424B3
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Filed Pursuant to Rule 424(b)(3)
Registration No. 333-130549
The information in this prospectus supplement and the accompanying prospectus is not complete and may be changed. This prospectus supplement and the accompanying prospectus are not an offer to sell these securities and are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED JANUARY 5, 2006
PRELIMINARY PROSPECTUS SUPPLEMENT
(To Prospectus dated December 21, 2005)
$3,600,000,000
(NRG Energy, Inc.)
NRG Energy, Inc.
% SENIOR NOTES DUE           
 
We are offering      % Senior Notes due           . We will pay interest on the notes on February 1 and August 1 of each year, beginning August 1, 2006. The notes will mature on February 1,           .
On September 30, 2005, NRG Energy, Inc., or NRG, entered into a definitive agreement to acquire Texas Genco LLC. Pending consummation of NRG’s acquisition of Texas Genco LLC, the net proceeds of this offering will be held in escrow for the benefit of the holders of the notes. The notes will be unsecured obligations and rank equally in right of payment to all of NRG’s existing and future unsecured senior indebtedness. The notes will only be issued in registered form in denominations of $5,000.
If the acquisition is not consummated prior to September 30, 2006, the notes are subject to special redemption at a redemption price of 100% of the aggregate principal amount, plus accrued interest to, but not including, the redemption date. See “Description of the Notes—Escrow of Proceeds; Special Mandatory Redemption.”
Concurrently with this offering, we are offering shares of our common stock and mandatory convertible preferred stock. This offering is not contingent on the consummation of these concurrent offerings.
Investing in the notes involves risks that are described in the “Risk Factors” section beginning on page S-17 of this prospectus supplement.
 
                 
    Per Note   Total
         
Public offering price
      %   $    
Underwriting discount
      %   $    
Proceeds, before expenses, to NRG Energy, Inc. 
      %   $    
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 accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
The notes will be ready for delivery in book-entry form only through The Depository Trust Company on or about                     , 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                     , 2006.


 

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Prospectus
 
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”),

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  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”), 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 and Form 8-K/A filed on January 5, 2006.
      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;
 
  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;

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  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 and the concurrent offerings by NRG of its common stock and mandatory convertible preferred stock 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 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

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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 preferred stock issued to the Sellers. 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.
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 “FORNRG,” 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

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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 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-17 for a discussion of the factors you should consider before investing in our securities.

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The Financing Transactions
      The offering of the notes 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) $1.0 billion of its common stock and (ii) $500 million of its mandatory convertible preferred stock. See “Description of Certain Other Indebtedness and Preferred Stock—Mandatory Convertible Preferred Stock.” This offering, the mandatory convertible preferred stock offering and the common stock 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 common stock offering and/or the closing of the mandatory convertible preferred stock offering. The net proceeds of the offering of these 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 Other Indebtedness and Preferred Stock—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 common stock, the mandatory convertible preferred stock 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 will use the net proceeds from this offering to redeem the notes offered hereby. See “Description of the Notes—Escrow of Proceeds; Special Mandatory Redemption” and “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 common stock 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. 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, 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 common stock offering and/or the mandatory convertible preferred stock offering. See “Description of Certain Other Indebtedness and Preferred Stock—Bridge Loan Facility.” In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the common stock 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. In the event that NRG does not consummate the common stock and mandatory convertible preferred 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,

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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. 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.”
                 
Sources(1)   Amount
     
    (in millions)
Gross proceeds of notes offered hereby
      $ 3,600  
New senior secured term loan facility
        3,200  
Cash released from canceling existing funded letter of credit facility(3)
        350  
Gross proceeds of common stock offering
        1,000  
 
Common stock consideration to be issued to Sellers
  1,606        
 
Preferred stock consideration to be issued to Sellers
  368        
           
   
Total
        1,974 (2)
Gross proceeds of mandatory convertible preferred stock offering
        500  
 
NRG’s cash on hand
        383  
           
   
Total
      $ 11,007  
           
                 
Uses   Amount
     
    (in millions)
Purchase price less acquisition costs(2)
      $ 6,005  
Texas Genco’s cash on hand to reduce consideration(2)
        (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
        476  
           
   
Total
      $ 11,007  
           
 
(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 common stock offering and/or the mandatory convertible preferred stock offering are not consummated. In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the common stock 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. In the event that NRG does not consummate the common stock 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.
 
(2)  The common stock component of the consideration for the Acquisition is based on a stock price of $45.37 per share of NRG’s common stock and the preferred stock consideration is valued based on an average common stock price of $40.73, as prescribed by

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the Acquisition Agreement. This is because the foregoing table is based on a pro forma closing date of the 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.
 
(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.
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 640 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 5, 2006 and incorporated herein by reference.
  Tender Offers and Consent Solicitations
      On December 29, 2005, NRG announced that it had received valid tenders and consents from holders of approximately $1,078,137,353 in aggregate principal amount of Second Priority Notes and $1,124,875,000 in aggregate principal amount of Unsecured Senior Notes, representing approximately 99.78% and 99.98% 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.

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Corporate Structure and Material Components of Consolidated Debt
      The following simplified diagram represents the combined company’s corporate structure and material components of the combined company’s indebtedness at September 30, 2005 on a pro forma basis after giving effect to the Transactions:
CORPORATE STRUCTURE GRAPH
 
(1)  The combined company’s corporate structure also includes $246.2 million of our 3.625% Convertible Preferred Stock, which is reflected in the mezzanine section of NRG’s balance sheet as of September 30, 2005.
 
(2)  $1.0 billion revolving credit facility is expected to be undrawn at closing of the Acquisition and the Financing Transactions.
 
(3)  Includes Camas, Thermal and Peakers. Such subsidiaries had $368 million of outstanding debt as of September 30, 2005 on a pro forma basis. Although the Excluded Domestic Subsidiaries do not guarantee the notes, their results of operations will be counted when measuring certain financial ratios under the terms of the notes. See “Description of the Notes.”
 
(4)  Includes SEG, Itiquira and Flinders. Such subsidiaries had $470 million of outstanding debt as of September 30, 2005 on a pro forma basis. Although the Excluded Foreign Subsidiaries do not guarantee the notes, their results of operations will be counted when measuring certain financial ratios under the terms of the notes. See “Description of the Notes.”
 
(5)  The $368 million of Cumulative Redeemable Preferred Stock issued to the Sellers on a pro forma basis is considered to be debt under U.S. Generally Accepted Accounting Principles.
 
     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.
 
Notes $3,600 million in aggregate principal amount of           % Senior Notes due           .
 
Maturity Date                     ,           .
 
Interest Rates           % per year.
 
Interest Payment Dates February 1 and August 1 of each year, commencing August 1, 2006.
 
Guarantees The notes will be guaranteed jointly and severally by each of our current and future restricted subsidiaries, excluding certain foreign, project and immaterial subsidiaries. Significant guarantors will include NRG Power Marketing, Inc., NRG South Central Generating LLC and certain of its subsidiaries, and the subsidiaries owning NRG’s assets in the MidAtlantic region and in the Northeast region. Each guarantee will rank pari passu with all existing and future senior indebtedness of that guarantor and will be senior in right of payment to all existing and future subordinated indebtedness of that guarantor.
 
Ranking The notes will be our general unsecured obligations and 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 notes will be guaranteed by only certain of our subsidiaries, they will be structurally subordinated to all indebtedness and other liabilities, including trade payables, of those subsidiaries that do not guarantee the notes. After giving pro forma effect to the Transactions, (i) our guarantor subsidiaries accounted for approximately 91% of our revenues from wholly-owned operations for the nine months ended September 30, 2005 and held approximately 90% of our consolidated assets as of September 30, 2005, and (ii) our non-guarantor subsidiaries had approximately $1.2 billion in aggregate principal amount of external funded indebtedness as of September 30, 2005, and our outstanding consolidated trade payables were $339 million as of September 30, 2005. Approximately 77% of these trade payables constituted obligations of NRG and its guarantor subsidiaries. See “Risk Factors—Risks Related to the Offering—We may not have access to the cash flow and other assets of our subsidiaries that may be needed to make payment on the notes.”
 
Optional Redemption We may redeem some or all of the notes at any time prior to February 1,           at a price equal to 100% of the principal amount of the notes redeemed plus a “make-whole” premium and accrued and unpaid interest. On or after February 1,           , we can redeem some or all of the notes at the redemption prices listed in the “Description of the Notes—Optional Redemption” section of this prospectus supplement, plus accrued and unpaid interest.

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Prior to February 1, 2009, we may redeem up to 35% of the notes issued under the indenture with the net cash proceeds of certain equity offerings, provided at least 65% of the aggregate principal amount of the notes issued in this offering remains outstanding after the redemption.
 
NRG may redeem the notes, at its option, in whole but not in part, at any time prior to September 30, 2006 at a redemption price equal to 100% of the aggregate principal amount of the notes plus accrued interest to, but not including, the redemption date if, in its judgment, any of the conditions to the release of funds from the escrow account to NRG to fund the Acquisition will not be satisfied on or prior to September 30, 2006.
 
Change of control Upon the occurrence of a change of control, holders of the 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 to the date of repurchase. See “Description of the Notes—Repurchase at the Option of Holders—Change of Control.”
 
Certain Covenants The indenture governing the notes will contain certain covenants that will, among other things, limit our ability and ability of our restricted subsidiaries to:
 
• incur additional debt;
 
• declare or pay dividends, redeem stock or make other distributions to stockholders;
 
• create liens;
 
• make certain restricted investments;
 
• enter into transactions with affiliates;
 
• sell or transfer assets; and
 
• consolidate or merge.
 
These covenants are subject to a number of important qualifications and limitations. See “Description of the Notes—Certain Covenants.”
 
Escrow of Proceeds; Redemption The underwriters will deposit the net proceeds of this offering (after payment of underwriting discounts and commissions) into an escrow account held by the escrow agent, and these proceeds will be used to pay the special mandatory redemption price for the notes described below, when and if due.
 
The notes are subject to a special mandatory redemption at a redemption price equal to 100% of the aggregate principal amount of the notes plus accrued interest to, but not including, the redemption date if the Acquisition is not consummated by September 30, 2006 on substantially the terms described in this prospectus supplement. NRG has received consents from the lenders under its existing credit facility to permit the funding of the escrow, the granting of a lien on the escrow account and the making of the

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special mandatory redemption in connection with this offering and the Acquisition.
 
The funds held in the escrow account, including the net proceeds from this offering, will be released from escrow to NRG upon consummation of the Acquisition on substantially the terms described in this prospectus supplement on or prior to September 30, 2006. The notes will be guaranteed jointly and severally by each of our current and future restricted subsidiaries other than certain foreign, project and immaterial subsidiaries. See “Description of the Notes—Escrow of Proceeds; Special Mandatory Redemption.”
 
Use of Proceeds We estimate that the net proceeds of this offering, after giving effect to underwriting discounts and commissions, will be approximately $           million. We intend to use the net proceeds from this offering and the offerings of common stock 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.”

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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 of 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 and incorporated in this prospectus supplement by reference, (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

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occurred on September 30, 2005. The adjustments reflected in the unaudited pro forma financial data are 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.”

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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            
        July 19,   For the   For the       For the
    For the Year   2004   Nine Months   Nine Months   For the Year   Nine Months
    Ended   through   Ended   Ended   Ended   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       182,762       614,493  
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  
Earnings per share-Basic
  $ 1.86     $ (0.13 )   $ 0.07     $ 2.05     $ 0.98     $ 4.01  
Earnings per share-Diluted
  $ 1.85     $ (0.13 )   $ 0.07     $ 1.98     $ 0.97     $ 3.69  
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  
EBITDA(3)(4)(5)
    965,627       26,614       395,874       764,463       1,763,542       842,010  
Ratio of earnings to fixed charges
    1.83 x     0.4 x     1.19 x     3.70 x     1.39 x     3.41 x
Balance Sheet Data (at period end):
                                               
Cash and cash equivalents
  $ 1,103,678       85,939     $ 504,336       222,393       NA       152,715  
Restricted cash
    109,633             91,508             NA       91,508  
Total Assets
    7,830,283       4,587,566       7,795,367       6,098,723       NA       20,811,525  
Total long-term debt including current maturities
    3,723,854       2,280,105       3,042,398       2,742,910       NA       7,634,504  
Stockholders’ equity/(deficit)
    2,692,164       771,516       2,019,168       773,112       NA       4,952,919  
 
(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       For the
    For the   Nine Months   For the   Nine Months
    Year Ended   Ended   Year Ended   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

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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 and the sale of Rocky Road for purposes of these pro forma financial statements.
 
(3) NRG and Texas Genco’s EBITDA represent net income before interest, taxes, depreciation and amortization. We present EBITDA because we consider it an important supplemental measure of our liquidity and our ability to service our debt and believe it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies’ liquidity in our industry. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of NRG and Texas Genco’s operating results as reported under accounting principles generally accepted in the United States, or GAAP. Some of these limitations are:
  EBITDA does not reflect our cash expenditures, or future requirements for capital expenditures, or contractual commitments;
 
  EBITDA does not reflect changes in, or cash requirements for, our working capital needs;
 
  EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debts;
 
  Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and our EBITDA does not reflect any cash requirements for such replacements; and
 
  Other companies may calculate EBITDA differently than we do, limiting its usefulness as a comparative measure.
  Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA only supplementally.
 
  The following table summarizes the calculation of NRG’s EBITDA and provides a reconciliation to NRG’s net income for the periods indicated:
                 
    NRG Energy, Inc.
     
        For the
    For the Year   Nine Months
    Ended   Ended
    December 31,   September 30,
    2004   2005
         
    (unaudited)   (unaudited)
    ($ in thousands)
Net income/(loss)
  $ 185,617     $ 19,603  
Plus
               
Income tax expense/(benefit)
    65,364       21,201  
Interest and refinancing expense
    337,714       194,634  
Depreciation and amortization expense
    208,036       144,317  
WCP CDWR Contract amortization
    115,751        
Amortization of power contracts
    35,316       6,485  
Amortization of emission credits
    17,829       9,634  
             
NRG EBITDA
  $ 965,627     $ 395,874  

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(4) The following table summarizes the calculation of Texas Genco’s EBITDA and provides a reconciliation to Texas Genco’s net income for the periods include:
                                 
    Predecessor            
                 
    Texas Genco       Combined    
    Holdings,   Texas Genco   Texas Genco   Texas Genco
    Inc.   LLC   LLC(a)   LLC
                 
        For the Period       For the
    For the Year   from July 19,   For the Year   Nine Months
    Ended   2004 through   Ended   Ended
    December 31,   December 31,   December 31,   September 30,
    2004   2004   2004   2005
                 
        ($ in thousands)       (unaudited)
Net income/(loss)
    (99,118 )   $ (20,133 )     (119,251 )   $ 345,928  
Depreciation and amortization
    88,928       12,607       101,535       253,399  
Fuel-related depreciation and amortization
    29,079             29,079       10,278  
Interest expense
    126       34,140       34,266       134,306  
Income taxes
    170,479             170,479       20,552  
                         
Texas Genco EBITDA
  $ 189,494     $ 26,614     $ 216,108     $ 764,463  
 
(a) Reflects a combination of Texas Genco LLC and its predecessor, Texas Genco Holdings, Inc., results for the year ended December 31, 2004, combined for presentation purposes only.
 
(5) The following table sets forth a reconciliation of the combined company’s pro forma income from continuing operations to pro forma combined EBITDA:
                   
    Pro Forma Combined Company
     
        For the
    For the Year   Nine Months
    Ended   Ended
    December 31,   September 30,
    2004   2005
         
    (unaudited)   (unaudited)
    ($ in thousands)
Income/(loss) from continuing operations
  $ 182,762     $ 614,493  
Plus
               
 
Income tax expense
    51,077       392,347  
 
Interest expense
    621,650       418,737  
 
Refinancing expense
    71,569       44,036  
 
Depreciation and amortization
    780,250       460,383  
 
Fuel-related depreciation and amortization
    28,017       17,121  
 
Amortization of power contracts
    35,316       6,485  
 
Amortization of emission credits
    141,611       102,431  
 
Amortization of out of market contracts for coal and power sales
    (264,461 )     (1,214,023 )
 
WCP CDWR contract amortization
    115,751        
             
 
Pro forma combined EBITDA
    1,763,542       842,010  

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(6) Our pro forma results include the following items that have had a significant impact on operations during the periods indicated below:
                 
    Pro Forma Combined Company
     
        For the
    For the Year   Nine Months
    Ended   Ended
    December 31,   September 30,
    2004   2005
         
    (unaudited)   (unaudited)
    ($ in thousands)
Corporate relocation charges
    16,167       5,651  
Reorganization items
    (13,390 )      
Impairment charges
    69,009       6,223  
FERC-authorized settlement with CLSP
    (38,357 )      
Write down on notes receivable
    4,572        
Write downs (Gains)/Loss on sales of equity investments
    16,270       (15,894 )
(Gains)/Loss on sale of assets
    (689 )     (28,358 )
Restructuring costs
          35,293  
Transaction costs
    2,694        
Domestic mark to market (gains)/loss
    (55,253 )     235,156  

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RISK FACTORS
      Investing in the notes 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 notes.
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.
      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

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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 upgrading 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 upgrade of current facilities based on our assessment that such activity will provide adequate financial returns. Such projects often require several years of development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. The construction,

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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.
      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

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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 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

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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 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.

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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 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.

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      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 NOx and sulfur dioxide, or SO2, 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 SO2, NOx, 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. 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 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

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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.”
      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.

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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 the notes offered hereby 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;
 
  making it more difficult for us to satisfy our obligations with respect to these notes;
 
  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 notes offered hereby 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.
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

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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
The net proceeds from this offering will be deposited in escrow and we will be required to redeem the notes if we do not consummate the Acquisition on substantially the terms described in this prospectus supplement on or before September 30, 2006.
      This offering will be consummated before, and is not conditioned on, the closing of the Acquisition. The Acquisition cannot close until the remaining conditions precedent have been satisfied or waived. See “The Acquisition—The Acquisition—Certain Terms and Conditions of the Acquisition Agreement.” The net proceeds of this offering (after payment of underwriting discounts and commissions) will be deposited in escrow pending consummation of the Acquisition. If the Acquisition does not occur by September 30, 2006 on substantially the terms described in this prospectus supplement, then the indenture will require that we redeem all the notes at a redemption price equal to 100% of the principal amount plus accrued interest to, but not including, the redemption date. Although we currently believe that all conditions to the Acquisition will be satisfied and expect to consummate the Acquisition before the deadline for the special mandatory redemption, we cannot assure you that the conditions will be satisfied or waived, that we will in fact close the Acquisition on substantially the terms described in this prospectus supplement, or that we will not otherwise have to redeem the notes. If for any reason we believe that the Acquisition will not close before the deadline for special mandatory redemption, we have the option to redeem the notes earlier on the same terms.
If the Acquisition is not completed on or prior to September 30, 2006, NRG may not be able to obtain all the funds necessary to finance the special mandatory redemption required by the indenture.
      The net proceeds of this offering (after payment of underwriting discounts and commissions) will be placed in escrow pending the consummation of the Acquisition. If the Acquisition is not consummated on or prior to September 30, 2006, all of the notes will be subject to a special redemption at a price of 100% of the aggregate principal amount of the notes outstanding on such date plus accrued an unpaid interest. See “Description of the Notes—Escrow of Proceeds; Special Mandatory Redemption.” If NRG redeems the notes, however, you will have to rely on it for payment of amounts in excess of the net proceeds of the offering. In addition, you may not be able to reinvest the proceeds from a special mandatory redemption in an investment that results in comparable returns of the notes offered hereby.
In a bankruptcy proceeding, the holders of notes might not be able to apply the escrowed funds to repay the notes without bankruptcy court approval.
      If we commence a bankruptcy or reorganization case, or one is commenced against us, while the escrow account remains funded, bankruptcy law may prevent the trustee under the indenture governing the notes from using the escrowed funds to pay the special mandatory redemption. The court adjudicating that case might find that the escrow account is the property of the bankruptcy estate. In that event, we believe that the holders of notes would be treated as secured creditors with a security interest in the escrowed funds. However, in a bankruptcy, secured creditors are prohibited from foreclosing upon or disposing of a debtor’s property without prior bankruptcy court approval. As a result, it is possible that holders of notes would not be able to apply the escrowed funds to repay the notes without bankruptcy court approval.
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 notes 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 common stock and mandatory convertible preferred stock. 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. NRG intends to use initial borrowings

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under its new senior secured credit facility, together with the net proceeds from this offering and the offerings of common stock and mandatory convertible preferred stock, 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 common stock offering and/or the mandatory convertible preferred stock offering. See “Description of Certain Other Indebtedness and Preferred Stock—Bridge Loan Facility.”
      In the event that NRG is unable to raise sufficient proceeds through the consummation of the common stock 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. Any borrowings under the bridge loan facility will constitute our senior indebtedness and will rank pari passu with the notes offered hereby. 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 Other Indebtedness and Preferred Stock—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 (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 and prevent us from fulfilling our obligations under the notes.
      In the event that NRG does not consummate the common stock 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. 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. In addition, holders of such senior secured debt would have claims that are prior to your claims as holders of the notes to the extent of the value of the assets securing that other indebtedness. In the event of bankruptcy, liquidation, reorganization or similar proceeding, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of notes may receive less, ratably, than holders of secured indebtedness.
Despite current indebtedness levels, we and our subsidiaries may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial leverage.
      We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the indenture do not fully prohibit us or our subsidiaries from doing so. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could increase. See “Description of Certain Other Indebtedness and Preferred Stock—New Senior Secured Credit Facility.”
To service our indebtedness, we will use a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.
      Our ability to make payments on and to refinance our indebtedness, including these notes, and to fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.

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      Based on our current level of operations and anticipated cost savings and operating improvements, we believe our cash flow from operations, available cash and available borrowings under our new credit facility, will be adequate to meet our future liquidity needs for at least the next 12 months.
      We cannot assure you, however, that our business will generate sufficient cash flow from operations, that currently anticipated cost savings and operating improvements will be realized on schedule or that future borrowings will be available to us under our new credit facility in an amount sufficient to enable us to pay our indebtedness, including these notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including these notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our new credit facility and these notes, on commercially reasonable terms or at all.
In the event of a bankruptcy or insolvency, holders of our secured indebtedness and other secured obligations will have a prior secured claim to any collateral securing such indebtedness or other obligations.
      Holders of our secured indebtedness and the secured indebtedness of the guarantors will have claims that are prior to your claims as holders of the notes to the extent of the value of the assets securing that other indebtedness. Notably, we and certain of our subsidiaries, including the guarantors, will be parties to the new credit facility, which will be secured by liens on substantially all of our assets and the assets of the guarantors. Also, Texas Genco and its subsidiaries have granted hedging counterparties second liens on the assets of Texas Genco and certain of its subsidiaries securing hedging obligations of approximately 2,181 million as of September 30, 2005. In the event of any distribution or payment of our assets in any foreclosure, dissolution, winding-up, liquidation, reorganization, or other bankruptcy proceeding, holders of secured indebtedness will have prior claim to those of our assets that constitute their collateral. Holders of the notes will participate ratably with all holders of our unsecured indebtedness that is deemed to be of the same class as the notes, and potentially with all our other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of notes may receive less, ratably, than holders of secured indebtedness.
Your right to receive payments on these notes could be adversely affected if any of our non-guarantor subsidiaries declare bankruptcy, liquidate or reorganize.
      Some but not all of our subsidiaries will guarantee the notes. In the event of a bankruptcy, liquidation or reorganization of any of our non-guarantor subsidiaries, holders of their indebtedness and their trade creditors will generally be entitled to payment of their claims from the assets of those subsidiaries before any assets are made available for distribution to us. In addition, the indenture governing the notes will permit us, subject to certain covenant limitations, to provide credit support for the obligations of the non-guarantor subsidiaries and such credit support may be effectively senior to our obligations under the notes. Further, the indenture governing the notes will allow us to transfer assets, including certain specified facilities, to the non-guarantor subsidiaries.
We may not have access to the cash flow and other assets of our subsidiaries that may be needed to make payment on the notes.
      Much of our business is conducted through our subsidiaries. Although certain of our subsidiaries will become guarantors of the notes upon closing of the notes offering, some of our subsidiaries will not become guarantors and thus will not be obligated to make funds available to us for payment on the notes. Our ability to make payments on the notes will be dependent on the earnings and the distribution of funds from subsidiaries, some of which are non-guarantors. Our subsidiaries will be permitted under the terms of the indenture to incur additional indebtedness that may restrict or prohibit the making of distributions, the payment of dividends or the making of loans by such subsidiaries to us. We cannot assure you that the agreements governing the current and future indebtedness of our subsidiaries will permit our subsidiaries to provide us with sufficient dividends, distributions or loans to fund payments on the notes when due. Furthermore, certain of our subsidiaries and affiliates are already subject to project financing. Such entities will not guarantee our

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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.
We may not have the ability to raise the funds necessary to finance the change of control offer required by the indenture.
      Upon the occurrence of certain specific kinds of change of control events, we will be required to offer to repurchase all outstanding notes at 101% of the principal amount thereof plus accrued and unpaid interest, if any, to the date of repurchase. However, it is possible that we will not have sufficient funds at the time of a change of control to make the required repurchase of notes or that restrictions in our new credit facility will not allow such repurchases. In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a “Change of Control” under the indenture. See “Description of Notes—Repurchase at the Option of Holders.”
Federal and state statutes allow courts, under specific circumstances, to void guarantees and require note holders to return payments received from guarantors.
      Under the federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee could be voided, or claims in respect of a guarantee could be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee:
  received less than reasonably equivalent value or fair consideration for the incurrence of such guarantee; and
 
  was insolvent or rendered insolvent by reason of such incurrence; or
 
  was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
 
  intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.
      In addition, any payment by that guarantor pursuant to its guarantee could be voided and required to be returned to the guarantor, or to a fund for the benefit of the creditors of the guarantor.
      The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if:
  the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets; or
 
  if the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or
 
  it could not pay its debts as they become due.
      On the basis of historical financial information, recent operating history and other factors, we believe that each guarantor, after giving effect to its guarantee of these notes, will not be insolvent, will not have unreasonably small capital for the business in which it is engaged and will not have incurred debts beyond its ability to pay such debts as they mature. We cannot assure you, however, as to what standard a court would apply in making these determinations or that a court would agree with our conclusions in this regard.

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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 preferred stock issued to the Sellers. As a result of the Acquisition, Texas Genco will become a wholly-owned subsidiary of NRG.
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 $4.031 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, referred to as the Cumulative 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. If NRG elects to pay all or a portion of the remaining purchase price in cash, the amount payable in cash would be calculated in the same manner. 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 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. 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

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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 the notes 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) $1.0 billion of its common stock and (ii) $500 million of its mandatory convertible preferred stock. See “Description of Certain Other Indebtedness and Preferred Stock—Mandatory Convertible Preferred Stock.” This offering, the mandatory convertible preferred stock offering and the common stock 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 common stock offering and/or the closings of the mandatory convertible preferred stock offering. The net proceeds of the offering of these 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 common stock, the mandatory convertible preferred stock 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 will use the net proceeds from this offering to redeem the notes offered hereby. See “Description of the Notes—Escrow of Proceeds; Special Mandatory Redemption” and “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 common stock 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. 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

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the event that sufficient funds are not raised from this offering, the common stock offering and/or the mandatory convertible preferred stock offering. See “Description of Certain Other Indebtedness and Preferred Stock—Bridge Loan Facility.” In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the common stock 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. In the event that NRG does not consummate the common stock 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.

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USE OF PROCEEDS
      We estimate that the net proceeds of this offering, after giving effect to underwriting discounts and commissions, will be approximately $             million. We intend to use the net proceeds from the offering of the notes and the other Financing Transactions, including the offerings of common stock 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 premiums, fees and expenses. The net proceeds of this offering will be placed into an escrow account held by the trustee, as escrow agent, until the consummation of the Acquisition. In the event that NRG does not consummate the Acquisition, NRG will use the net proceeds from this offering to redeem the notes. See “Description of the Notes—Escrow of Proceeds; Special Mandatory Redemption.”
      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 Other Indebtedness and Preferred Stock.”
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. 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.”

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Sources(1)   Amount
     
    (in millions)
Gross proceeds of notes offered hereby
      $ 3,600  
New senior secured term loan facility
        3,200  
Cash released from canceling existing funded letter of credit facility
        350  
Gross proceeds of common stock offering
        1,000  
 
Common stock consideration to be issued to Sellers
  1,606        
 
Preferred stock consideration to be issued to Sellers
  368        
           
   
Total
        1,974 (2)
Gross proceeds of mandatory convertible preferred stock offering
        500  
NRG’s cash on hand
        383  
     
     
Total
      $ 11,007  
     
 
                 
Uses   Amount
     
    (in millions)
Purchase price less acquisition costs(2)
      $ 6,005  
Texas Genco’s cash on hand to reduce consideration(2)
        (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
        476  
     
   
Total
      $ 11,007  
     
(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 common stock offering and/or the mandatory convertible preferred stock offering are not consummated. In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the common stock 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. In the event that NRG does not consummate the common stock 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.
 
(2)  The common stock component of the consideration for the Acquisition is based on a stock price of $45.37 per share of NRG’s common stock and the preferred stock consideration is valued based on an average common stock price of $40.73, as prescribed by the Acquisition Agreement. This is because the foregoing table is based on a pro forma closing date of the 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 old debt structure; (iii) the remaining Financing Transactions and the subsequent Acquisition; and (iv) the acquisition of the remaining 50% of 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.
                                           
    As of September 30, 2005
     
        Cumulative    
        As Adjusted    
        Cumulative   for Audrain,    
        As Adjusted   Refinancing and   Cumulative
        As Adjusted   for Audrain and   Texas Genco   As Adjusted
    Historical   for Audrain   Refinancing(9)   Acquisition   for the Transactions(1)
                     
Cash and cash equivalents
  $ 504.3     $ 519.3     $ 250.1     $ 136.1     $ 152.7  
                               
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
                1,080.4       3,200.0       3,200.0  
Notes offered hereby
                446.6       3,600.0       3,600.0  
Cumulative Redeemable Preferred Stock(5)
                      368.1       368.1  
Existing non-guarantor debt (6)
    607.2       607.2       607.2       607.2       607.2  
                               
 
Total debt, before capital leases
    2,573.8       2,573.8       2,143.8       7,784.9       7,784.9  
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     $ 8,019.3     $ 8,019.3  
3.625% Convertible Preferred Stock
    246.2       246.2       246.2       246.2       246.2  
Mandatory Convertible Preferred Stock(7)
                      486.2       486.2  
Convertible Perpetual Preferred Stock
    406.2       406.2       406.2       406.2       406.2  
 
Other stockholders’ equity(8)
    1,613.0       1,628.2       1,538.6       4,085.7       4,060.5  
                               
Total capitalization
  $ 5,309.6     $ 5,084.9     $ 4,565.3     $ 13,243.6     $ 13,218.4  
                               

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(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 common stock offering and/or the mandatory convertible preferred stock offering are not consummated. In the event that NRG is unable to raise sufficient proceeds through the consummation of this offering, the common stock 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. See “Description of Certain Other Indebtedness and Preferred Stock — Bridge Loan Facility.” In the event that NRG does not consummate the common stock 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.
 
(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)  The Cumulative Redeemable Preferred Stock may be issued to the sellers pursuant to the Acquisition Agreement. The Cumulative Redeemable Preferred Stock can be redeemed, in whole or in part, at NRG’s option, at any time or from time to time, at a per share redemption price equal to 100% of the liquidation preference thereof, together with all accrued and unpaid dividends thereon. Due to these terms, the Cumulative Redeemable Preferred Stock is considered to be a debt instrument under U.S. Generally Accepted Accounting Principles. The dividend rate for the Cumulative Redeemable Preferred Stock begins at 10%, and if the outstanding balance of Cumulative Redeemable Preferred Stock remains above $200 million, the dividend rate increases by 1% each quarter to a maximum of 12%.
 
(6)  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.
 
(7)  The Mandatory Preferred Convertible Stock will be converted on March 16, 2009 and is subject to a 5.5% cumulative annual dividend. The Mandatory Convertible Preferred Stock has a total liquidation preference of $500 million and a conversion rate of                  shares of common stock per share of Mandatory Convertible Preferred Stock and are convertible at the option of the holder at any time.
 
(8)  Pro forma adjustments to Stockholders’ Equity include the issuance of $1.0 billion of common stock in the concurrent common stock offering, and the issuance of common stock and reissuance of treasury stock to the Sellers valued at $1,606.4 million. These amounts are offset 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.
 
(9)  Refinancing reflects the changes due to the refinancing of NRG’s old debt structure.

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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 a period of less than a full year are not necessarily indicative of the results to be expected for any interim period.
                                                                 
    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
                                 
        (unaudited)   (unaudited)
    ($ 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  

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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
                                 
        (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)
    1.81 x     1.26 x    
(3)     9.82 x(4)     1.68 x     1.83 x     1.80 x     1.19 x
Ratio of earnings to combined fixed charges and preference dividends(2)
    1.81 x     1.26 x    
(3)     9.82 x(4)     1.68 x     1.82 x     1.80 x     1.04 x
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  
 
(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   For the
    For the Year   For the Year   For the Year   Period from   Period from   For the Year   Nine Months   Nine Months
    Ended   Ended   Ended   January 1 -   December 6 -   Ended   Ended   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)        
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    
        For the   January 1,   Period from   For the
        Nine Months   2005   July 19, 2004   Nine Months
        Ended   through   through   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 )   $ 0.13     $ (0.13 )   $ 2.05  
Net income (loss) per share—diluted
    2.15       1.60       (1.16 )     3.13       (1.25 )     (2.13 )     0.13       (0.13 )     1.98  
Weighted average shares outstanding—basic (in millions)
    80.0       80.0       80.0       80.0       79.4       80.0       67.8       156.5       168.6  
Weighted average shares outstanding—diluted (in millions)
    80.0       80.0       80.0       80.0       79.4       80.0       67.8       156.5       175.1  
Other Financial Data:
                                                                       
Capital expenditures
  $ 207     $ 409     $ 258     $ 157     $ 73     $ 46.0     $ 9     $ 6     $ 74  
Balance Sheet Data (at period end):
                                                                       
Property, plant and equipment, net(10)
  $ 3,782     $ 4,020     $ 4,096     $ 4,126     $ 474     $ 478     $ 474     $ 2,446     $ 3,542  
Total assets(11)
    4,147       4,438       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(11)(12)
                                              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

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  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.”
 
  (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.”

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(10)  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.
 
(11)  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.
 
(12)  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 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.”
      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 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

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  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 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, 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 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 $5.2 billion to replace our existing senior credit facility. The senior secured credit facility is expected to consist of a $3.2 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 may increase the term facility and/or the revolving credit facility by an amount not to exceed $375 million at any time prior to the maturity date of the relevant facility, upon satisfying certain conditions set forth in the senior secured credit facility as discussed below. Morgan Stanley Senior Funding, Inc., an affiliate of one of the underwriters for this offering, will be the administrative agent and 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.

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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 $3.2 billion from the term loan facility to be used together with the net proceeds of $3.6 billion from this unsecured note offering, the offerings of common stock of $1.0 billion, $0.5 billion in mandatory convertible preferred stock, $368 million from issuing the Sellers Cumulative Redeemable 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 and the assets of our subsidiaries, with certain customary or agreed-upon exceptions for foreign subsidiaries and certain project subsidiaries, 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 five years, respectively, from the closing date of the 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 Other Indebtedness and Preferred Stock — 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 Other Indebtedness and Preferred Stock — 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 $8.3 billion of indebtedness, which includes the notes and amounts outstanding under our new senior secured credit facility. Of this total, approximately $3.2 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 (a) the sale of Audrain; (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, 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 85% of

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our consolidated assets as of September 30, 2005, and our non-guarantor subsidiaries would have had approximately $800 million in aggregate principal amount of funded indebtedness as of September 30, 2005. Our outstanding consolidated trade payables would have been $322.0 million as of September 30, 2005, on a pro forma basis. On a pro forma basis, approximately 75% 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 $275.5 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 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 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 Other Indebtedness and Preferred Stock.” 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 common stock offering and/or the mandatory convertible preferred stock offering described elsewhere in this 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 Other

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Indebtedness and Preferred Stock—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 common stock 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 could 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
      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.
      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 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 “FORNRG,” 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

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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
(PIE CHART)   (PIE CHART)   (PIE CHART)
 
(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

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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.
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:
(MAP)
     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       1,372       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  

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(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.
 
(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

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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.
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 totaling $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 transporta-

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tion 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.
      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 Other Indebtedness and Preferred Stock” 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.

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      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, 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 NOx 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
                 
    Control   Install   Control   Install   Control   Install   Control   Install
Units   Equipment   Date   Equipment   Date   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 “FORNRG,” or Focus on ROIC@NRG. Projects are focused on improving plant performance, reducing purchasing and other costs and streamlining processes. A large number of initiatives are currently underway in 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

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suppliers with our combined volumes and to incorporate existing and future Texas Genco processes under the FORNRG 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.
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:
                 
        Benchmark
    Average 5-Year   Average
    Availability   Availability
    Factor   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.

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      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.
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
Limestone
  Jewett, TX     100%       1,614     Lignite/Low Sulfur 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,

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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 NOx, control systems from 1999 to 2004. Each of the four coal-fired units has low-NOx burners and selective catalytic reduction, or SCR, installed to reduce NOx emissions. In addition, W. A. Parish Unit 8 has a scrubber installed to reduce sulfur dioxide, or SO2, 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.
      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 NOx emissions and scrubbers to reduce SO2 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 73 MW (32 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 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.

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Market Framework
      The ERCOT market is one of the nation’s largest and fastest growing power markets. It represents approximately 85% of the demand for power in Texas and covers the whole state, with the exception of the far west (El Paso), a large part of the Texas Panhandle and two small areas in the eastern part of the state. From 1994 through 2004, peak hourly demand in the ERCOT market grew at a compound annual rate of 3.0%, compared to a compound annual rate of growth of 2.1% in the United States for the same period. For 2004, hourly demand ranged from a low of 20,276 MW to a high of 58,506 MW. ERCOT has limited interconnections—currently limited to 856 MW of generation capacity—to other markets in the United States, and wholesale transactions within ERCOT are not subject to regulation by FERC. Any wholesale producer of power that qualifies as a power generation company under the Texas electric restructuring law and that can access the ERCOT electric power grid is allowed to sell power in the ERCOT market at unregulated rates.
      The ERCOT market has experienced significant construction of new generation plants in recent years, with over 20,000 MW of mostly natural gas-fired combined cycle generation capacity added to the market since 2000. As of 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.

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

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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 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.

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      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.
      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

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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 Turbines
    Various locations 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 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

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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 8,090 pounds and 8,690 pounds, 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 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.

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     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    
Plant   Location   % Owned   (MW)   Primary
                 
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
     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

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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, Forms 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% 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

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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.
      NRG’s power generation assets in the Western region as of September 30, 2005 are summarized in the table below:
                           
            Net    
            Generation    
            Capacity   Primary
Plant   Location   % Owned   (MW)   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.

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     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 NOx 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 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. On December 16, 2005, the Cal ISO approved a plan to increase the bid cap from a $250 per MWh “soft cap” to a $400 per MWh “hard cap,” meaning bidders would not be allowed to bid above that set cap level. The Cal ISO has filed the new cap for approval by FERC, and has asked that it be retroactive to January 1, 2006, and it is expected that FERC will approve the increase. NRG is working with various industry groups and governmental authorities to put market reforms in place in California that will

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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.”
      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
Plant   Location   % Owned   MW   Fuel 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          
                       

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(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 - 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 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

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day. NRG’s Resource Recovery business owns and operates NRG Processing Solutions, which includes 13 composting and processing sites in Minnesota, of which three 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 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.

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      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.
      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

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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 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

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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 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.

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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 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

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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.
      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

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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 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 payment has not been made to date as WCP has requested the Santa Monica Bay Restoration Fund to establish a trust in which to place the funds. Documentation is being exchanged between the parties to establish that trust. The CEC could subject WCP to fines and/or termination of the permit for failure to make the initial or subsequent payments. The project filed an application with the CEC to suspend the payments until a suitable long-term off take agreement was secured that would support financing. On November 5, 2005, by a 5-0 vote, the CEC denied the application to suspend requiring the project to remit the first $250,000 payment 30 days following that vote. 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

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anticipated megawatts added will be less than the number of megawatts retired. The California Court of Appeals, in a case involving the Los Angeles Department of Water and Power, held that the CEC jurisdiction is only required where the total megawatts added exceed the existing megawatts of capacity by over 50 megawatts.
      In California, the Cal ISO continues with its plan to move toward markets similar to PJM, NYISO and ISO-NE with its Market Redesign & Technology Upgrade, or MRTU—formerly MD02. These changes, once implemented, will re-establish a day-ahead time market and allow for multiple settlements. We view this as a vast improvement to the existing structure. In general, the Cal ISO is continuing along a path of small incremental changes rather than significant market restructuring. Although numerous stakeholder meetings have been held, the final market design remains unknown at this time. The effect of the new MRTU changes on us cannot be determined at this time. In addition to that activity, the California Public Utility Commission, or CPUC, recently issued their Resource Adequacy Order, which we believe will ultimately create greater opportunities for merchant generators in California. However, the final order did delay the implementation of local capacity requirements and allowed a liberalized phase out of firm liquidated damages contracts, which may act as a disincentive for load serving entities to contract for our capacity over the next two years. Assembly Bill 1576 which will promote and codify the recovery of costs from repowered facilities—thus making contracting from these sites more attractive to the in-state-utilities, was passed by the Senate on September 8, 2005, and signed by the Governor on September 29, 2005. This provides opportunities for the Western region, as WCP currently holds a permit for repowering up to 630 MW at the El Segundo facility and options for redevelopment at the Long Beach facility. Both facilities are positioned for possible long-term contracts as the market rules and structure fall into place in the near future.
      The CEC recently issued their 2005 Energy Report—Range of Need and Policy Recommendations To the California Public Utilities Commission, or CPUC. That study confirmed that the SCE franchise territory will require over 8,000 MW of new generation capacity by 2009; a dire prediction for a state with limited new resources coming on line and retirement of older facilities accelerating. There is some indication that the various regulatory agencies are responding to these warnings by moving to design a market that will provide the incentives to invest in new generation. The CPUC now requires that load-serving entities meet a 15-17% reserve margin by June 2006. This has prompted RFOs from load-serving entities, with the stated goal of engaging in bilateral contract negotiations with the merchant generators to secure their long-term capacity needs. Load-serving entities must demonstrate, by January 27, 2006 and by September 30 for each year thereafter that they have secured at least 90% of their capacity needs for the following year. The CPUC order requiring a demonstration of adequate capacity should present opportunities to enter into new bilateral agreements pursuant to competitive RFO processes. The Red Bluff and Chowchilla facilities have received capacity contracts for the period April 1, 2006 through December 31, 2007 from a major load serving entity. The capacity for El Segundo Units 3 and 4 has been secured under a tolling agreement with a major load serving entity for the period May 2006 through April 2008.
      In September 2004, Governor Schwarzenegger vetoed AB2006, commonly referred to as the “re-regulation” initiative. A proposition (Proposition 80) that would amend legislation forever prohibiting “customer choice” in California was defeated in a November 2005 special election.
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

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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 NOx emissions from power plants in two phases (2010 and 2015 for SO2 and 2009 and 2015 for NOx). 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 SO2 and NOx 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 on 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 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

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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 NOx emissions rates in the country. In aggregate, the Texas Genco plants are in compliance with current NOx emission limits and are not expected to incur material environmental capital expenditures to ensure NOx emissions compliance in the next several years. The Texas Commission on Environmental Quality has, however, initiated a rulemaking process for establishing lower NOx 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 NOx 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 NOx 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 NOx allowance be held for each ton of NOx 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 NOx 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 NOx allowances. Any obligation to purchase a substantial number of additional NOx 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 SO2 and NOx emissions from sources including power plants of a certain vintage) through the installation of Best Available Retrofit Technology, or BART, in certain cases. States must develop implementation plans by December 2007 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 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 NOx, SO2, mercury, and, in some instances, CO2. While the Administration’s proposed Clear Skies Act (which would regulate the aforementioned pollutants except for CO2) stalled in Senate Committee on March 9, 2005, the Bush Administration continues to support this legislation. Clear

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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 CO2 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 US 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.
      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 public comment through February 17, 2006.

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      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 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.

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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 NOx, SO2, mercury, and CO2. 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 NOx and SO2 limits. On June 4, 2004, the Massachusetts Department of Environmental Protection, or MADEP, issued its regulation on the control of mercury emissions. The effect of this regulation is that starting October 1, 2006, Somerset will be capped at 13.1 lbs/year of mercury 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 CO2 emission restrictions. A carbon emissions cap applies beginning January 1, 2006, while a rate requirement will apply in 2008. This regulation means that if CO2 emissions at NRG’s Somerset facility exceed the annual cap from 2006, then the excess must be offset with approved CO2 credits. However, since there are currently no approved CO2 credits for use in Massachusetts, MADEP has proposed that generators annually report overages, starting in 2006, and at the time that there is a an established CO2 market operating in the state, NRG would be required to purchase or generate sufficient CO2 credits to offset the balance. On December 20, 2005, Massachusetts issued proposed revisions to the CO2 regulations, including a proposed implementing regime that could allow the use of on-site and off-site generated CO2 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 Memorandum of Understanding with other northeastern states. Given the regulatory uncertainty surrounding implementation of Massachusetts’s carbon market and the corresponding costs of CO2 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 NOx emissions limit year-round. Our strategy for complying with the ADRP is to generate early reductions of SO2 and NOx 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 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.

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      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 SO2, NOx 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 (SO2, NOx, mercury and CO2) 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 NOx (to 1.87 million tons) and SO2 (to 3.0 million tons) apply; (d) 2012 Phase II reductions of NOx (to 1.28 million tons) and SO2 (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 NOx reductions would be 25% greater than CAIR, while SO2 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 CO2 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 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

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compliance with applicable NAAQS. NRG participated in development of the revisions, which require the reduction of NOx 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 NOx, 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 NOx 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, NOx regulations on January 7, 2005. RECLAIM is a regional emission-trading program targeting NOx reductions to achieve state and federal ambient air quality standards for ozone. Among other changes, the amendments reduce the NOx RECLAIM Trading Credit, or RTC, holdings of El Segundo Power, LLC and Long Beach Generation LLC facilities by certain amounts. Notwithstanding these amendments, retained RTCs are expected to be sufficient to operate El Segundo Units 3 and 4 as high as 100% capacity factor for the life of those units.
      On 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 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.
      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

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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.
      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,

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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 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 CO2 trading program to be a material constraint on our business in Germany. Changes to the German Emission Control Directive will result in lower NOx 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 NOx 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

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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. 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.

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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. In October 2005, the plaintiff petitioned the U.S. Supreme Court to review the case.
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 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. Texas Genco, LP has appealed the final judgment. The trial court has reinstated the temporary injunction pending the resolution of Texas Genco, LP’s appeal. The trial court also ordered, and Texas Genco, LP posted, a bond in the amount of approximately $860,000 (to be increased on a monthly basis after February 2006) in connection with the temporary injunction pending appeal.
      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

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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 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 September 30, 2005, there were 3,864 claims pending against Texas Genco Holdings, Inc., a wholly-owned subsidiary of Texas Genco LLC. For the nine months ended September 30, 2005, there were 211 claims filed against Texas Genco Holdings, Inc., 116 claims settled, 1,173 claims dismissed or otherwise resolved with no payment and the average settlement amount for each claim was approximately $3,300. 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

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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.
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

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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.
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 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.

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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. The period to request an en banc rehearing by the Second Circuit has been extended.
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. NiMo and FERC filed their briefs and the remaining briefs are due on January 17, 2006.
      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 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

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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. Itiquira responded to Inepar’s request by filing objections. Due to the uncertainty of the collection process, NRG is accounting for receipt of any amounts as a gain contingency.
CFTC Trading Litigation
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