format may be made available on a website maintained by one or more of the representatives of the underwriters and may also be made available on a website maintained by the other underwriters. The underwriters may agree to allocate a number of shares to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the representatives of the underwriters to underwriters that may make Internet distributions on the same basis as other allocations.
      Morgan Stanley & Co. Incorporated, Citigroup Global Markets Inc., Lehman Brothers Inc., Banc of America Securities LLC, Deutsche Bank Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Goldman Sachs & Co. and certain of their affiliates are lenders under, and receive customary fees and expenses in connection with, certain of our credit facilities, including the new senior secured credit facility and the bridge loan facility. See “Description of Certain Indebtedness.” We have also entered into the J. Aron PPA and other agreements with J. Aron, an affiliate of Goldman, Sachs & Co., as well as hedging agreements with Deutsche Bank Securities Inc. and/or its affiliates and certain other lenders under our new senior secured credit facility. See “Business— Regional Business Descriptions— Texas (ERCOT)— J. Aron Power Purchase Agreement.”

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      In addition, the underwriters and their affiliates have, from time to time, performed, and may in the future perform, various financial advisory, commercial banking or investment banking services for us, our subsidiaries or our affiliates for which they received or will receive customary fees and expenses.
      We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

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LEGAL MATTERS
      The validity of the common stock offered hereby and certain other matters will be passed upon for NRG by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York. The underwriters have been represented in connection with this offering by Latham & Watkins LLP, New York, New York.

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NRG Energy, Inc.
Debt Securities
Preferred Stock
Common Stock
 
        NRG Energy, Inc., from time to time, may offer to sell senior or subordinated debt securities, preferred stock and common stock. The debt securities and preferred stock may be convertible into or exercisable or exchangeable for our common stock, our preferred stock, our other securities or the debt or equity securities of one or more other entities. Our common stock is listed on the New York Stock Exchange and trades under the ticker symbol “NRG.”
      We may offer and sell these securities to or through one or more underwriters, dealers and agents, or directly to purchasers, on a continuous or delayed basis.
      This prospectus describes some of the general terms that may apply to these securities. The specific terms of any securities to be offered will be described in a supplement to this prospectus.
 
      Neither the Securities and Exchange Commission nor any other state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.
 
Prospectus dated December 21, 2005

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TABLE OF CONTENTS
 	 	 	 	 	 	
 	 	Page	 	
 	 	 	 	
 Where You Can Find More Information	 	 	ii	 	
 Incorporation Of Certain Information By Reference	 	 	ii	 	
 Disclosure Regarding Forward-Looking Statements	 	 	iii	 	
 NRG Energy, Inc. 	 	 	1	 	
 Description Of Securities We May Offer	 	 	2	 	
 	 Debt Securities And Guarantees	 	 	2	 	
 	 Preferred Stock	 	 	4	 	
 	 Common Stock	 	 	6	 	
 Ratios Of Earnings To Fixed Charges and Earnings To Combined Fixed Charges and Preference Dividends	 	 	7	 	
 Use Of Proceeds	 	 	8	 	
 Validity Of The Securities	 	 	8	 	
 Experts	 	 	8	 	

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WHERE YOU CAN FIND MORE INFORMATION
      We file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission, or the SEC. You can inspect and copy these reports, proxy statements and other information at the Public Reference Room of the SEC, 100 F Street, N.E., Washington, D.C. 20549. You can obtain copies of these materials from the Public Reference Section of the SEC, 100 F Street, N.E., Washington, D.C. 20549, at prescribed rates. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. NRG’s SEC filings will also be available to you on the SEC’s website at http://www.sec.gov and through the New York Stock Exchange, 20 Broad Street, New York, New York 10005, on which our common stock is listed.
      We have filed with the SEC a registration statement on Form S-3 relating to the securities covered by this prospectus. This prospectus, which forms a part of the registration statement, does not contain all the information that is included in the registration statement. You will find additional information about us in the registration statement. Any statements made in this prospectus concerning the provisions of legal documents are not necessarily complete and you should read the documents that are filed as exhibits to the registration statement or otherwise filed with the SEC for a more complete understanding of the document or matter.
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE
      The SEC allows the “incorporation by reference” of the information filed by us with the SEC into this prospectus, which means that important information can be disclosed to you by referring you to those documents and those documents will be considered part of this prospectus. Information that we file later with the SEC will automatically update and supersede the previously filed information. The documents listed below and any future filings we make with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) are incorporated by reference herein:
 	 	
 	      1. Our annual report on Form 10-K for the year ended December 31, 2004 filed on March 30, 2005.	
 	 	
 	      2. Our Definitive Proxy Statement on Schedule 14A filed on April 12, 2005.	
 	 	
 	      3. Our quarterly reports on Form 10-Q for the quarters ended March 31, 2005 filed on May 10, 2005, June 30, 2005 filed on August 9, 2005 and September 30, 2005 filed on November 7, 2005.	
 	 	
 	      4. Our current reports on Form 8-K filed on February 24, 2005, Form 8-K filed on March 3, 2005, two Forms 8-K filed on March 30, 2005 (which do not include information deemed “furnished” for purposes of Regulation F-D), Form 8-K filed on May 24, 2005, Form 8-K/ A filed on May 24, 2005, Form 8-K/ A filed on May 25, 2005, Form 8-K filed on June 15, 2005, Form 8-K/ A filed on June 15, 2005, Form 8-K filed on June 17, 2005, Form 8-K filed on July 18, 2005, Form 8-K filed on August 1, 2005, Form 8-K filed on August 3, 2005, Form 8-K filed on August 9, 2005 (which does not include information deemed “furnished” for purposes of Regulation F-D), Form 8-K filed on August 11, 2005, Form 8-K filed on September 1, 2005, Form 8-K filed on September 7, 2005 (which does not include information deemed “furnished” for purposes of Regulation F-D), Form 8-K filed on October 3, 2005, Form 8-K filed on October 12, 2005, Form 8-K filed on November 7, 2005 (which does not include information deemed “furnished” for purposes of Regulation F-D), Form 8-K filed on December 20, 2005 and Form 8-K filed on December 21, 2005.	
 	 	
 	      5. The description of our common stock contained in the Registration Statement on Form 8-A dated March 22, 2004 filed with the SEC to register such securities under the Securities and Exchange Act of 1934, as amended, including any amendment or report filed for the purpose of updating such description.	
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      If you make a request for such information in writing or by telephone, we will provide you, without charge, a copy of any or all of the information incorporated by reference into this prospectus. Any such request should be directed to:
NRG Energy, Inc.
211 Carnegie Center
Princeton, NJ 08540
(609) 524-4500
Attention: General Counsel
      You should rely only on the information contained in, or incorporated by reference in, this prospectus. We have not authorized anyone else to provide you with different or additional information. This prospectus does not offer to sell or solicit any offer to buy any notes in any jurisdiction where the offer or sale is unlawful. You should not assume that the information in this prospectus or in any document incorporated by reference is accurate as of any date other than the date on the front cover of the applicable document.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
      This prospectus, any accompanying prospectus supplement and the documents incorporated by reference herein and therein may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements are subject to certain risks, uncertainties and assumptions that include, but are not limited to, expected earnings and cash flows, future growth and financial performance and the expected synergies and other benefits of the acquisition of Texas Genco LLC described herein (including the documents incorporated herein by reference), and typically can be identified by the use of words such as “will,” “expect,” “estimate,” “anticipate,” “forecast,” “plan,” “believe” and similar terms. Although we believe that our expectations are reasonable, we can give no assurance that these expectations will prove to have been correct, and actual results may vary materially. Factors that could cause actual results to differ materially from those contemplated above include, among others:
 	 	 	
 	• 	Risks and uncertainties related to the capital markets generally, including increases in interest rates and the availability of financing for the acquisition of Texas Genco LLC;	
 	 	 	
 	• 	NRG’s indebtedness and the additional indebtedness that it will incur in connection with the acquisition of Texas Genco LLC;	
 	 	 	
 	• 	NRG’s ability to successfully complete the acquisition of Texas Genco LLC, regulatory or other limitations that may be imposed as a result of the acquisition of Texas Genco LLC, and the success of the business following the acquisition of Texas Genco LLC;	
 	 	 	
 	• 	General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel or other raw materials;	
 	 	 	
 	• 	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 fossil 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 we may not have adequate insurance to cover losses as a result of such hazards;	
 	 	 	
 	• 	NRG’s potential inability to enter into contracts to sell power and procure fuel on terms and prices acceptable to it;	
 	 	 	
 	• 	The liquidity and competitiveness of wholesale markets for energy commodities;	
 	 	 	
 	• 	Changes in government regulation, including possible changes of market rules, market structures and design, rates, tariffs, environmental laws and regulations and regulatory compliance requirements;	
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 	• 	Price mitigation strategies and other market structures or designs employed by independent system operators, or ISOs, or regional transmission organizations, or RTOs, that result in a failure to adequately compensate our generation units for all of their costs;	
 	 	 	
 	• 	NRG’s ability to realize its significant deferred tax assets, including loss carry forwards;	
 	 	 	
 	• 	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 (including general and administrative expenses) tightly and generate earnings and cash flow from its asset-based businesses in relation to its debt and other obligations; and	
 	 	 	
 	• 	Significant operating and financial restrictions placed on NRG contained in the indenture governing its 8% second priority senior secured notes due 2013, its amended and restated credit facility as well as in debt and other agreements of certain of NRG’s subsidiaries and project affiliates generally.	
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NRG ENERGY, INC.
      NRG Energy is a wholesale power generation company, primarily engaged in the ownership and operation of power generation facilities, the transacting in and trading of fuel and transportation services and the marketing and trading of energy, capacity and related products in the United States and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type and dispatch levels. Our principal domestic generation assets (without giving effect to the acquisition of Texas Genco LLC) consist of a diversified mix of natural gas-, coal- and oil-fired facilities, representing approximately 40%, 30% and 30% of our total domestic generation capacity, respectively. In addition (without giving effect to the acquisition of Texas Genco LLC), approximately 15% of our domestic generating facilities have dual-or multiple-fuel capacity, which render the ability for plants to dispatch with the lowest cost fuel option.
      Our two principal operating objectives are to optimize performance of our entire portfolio, and to protect and enhance the market value of our physical and contractual assets through the execution of risk management, marketing and trading strategies within well-defined risk and liquidity guidelines. We manage the assets in our core regions on a portfolio basis as integrated businesses in order to maximize profits and minimize risk. Our business involves the reinvestment of capital in our existing assets for reasons of repowering, expansion, pollution control, operating efficiency, reliability programs, greater fuel optionality, greater merit order diversity, and enhanced portfolio effect, among other reasons. Our business also may involve acquisitions intended to complement the asset portfolios in our core regions. From time to time we may also consider and undertake other merger and acquisition transactions that are consistent with our strategy, such as our pending acquisition of Texas Genco LLC.
      On September 30, 2005, we entered into an acquisition agreement, or the Acquisition Agreement, with Texas Genco LLC and each of the direct and indirect owners of equity interests in Texas Genco LLC, or the Sellers. Pursuant to the Acquisition Agreement, we agreed to purchase all of the outstanding equity interests in Texas Genco LLC for a total purchase price of approximately $5.825 billion and the assumption by us of approximately $2.5 billion of indebtedness. The purchase price is subject to adjustment, and includes an equity component valued at $1.8 billion based on a price per share of $40.50 of NRG’s common stock. As a result of the Acquisition, Texas Genco LLC will become a wholly owned subsidiary of NRG and will nearly double our U.S. generation portfolio from approximately 12,005 Megawatts to 23,124 Megawatts.
      We were incorporated as a Delaware corporation on May 29, 1992. Our common stock is listed on the New York Stock Exchange under the symbol “NRG”. Our headquarters and principal executive offices are located at 211 Carnegie Center, Princeton, New Jersey 08540. Our telephone number is (609) 524-4500.
      You can get more information regarding our business by reading our Annual Report on Form 10-K for the fiscal year ended December 31, 2004, and the other reports we file with the Securities and Exchange Commission. See “Where You Can Find More Information.”

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DESCRIPTION OF SECURITIES WE MAY OFFER
DEBT SECURITIES AND GUARANTEES
      We may offer secured or unsecured debt securities, which may be convertible. Our debt securities and any related guarantees will be issued under an indenture to be entered into between us and Law Debenture Trust Company of New York. Holders of our indebtedness will be structurally subordinated to holders of any indebtedness (including trade payables) of any of our subsidiaries that do not guarantee our payment obligations under such indebtedness.
      We have summarized certain general features of the debt securities from the indenture. A form of indenture is attached as an exhibit to the registration statement of which this prospectus forms a part. The following description of the terms of the debt securities and the guarantees sets forth certain general terms and provisions. The particular terms of the debt securities and guarantees offered by any prospectus supplement and the extent, if any, to which such general provisions may apply to the debt securities and guarantees will be described in the related prospectus supplement. Accordingly, for a description of the terms of a particular issue of debt securities, reference must be made to both the related prospectus supplement and to the following description.
General
      The aggregate principal amount of debt securities that may be issued under the indenture is unlimited. The debt securities may be issued in one or more series as may be authorized from time to time.
      Reference is made to the applicable prospectus supplement for the following terms of the debt securities (if applicable):
 	 	 	
 	• 	title and aggregate principal amount;	
 	 	 	
 	• 	whether the securities will be senior or subordinated;	
 	 	 	
 	• 	applicable subordination provisions, if any;	
 	 	 	
 	• 	whether securities issued by us will be entitled to the benefits of the guarantees or any other form of guarantee;	
 	 	 	
 	• 	conversion or exchange into other securities;	
 	 	 	
 	• 	whether securities issued by us will be secured or unsecured, and if secured, what the collateral will consist of;	
 	 	 	
 	• 	percentage or percentages of principal amount at which such securities will be issued;	
 	 	 	
 	• 	maturity date(s);	
 	 	 	
 	• 	interest rate(s) or the method for determining the interest rate(s);	
 	 	 	
 	• 	dates on which interest will accrue or the method for determining dates on which interest will accrue and dates on which interest will be payable;	
 	 	 	
 	• 	redemption (including upon a “change of control”) or early repayment provisions;	
 	 	 	
 	• 	authorized denominations;	
 	 	 	
 	• 	form;	
 	 	 	
 	• 	amount of discount or premium, if any, with which such securities will be issued;	
 	 	 	
 	• 	whether such securities will be issued in whole or in part in the form of one or more global securities;	
 	 	 	
 	• 	identity of the depositary for global securities;	
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 	• 	whether a temporary security is to be issued with respect to such series and whether any interest payable prior to the issuance of definitive securities of the series will be credited to the account of the persons entitled thereto;	
 	 	 	
 	• 	the terms upon which beneficial interests in a temporary global security may be exchanged in whole or in part for beneficial interests in a definitive global security or for individual definitive securities;	
 	 	 	
 	• 	conversion or exchange features;	
 	 	 	
 	• 	any covenants applicable to the particular debt securities being issued;	
 	 	 	
 	• 	any defaults and events of default applicable to the particular debt securities being issued;	
 	 	 	
 	• 	currency, currencies or currency units in which the purchase price for, the principal of and any premium and any interest on, such securities will be payable;	
 	 	 	
 	• 	time period within which, the manner in which and the terms and conditions upon which the purchaser of the securities can select the payment currency;	
 	 	 	
 	• 	securities exchange(s) on which the securities will be listed, if any;	
 	 	 	
 	• 	whether any underwriter(s) will act as market maker(s) for the securities;	
 	 	 	
 	• 	extent to which a secondary market for the securities is expected to develop;	
 	 	 	
 	• 	additions to or changes in the events of default with respect to the securities and any change in the right of the trustee or the holders to declare the principal, premium and interest with respect to such securities to be due and payable;	
 	 	 	
 	• 	provisions relating to covenant defeasance and legal defeasance;	
 	 	 	
 	• 	provisions relating to satisfaction and discharge of the indenture;	
 	 	 	
 	• 	provisions relating to the modification of the indenture both with and without the consent of holders of debt securities issued under the indenture; and	
 	 	 	
 	• 	additional terms not inconsistent with the provisions of the indenture.	
      One or more series of debt securities may be sold at a substantial discount below their stated principal amount, bearing no interest or interest at a rate which at the time of issuance is below market rates. One or more series of debt securities may be variable rate debt securities that may be exchanged for fixed rate debt securities.
      United States federal income tax consequences and special considerations, if any, applicable to any such series will be described in the applicable prospectus supplement.
      Debt securities may be issued where the amount of principal and/or interest payable is determined by reference to one or more currency exchange rates, commodity prices, equity indices or other factors. Holders of such securities may receive a principal amount or a payment of interest that is greater than or less than the amount of principal or interest otherwise payable on such dates, depending upon the value of the applicable currencies, commodities, equity indices or other factors. Information as to the methods for determining the amount of principal or interest, if any, payable on any date, the currencies, commodities, equity indices or other factors to which the amount payable on such date is linked and certain additional United States federal income tax considerations will be set forth in the applicable prospectus supplement.
      The term “debt securities” includes debt securities denominated in U.S. dollars or, if specified in the applicable prospectus supplement, in any other freely transferable currency or units based on or relating to foreign currencies.
      We expect most debt securities to be issued in fully registered form without coupons and in denominations of $1,000 or $5,000 and any integral multiples thereof. Subject to the limitations provided in the indenture and in the prospectus supplement, debt securities that are issued in registered form may be

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transferred or exchanged at the office of the trustee maintained in the Borough of Manhattan, The City of New York or the principal corporate trust office of the trustee, without the payment of any service charge, other than any tax or other governmental charge payable in connection therewith.
Guarantees
      Any debt securities may be guaranteed by one or more of our direct or indirect subsidiaries. Each prospectus supplement will describe any guarantees for the benefit of the series of debt securities to which it relates, including required financial information of the subsidiary guarantors, as applicable.
Global Securities
      The debt securities of a series may be issued in whole or in part in the form of one or more global securities that will be deposited with, or on behalf of, a depositary (the “depositary”) identified in the prospectus supplement. Global securities will be issued in registered form and in either temporary or definitive form. Unless and until it is exchanged in whole or in part for the individual debt securities, a global security may not be transferred except as a whole by the depositary for such global security to a nominee of such depositary or by a nominee of such depositary to such depositary or another nominee of such depositary or by such depositary or any such nominee to a successor of such depositary or a nominee of such successor. The specific terms of the depositary arrangement with respect to any debt securities of a series and the rights of and limitations upon owners of beneficial interests in a global security will be described in the applicable prospectus supplement.
Governing Law
      The indenture, the debt securities and the guarantees shall be construed in accordance with and governed by the laws of the State of New York, without giving effect to the principles thereof relating to conflicts of law.
PREFERRED STOCK
      The following briefly summarizes the material terms of our preferred stock, other than pricing and related terms that will be disclosed in an accompanying prospectus supplement. You should read the particular terms of any series of preferred stock offered by us, which will be described in more detail in any prospectus supplement relating to such series, together with the more detailed provisions of our amended and restated certificate of incorporation and the certificate of designation relating to each particular series of preferred stock for provisions that may be important to you. The certificate of incorporation, as amended and restated, is incorporated by reference into the registration statement of which this prospectus forms a part. The certificate of designation relating to the particular series of preferred stock offered by an accompanying prospectus supplement and this prospectus will be filed as an exhibit to a document incorporated by reference in the registration statement. The prospectus supplement will also state whether any of the terms summarized below do not apply to the series of preferred stock being offered.
      As of the date of this prospectus, we are authorized to issue up to 10,000,000 shares of preferred stock, par value $0.01 per share. As of December 16, 2005, 420,000 shares of 4% Convertible Perpetual Preferred Stock were outstanding and 250,000 shares of 3.625% Convertible Perpetual Preferred Stock were outstanding. Under our amended and restated certificate of incorporation, our board of directors is authorized to issue shares of preferred stock in one or more series, and to establish from time to time a series of preferred stock with the following terms specified:
 	 	 	
 	• 	the number of shares to be included in the series;	
 	 	 	
 	• 	the designation, powers, preferences and rights of the shares of the series; and	
 	 	 	
 	• 	the qualifications, limitations or restrictions of such series.	
      Prior to the issuance of any series of preferred stock, our board of directors will adopt resolutions creating and designating the series as a series of preferred stock and the resolutions will be filed in a certificate of

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designation as an amendment to the amended and restated certificate of incorporation. The term “board of directors” includes any duly authorized committee.
      The rights of holders of the preferred stock offered may be adversely affected by the rights of holders of any shares of preferred stock that may be issued in the future. Our board of directors may cause shares of preferred stock to be issued in public or private transactions for any proper corporate purpose. Examples of proper corporate purposes include issuances to obtain additional financing in connection with acquisitions or otherwise, and issuances to our or our subsidiaries’ officers, directors and employees pursuant to benefit plans or otherwise. Shares of preferred stock we issue may have the effect of rendering more difficult or discouraging an acquisition of us deemed undesirable by our board of directors.
      The preferred stock will be, when issued, fully paid and nonassessable. Holders of preferred stock will not have any preemptive or subscription rights to acquire more of our stock.
      The transfer agent, registrar, dividend disbursing agent and redemption agent for shares of each series of preferred stock will be named in the prospectus supplement relating to such series.
Rank
      Unless otherwise specified in the prospectus supplement relating to the shares of a series of preferred stock, such shares will rank on an equal basis with each other series of preferred stock and prior to the common stock as to dividends and distributions of assets.
Dividends
      Holders of each series of preferred stock will be entitled to receive cash dividends when, as and if declared by our board of directors out of funds legally available for dividends. The rates and dates of payment of dividends will be set forth in the prospectus supplement relating to each series of preferred stock. Dividends will be payable to holders of record of preferred stock as they appear on our books or, if applicable, the records of the depositary referred to below on the record dates fixed by the board of directors. Dividends on a series of preferred stock may be cumulative or noncumulative.
      We may not declare, pay or set apart for payment dividends on the preferred stock unless full dividends on other series of preferred stock that rank on an equal or senior basis have been paid or sufficient funds have been set apart for payment for
 	 	 	
 	• 	all prior dividend periods of other series of preferred stock that pay dividends on a cumulative basis; or	
 	 	 	
 	• 	the immediately preceding dividend period of other series of preferred stock that pay dividends on a noncumulative basis.	
      Partial dividends declared on shares of preferred stock and each other series of preferred stock ranking on an equal basis as to dividends will be declared pro rata. A pro rata declaration means that the ratio of dividends declared per share to accrued dividends per share will be the same for each series of preferred stock.
      Similarly, we may not declare, pay or set apart for payment non-stock dividends or make other payments on the common stock or any other of our stock ranking junior to the preferred stock until full dividends on the preferred stock have been paid or set apart for payment for
 	 	 	
 	• 	all prior dividend periods if the preferred stock pays dividends on a cumulative basis; or	
 	 	 	
 	• 	the immediately preceding dividend period if the preferred stock pays dividends on a noncumulative basis.	
Conversion and Exchange
      The prospectus supplement for a series of preferred stock will state the terms, if any, on which shares of that series are convertible into or exchangeable for shares of our common stock, our preferred stock, our other securities or the debt or equity securities of one or more other entities.

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Redemption and Sinking Fund
      If so specified in the applicable prospectus supplement, a series of preferred stock may be redeemable at any time, in whole or in part, at our option or the option of the holder thereof and may be mandatorily redeemed. Any partial redemptions of preferred stock will be made in a way that the board of directors decides is equitable.
      Unless we default in the payment of the redemption price, dividends will cease to accrue after the redemption date on shares of preferred stock called for redemption and all rights of holders of such shares will terminate except for the right to receive the redemption price.
      No series of preferred stock will receive the benefit of a sinking fund except as set forth in the applicable prospectus supplement.
Liquidation Preference
      Upon any voluntary or involuntary liquidation, dissolution or winding up, holders of each series of preferred stock will be entitled to receive distributions upon liquidation in the amount set forth in the prospectus supplement relating to such series of preferred stock, plus an amount equal to any accrued and unpaid dividends. Such distributions will be made before any distribution is made on any securities ranking junior relating to liquidation, including common stock.
      If the liquidation amounts payable relating to the preferred stock of any series and any other securities ranking on a parity regarding liquidation rights are not paid in full, the holders of the preferred stock of such series and such other securities will share in any such distribution of our available assets on a ratable basis in proportion to the full liquidation preferences. Holders of such series of preferred stock will not be entitled to any other amounts from us after they have received their full liquidation preference.
Voting Rights
      The holders of shares of preferred stock will have no voting rights, except:
 	 	 	
 	• 	as otherwise stated in the prospectus supplement;	
 	 	 	
 	• 	as otherwise stated in the certificate of designation establishing such series; and	
 	 	 	
 	• 	as required by applicable law.	
      Holders of our 4% Convertible Perpetual Preferred Stock are entitled to one vote for each share held by such holder on all matters voted upon by our common stockholders.
COMMON STOCK
      The following description of our common stock is only a summary. We encourage you to read our amended and restated certificate of incorporation, which is incorporated by reference into the registration statement of which this prospectus forms a part. As of the date of this prospectus, we are authorized to issue up to 500,000,000 shares of common stock, $0.01 par value per share. As of December 16, 2005, we had outstanding 80,701,888 shares of our common stock.
Liquidation Rights
      Upon voluntary or involuntary liquidation, dissolution or winding up, the holders of our common stock share ratably in the assets remaining after payments to creditors and provision for the preference of any preferred stock.
Dividends
      Except as otherwise provided by the Delaware General Corporation Law or our amended and restated certificate of incorporation, the holders of our common stock, subject to the rights of holders of any series of

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preferred stock, shall share ratably in all dividends as may from time to time be declared by our board of directors in respect of our common stock out of funds legally available for the payment thereof and payable in cash, stock or otherwise, and in all other distributions (including, without limitation, our dissolution, liquidation and winding up), whether in respect of liquidation or dissolution (voluntary or involuntary) or otherwise, after payment of liabilities and liquidation preference on any outstanding preferred stock.
Voting Rights
      Except as otherwise provided by the Delaware General Corporation Law or our certificate of incorporation and subject to the rights of holders of any series of preferred stock, all the voting power of our stockholders shall be vested in the holders of our common stock, and each holder of our common stock shall have one vote for each share held by such holder on all matters voted upon by our stockholders.
      Subject to the rights of holders of any outstanding shares of preferred stock to act by written consent, our stockholders may not take any action by written consent in lieu of a meeting and must take any action at a duly called annual or special meeting of stockholders.
      The affirmative vote of holders of at least two-thirds of the combined voting power of our outstanding shares eligible to vote in the election of directors is required to alter, amend or repeal provisions in the amended and restated certificate of incorporation regarding indemnification, classification of directors, action by written consent and changes to voting requirements applicable to such provisions.
Conversion and Exchange
      Our common stock is not convertible into, or exchangeable for, any other class or series of our capital stock.
Miscellaneous
      Holders of our common stock have no preemptive or other rights to subscribe for or purchase additional securities of ours. We are subject to Section 203 of the DGCL. Shares of our common stock are not subject to calls or assessments. No personal liability will attach to holders of our common stock under the laws of the State of Delaware (our state of incorporation) or of the State of New Jersey (the state in which our principal place of business is located). All of the outstanding shares of our common stock are fully paid and nonassessable. Our common stock is listed and traded on the New York Stock Exchange under the symbol “NRG.”
RATIOS OF EARNINGS TO FIXED CHARGES AND EARNINGS TO COMBINED FIXED CHARGES AND PREFERENCE DIVIDENDS
      The ratios of earnings to fixed charges and earnings to combined fixed charges and preference dividends for the periods indicated are stated below. For this purpose, “earnings” include pre-tax income (loss) before adjustments for minority interest in our consolidated subsidiaries and income or loss from equity investees, plus fixed charges and distributed income of equity investees, reduced by interest capitalized. “Fixed charges” include interest, whether expensed or capitalized, amortization of debt expense and the portion of rental expense that is representative of the interest factor in these rentals. “Preference dividends” equals the amount of pre-tax earnings that is required to pay the dividends on outstanding preference securities. “Predecessor Company” refers to NRG’s operations prior to December 6, 2003, before emergence from bankruptcy and

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“Reorganized NRG” refers to NRG’s operations from December 6, 2003 onwards, after emergence from bankruptcy.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reorganized NRG	 	 	Predecessor Company	 	
 	 	 	 	 	 	 	
 	 	 	 	 	 	Year	 	
 	 	Nine Months	 	 	Year	 	 	December 6,	 	 	January 1,	 	 	Ended	 	
 	 	Ended	 	 	Ended	 	 	2003 through	 	 	2003 through	 	 	December 31,	 	
 	 	September 30,	 	 	December 31,	 	 	December 31,	 	 	December 5,	 	 	 	 	
 	 	2005	 	 	2004	 	 	2003	 	 	2003	 	 	2002	 	 	2001	 	 	2000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ratio of Earnings to Fixed Charges	 	 	1.19	x	 	 	1.83	x	 	 	1.68	x	 	 	9.82	x(1)	 	 	—	(2)	 	 	1.26	x	 	 	1.81	x	
Ratio of Earnings to Combined Fixed Charges and Preference Dividends	 	 	1.04	x	 	 	1.82	x	 	 	1.68	x	 	 	9.82	x(1)	 	 	—	(2)	 	 	1.26	x	 	 	1.81	x	

(1) 	For the period January 1, 2003 through December 5, 2003, the earnings include a one time earning of $4,118,636,000 due to Fresh Start adjustments.	
 	 	
(2) 	For the year ended December 31, 2002, the deficiency of earnings to fixed charges was $3,023,467,000.	
USE OF PROCEEDS
      We intend to use the net proceeds from the sales of the securities as set forth in the applicable prospectus supplement.
VALIDITY OF THE SECURITIES
      In connection with particular offerings of the securities in the future, and if stated in the applicable prospectus supplements, the validity of those securities may be passed upon for the Company by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York, and for any underwriters or agents by counsel named in the applicable prospectus supplement.
EXPERTS
      The consolidated financial statements and schedule of NRG Energy, Inc. (the Company) as of December 31, 2004, and for the year then ended, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004, included in the Company’s Form 10-K, as amended on Form 8-K dated December 20, 2005, which is incorporated by reference in this registration statement, have been incorporated by reference herein in reliance upon the reports of KPMG LLP, an independent registered accounting firm, incorporated by reference herein, and upon the authority of said firm as experts in accounting and auditing.
      The consolidated financial statements and schedule of NRG South Central Generating LLC and subsidiaries and the financial statements and schedule of Louisiana Generating LLC as of December 31, 2004 and for the year then ended, the consolidated financial statements of NRG Northeast Generating LLC and subsidiaries, NRG Mid Atlantic Generating LLC and subsidiaries, NRG International LLC and subsidiaries and the financial statements of Indian River Power LLC and subsidiaries as of December 31, 2004 and for the year then ended, the financial statements of Oswego Harbor Power LLC as of December 31, 2004 and 2003 and for the year ended December 31, 2003 and the period from December 6, 2003 to December 31, 2003 and the statements of operations, member’s equity and comprehensive income and cash flows of Oswego Harbor Power LLC for the period from January 1, 2003 to December 5, 2003, have been incorporated by reference herein in reliance on the reports of KPMG LLP, an independent registered public accounting firm, incorporated by reference herein, and upon authority of said firm as experts in accounting and auditing.
      The consolidated financial statements of NRG Energy, Inc. as of December 31, 2003 and for the period December 6, 2003 through December 31, 2003, the period January 1, 2003 through December 5, 2003 and the year ended December 31, 2002 incorporated in this prospectus by reference to NRG Energy, Inc.’s annual

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report on Form 10-K for the year ended December 31, 2004, as amended on Form 8-K dated December 20, 2005, which is incorporated by reference in this registration statement, have been so incorporated in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
      The consolidated financial statements of NRG Northeast Generating LLC, NRG South Central Generating LLC, Louisiana Generating LLC, NRG Mid Atlantic Generating LLC, Indian River Power LLC, and NRG International LLC as of December 31, 2003 and for the period from December 6, 2003 through December 31, 2003, the period from January 1, 2003 through December 5, 2003 and the year ended December 31, 2002 incorporated in this prospectus by reference to NRG Energy, Inc.’s current report on Form 8-K dated June 14, 2005, have been so incorporated in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
      The consolidated financial statements of West Coast Power LLC incorporated in this prospectus by reference to NRG Energy, Inc.’s annual report on Form 10-K for the year ended December 31, 2004, as amended on Form 8-K dated December 20, 2005, which is incorporated by reference in this registration statement, have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
      The consolidated balance sheet of Texas Genco LLC and subsidiaries as of December 31, 2004 and the related consolidated statements of operations, cash flows, members’ equity and comprehensive loss for the period from July 19, 2004 to December 31, 2004, all incorporated in this prospectus by reference to NRG Energy, Inc.’s current report on Form 8-K, filed on December 21, 2005, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report, which is incorporated herein by reference and has been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.
      The consolidated balance sheet of Texas Genco Holdings, Inc. and subsidiaries as of December 31, 2003 and 2004 and the related statements of consolidated operations, cash flows, and capitalization and shareholders’ equity for each of the three years for the period ended December 31, 2004, and the statement of consolidated comprehensive loss for each of the three years for the period ended December 31, 2004, all incorporated in this prospectus by reference to NRG Energy, Inc.’s current report on Form 8-K, filed on December 21, 2005, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report, which is incorporated herein by reference and has been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

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________________________________________________________________________________
 
20,855,057 Shares

NRG Energy, Inc.
Common Stock
 
PROSPECTUS SUPPLEMENT

MORGAN STANLEY	CITIGROUP	
 
LEHMAN BROTHERS
 	 	
 	BANC OF AMERICA SECURITIES LLC	
 	 	
 	DEUTSCHE BANK SECURITIES	
 	 	
 	GOLDMAN, SACHS & CO.	
 	 	
 	MERRILL LYNCH & CO.