Edgar Filing: NRG ENERGY, INC.

FORM 424B3

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 23, 2006

PRELIMINARY PROSPECTUS SUPPLEMENT

(To Prospectus dated December 21, 2005)

$3,600,000,000

NRG Energy, Inc.

$ FLOATING RATE SENIOR NOTES DUE 2014

$ % SENIOR NOTES DUE 2014

$ % SENIOR NOTES DUE 2016

We are offering Floating Rate Senior Notes due 2014, or the 2014 floating rate notes, % Senior Notes due 2014, or the 2014 fixed rate notes, and % Senior Notes due 2016, or the 2016 notes. We will pay interest on the 2014 fixed rate notes and 2016 notes on February 1 and August 1 of each year, beginning August 1, 2006. We will pay interest on the 2014 floating rate notes on February 1, May 1, August 1, and November 1 of each year, beginning May 1, 2006. The 2014 floating rate notes and 2014 fixed rate notes will mature on February 1, 2014, and the 2016 notes will mature on February 1, 2016.

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-18 of this prospectus supplement.

Proceeds, before

Public

Underwriting

expenses, to

Offering Price

Discounts

NRG Energy, Inc.

Per 2014 floating rate note

Total

Per 2014 fixed rate note

Total

Per 2016 note

Total

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.

TABLE OF CONTENTS


		Page

Prospectus Supplement
About This Prospectus Supplement			ii
Where You Can Find More Information			ii
Incorporation of Certain Documents by Reference			ii
Disclosure Regarding Forward-Looking Statements			iii
Market and Industry Data			iv
Summary			S-1
Risk Factors			S-18
The Acquisition			S-36
Use of Proceeds			S-39
Capitalization			S-41
Selected Consolidated Financial Information of NRG			S-43
Selected Consolidated Financial Information of Texas Genco			S-45
Liquidity and Capital Resources Discussion			S-49
Business			S-54
Management			S-103
Certain Relationships and Related Party Transactions			S-108
Description of the Notes			S-109
Description of Certain Other Indebtedness and Preferred Stock			S-160
Certain U.S. Federal Income Tax Considerations			S-167
Underwriting			S-169
Legal Matters			S-171
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

About This Prospectus Supplement

This document consists of two parts. The first part is this prospectus supplement, which describes the specific terms of this offering. The second part is the accompanying prospectus, which describes more general information, some of which may not apply to this offering. You should read both this prospectus supplement and the accompanying prospectus, together with additional information described below under the headings “Where You Can Find More Information” and “Incorporation of Certain Documents by Reference.”

If the description of the offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

Any statement made in this prospectus supplement or in a document incorporated or deemed to be incorporated by reference in this prospectus supplement will be deemed to be modified or superseded for purposes of this prospectus supplement to the extent that a statement contained in this prospectus supplement or in any other subsequently filed document that is also incorporated or deemed to be incorporated by reference in this prospectus supplement modifies or supersedes that statement. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to constitute a part of this prospectus supplement. See “Incorporation of Certain Documents By Reference.”

Where You Can Find More Information

NRG files annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission, or the SEC. You can inspect and copy these reports, proxy statements and other information at the Public Reference Room of the SEC, 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. NRG’s SEC filings will also be available to you on the SEC’s website at http://www.sec.gov and through the New York Stock Exchange, 20 Broad Street, New York, NY 10005, on which NRG’s common stock is listed.

This prospectus supplement and the accompanying prospectus, which forms a part of the registration statement, do not contain all the information that is included in the registration statement. You will find additional information about us in the registration statement. Any statements made in this prospectus supplement or the accompanying prospectus concerning the provisions of legal documents are not necessarily complete and you should read the documents that are filed as exhibits to the registration statement or otherwise filed with the SEC for a more complete understanding of the document or matter.

Incorporation of Certain Documents by Reference

The SEC allows the “incorporation by reference” of the information filed by NRG with the SEC into this prospectus supplement, which means that important information can be disclosed to you by referring you to those documents and those documents will be considered part of this prospectus supplement. Information that NRG files later with the SEC will automatically update and supersede the previously filed information. The documents listed below and any future filings NRG makes with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, are incorporated by reference herein, after the date of this prospectus supplement but before the end of any offering made under this prospectus supplement:


	1.	NRG’s annual report on Form 10-K for the year ended December 31, 2004 filed on March 30, 2005 as amended by the current report on Form 8-K filed on December 20, 2005.

2. NRG’s Definitive Proxy Statement on Schedule 14A filed on April 12, 2005.


	3.	NRG’s quarterly reports on Form 10-Q for the quarters ended March 31, 2005 (filed on May 10, 2005), June 30, 2005 (filed on August 9, 2005) and September 30, 2005 (filed on November 7, 2005).

	4.	NRG’s current reports on Form 8-K filed on February 24, 2005, Form 8-K filed on March 3, 2005, two Forms 8-K filed on March 30, 2005 (which do not include information deemed “furnished”),


		Form 8-K filed on May 24, 2005, Form 8-K/ A filed on May 24, 2005, Form 8-K/ A filed on May 25, 2005, Form 8-K filed on June 15, 2005, Form 8-K/ A filed on June 15, 2005, Form 8-K filed on June 17, 2005, Form 8-K filed on July 18, 2005, Form 8-K filed on August 1, 2005, Form 8-K filed on August 3, 2005, Form 8-K filed on August 9, 2005 (which does not include information deemed “furnished”), Form 8-K filed on August 11, 2005, Form 8-K filed on September 1, 2005, Form 8-K filed on September 7, 2005 (which does not include information deemed “furnished”), Form 8-K filed on October 3, 2005, Form 8-K filed on October 12, 2005, Form 8-K filed on November 7, 2005 (which does not include information deemed “furnished”), Form 8-K filed on December 20, 2005, Form 8-K filed on December 21, 2005, Form 8-K filed on December 28, 2005 (which does not include information deemed “furnished”), Form 8-K filed on January 4, 2006, Form 8-K filed on January 5, 2006, Form 8-K/A filed on January 5, 2006, Form 8-K filed on January 13, 2006, Form 8-K filed on January 23, 2006 and Form 8-K/A filed on January 23, 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;

iii


	•	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.

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 “2014 floating rate notes” refers to NRG’s Floating Rate Senior Notes due 2014 offered pursuant to this prospectus supplement;

	•	the term “2014 fixed rate notes” refers to NRG’s % Senior Notes due 2014 offered pursuant to this prospectus supplement;

	•	the term “2016 notes” refers to NRG’s % Senior Notes due 2016 offered pursuant to this prospectus supplement;

	•	the term “2014 notes” refers to the 2014 floating rate notes and the 2014 fixed rate notes, collectively;

	•	the term “notes” refers to the 2014 notes and the 2016 notes, collectively;

	•	the term “2014 floating rate indenture” refers to the base indenture dated December 21, 2005, as supplemented by the 2014 floating rate supplemental indenture to be dated February , 2006 among NRG, the Guarantors and Law Debenture Trust Company, as trustee;

	•	the term “2014 fixed rate indenture” refers to the base indenture dated December 21, 2005, as supplemented by the 2014 fixed rate supplemental indenture to be dated February , 2006 among NRG, the Guarantors and Law Debenture Trust Company, as trustee;

	•	the term “2016 indenture” refers to the base indenture dated December 21, 2005, as supplemented by the 2016 notes supplemental indenture to be dated February , 2006 among NRG, the Guarantors and Law Debenture Trust Company, as trustee;

	•	the term “indentures” refers to the 2014 floating rate indenture, the 2014 fixed rate indenture and the 2016 indenture, collectively;

	•	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).

S-1

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 during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.

The Texas Genco Acquisition

On September 30, 2005, NRG entered into an acquisition agreement, or the Acquisition Agreement, with Texas Genco and each of the direct and indirect owners of equity interests in Texas Genco, or the Sellers. Pursuant to the Acquisition Agreement, NRG agreed to purchase all of the outstanding equity interests in Texas Genco for a total pro forma purchase price of approximately $6.121 billion that includes the assumption of approximately $2.7 billion of indebtedness. The purchase price is subject to adjustment, and includes an equity component valued at approximately $2.0 billion based on a price per share of $45.37 of NRG’s common stock issued to the Sellers, and an average price per share of $40.73 for the consideration with a fair value of $368 million, or the Other Consideration. As a result of the Acquisition, Texas Genco will become a wholly-owned subsidiary of NRG. Each of NRG’s and the Sellers’ obligation to consummate the Acquisition is subject to certain customary conditions, including the receipt of required regulatory consents and approvals. See “The Acquisition” for a discussion of the Acquisition.

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

S-2

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.

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

S-3

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.

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.”

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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, among other alternatives, the issuance in part of senior secured debt securities or borrowing in part on a senior secured basis.

S-5

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 2014 floating rate notes offered hereby			$	300
Gross proceeds of 2014 fixed rate notes offered hereby				1,100
Gross proceeds of 2016 notes offered hereby				2,200
New senior secured term loan facility				3,575
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	⁽²⁾
Gross proceeds of mandatory convertible preferred stock offering				500

NRG’s cash on hand				383


	Total		$	11,014


Uses			Amount

			(in millions)
Purchase price less acquisition costs⁽²⁾				$	6,005
Texas Genco’s cash on hand to reduce consideration					(222	)
Refinancing:
	Repayment of NRG’s existing credit facilities⁽³⁾		877
	Repayment of Texas Genco’s existing credit facilities ⁽⁴⁾		1,614

		Total repayment of existing credit facilities			2,491
Repurchase of NRG’s Second Priority Notes⁽⁵⁾					1,080
Repurchase of Texas Genco’s Unsecured Senior Notes⁽⁶⁾					1,125
Accrued interest for NRG and Texas Genco outstanding debt					52
Estimated underwriting commissions, tender offer premiums, fees and expenses					483


		Total		$	11,014


(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 fair value of $45.37 per share of NRG’s common stock and consideration with a fair value of $368 million, or the Other Consideration, which may be comprised of either an additional 9,038,125 shares of common stock, additional cash, shares of a new series of NRG’s Cumulative Preferred Stock or a combination of the foregoing. This fair value is based on an average stock price of $40.73, as prescribed by the Acquisition

S-6

Agreement. The Company has elected to pay this amount in cash. This is because the foregoing table is based on a pro forma closing date of the Acquisition of September 30, 2005. To the extent the fair value of NRG’s common stock price for purposes of the equity component, and Texas Genco’s cash on hand, is different at closing of the Acquisition, this amount and the purchase price for the Acquisition will be adjusted accordingly.


(3)	Before giving effect to the Acquisition and the Financing Transactions, as of September 30, 2005, NRG had $876.6 million of outstanding indebtedness under its amended and restated credit facility, which consisted of (a) $446.6 million in term loans outstanding, which term loans provide for interest at a rate of LIBOR (4.02% at September 30, 2005) plus 187.5 basis points payable quarterly and mature on December 24, 2011, (b) $80.0 million in principal amount outstanding under the revolving credit facility, which provides for interest at a rate of LIBOR (3.83% at September 30, 2005) plus 2.5% and matures on December 24, 2007 and (c) $350.0 million outstanding under the funded letter of credit facility, which provide for a participation fee of 1.875%, a deposit fee of 0.10%, and an issuance fee of 0.25%, and matures on December 24, 2011.

(4)	Before giving effect to the Acquisition and Financing Transactions, as of September 30, 2005, Texas Genco had $1,614 million in term loans outstanding under its existing senior secured credit facility, which term loans provide for interest at a rate of 5.94% (as of September 30, 2005) payable at least quarterly and mature in December 2011.

(5)	Before giving effect to the Acquisition and Financing Transactions, as of September 30, 2005, NRG had $1.08 billion of Second Priority Notes outstanding, which provide for cash interest at 8.0% per annum payable semiannually.

(6)	Before giving effect to the Acquisition and Financing Transactions, as of September 30, 2005, Texas Genco had $1.125 billion of Unsecured Senior Notes outstanding, which provide for cash interest at 6.875% per annum payable semiannually.

Recent Developments

Acquisitions and Dispositions

We anticipate that the following transactions will be consummated after the Acquisition and Financing Transactions.

On December 8, 2005, NRG entered into an asset purchase and sale agreement to sell NRG Audrain Generating LLC, or Audrain, a gas fired 577 MW peaking facility in Vandalia, Missouri to AmerenUE, a subsidiary of Ameren Corporation. The purchase price is $115 million, subject to customary purchase price adjustments, plus the assumption of $240 million of non-recourse capital lease obligations and assignment of a $240 million note receivable. Of the $115 million in cash proceeds, approximately $93 million of the proceeds will be paid to the project lenders with the balance of approximately $22 million paid to NRG. This transaction, which is subject to regulatory approval, is expected to close during the first half of 2006.

On December 27, 2005, NRG entered into two purchase and sale agreements with Dynegy Inc., or Dynegy, through which the companies will each simultaneously purchase the other’s interest in two jointly held entities that own power generation facilities in the states of California and Illinois, respectively. Under the purchase and sale agreement for the California interests, NRG will acquire Dynegy’s 50% interest in WCP (Generation) Holdings LLC, or WCP Holdings, for a purchase price of $205 million. As a result of this transaction, NRG will become the sole owner of power plants totaling approximately 1,800 MW in southern California. Pursuant to the terms of the purchase and sale agreement for the Illinois interests, NRG will sell to Dynegy its 50% ownership interest in the jointly held entity that owns the Rocky Road power plant, a 330 MW natural gas-fired peaking facility near Chicago, for a purchase price of $45 million. NRG will effectively fund the net purchase price of $160 million with cash held by West Coast Power LLC, or WCP. The transactions, which are conditioned upon each other and subject to regulatory approval, are expected to close in the first quarter of 2006.

These transactions have been reflected in our pro forma financial statements as filed on our amended Current Report on Form 8-K/A filed on January 23, 2006 and 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:


(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.”

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		$ in aggregate principal amount of Floating Rate Senior Notes due 2014.

		$ in aggregate principal amount of % Senior Notes due 2014.

		$ in aggregate principal amount of % Senior Notes due 2016.

Maturity Date		The 2014 notes will mature on February 1, 2014.

		The 2016 notes will mature on February 1, 2016.

Interest Rates		The 2014 floating rate notes will accrue interest from the date of their issuance at a floating rate per year equal to LIBOR (as defined) plus %, and will be reset and payable quarterly on each February 1, May 1, August 1 and November 1.

		The 2014 fixed rate notes will accrue interest at a rate per year equal to %.

		The 2016 notes will accrue interest at a rate per year equal to %.

Interest Payment Dates		We will pay interest on the 2014 fixed rate notes and 2016 notes on February 1 and August 1 of each year, commencing August 1, 2006.

		We will pay interest on the 2014 floating rate notes on February 1, May 1, August 1 and November 1, commencing May 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 90% of our revenues from wholly-owned operations for the nine months ended September 30, 2005 and held approxi-

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		mately 90% of our consolidated assets as of September 30, 2005, and (ii) our non-guarantor subsidiaries had approximately $781 million 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		On or after February 1, 2008, we can redeem some or all of the 2014 floating rate notes at the redemption prices listed in the “Description of the Notes—Optional Redemption—2014 Floating Rate Notes” section of this prospectus supplement, plus accrued and unpaid interest.

		We may redeem some or all of the 2014 fixed rate notes at any time prior to February 1, 2010 at a price equal to 100% of the principal amount of the 2014 fixed rate notes redeemed plus a “make-whole” premium and accrued and unpaid interest. On or after February 1, 2010, we can redeem some or all of the 2014 fixed rate notes at the redemption prices listed in the “Description of the Notes—Optional Redemption—2014 Fixed Rate Notes” section of this prospectus supplement, plus accrued and unpaid interest.

		We may redeem some or all of the 2016 notes at any time prior to February 1, 2011 at a price equal to 100% of the principal amount of the 2016 notes redeemed plus a “make-whole”’ premium and accrued and unpaid interest. On or after February 1, 2011, we can redeem some or all of the 2016 notes at the redemption prices listed in the “Description of the Notes—Optional Redemption—2016 Notes” section of this prospectus supplement, plus accrued and unpaid interest.

		Prior to February 1, 2008, we may redeem up to 35% of the 2014 floating rate notes issued under the 2014 floating rate indenture with the net cash proceeds of certain equity offerings, provided at least 65% of the aggregate principal amount of the 2014 floating rate notes issued in this offering remains outstanding after the redemption.

		Prior to February 1, 2009, we may redeem up to 35% of the 2014 fixed rate notes issued under the 2014 fixed rate indenture with the net cash proceeds of certain equity offerings, provided at least 65% of the aggregate principal amount of the 2014 fixed rate notes issued in this offering remains outstanding after the redemption.

		Prior to February 1, 2009, we may redeem up to 35% of the 2016 notes issued under the 2016 indenture with the net cash proceeds of certain equity offerings, provided at least 65% of the aggregate principal amount of the 2016 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

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		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 indentures governing the notes will contain certain covenants that will, among other things, limit our ability and the 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 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. See “Description of the Notes—Escrow of Proceeds; Special Mandatory Redemption.”

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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 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

S-13

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			183,286			617,507
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		$	0.96		$	4.02
Earnings per share-Diluted	$	1.85		$	(0.13	)	$	0.07		$	1.98		$	0.96		$	3.70
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			1,763,642			842,040
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			153,967
Restricted cash		109,633			—			91,508			—			NA			91,508
Total Assets		7,830,283			4,587,566			7,795,367			6,098,723			NA			20,818,402
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

S-15


	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


(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	$	(151,464	)	$	26,614		$	(124,850	)	$	764,463

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(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		$	183,286		$	617,507
Plus
	Income tax expense		51,418			394,319
	Interest expense		620,885			413,781
	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		1,763,642			842,040


(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 and the 2014 floating rate notes 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 indentures for the notes offered hereby contain, 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 indentures 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 indentures.

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 indentures 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 indentures 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 indentures 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 indentures 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 indentures 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 indentures.*

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 indentures. 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 Other Consideration 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 $4.399 billion in cash, subject to adjustment, and issue a minimum of 35,406,320 shares of NRG’s common stock. The remaining consideration is to be comprised of an additional 9,038,125 shares of common stock, or at NRG’s election, the equivalent in the form of common stock, additional cash or shares of a new series of NRG’s Cumulative Redeemable Preferred Stock, or any combination of the foregoing. If issued, the aggregate liquidation preference of the Cumulative Preferred Stock will be determined by reference to the average price of NRG’s common stock over a 20 trading day period prior to the closing of the Acquisition, which on a pro forma basis is $40.73. NRG has elected to pay this amount in cash. The purchase price payable by NRG is subject to adjustment based on the level of Texas Genco’s working capital, the amount of Texas Genco’s indebtedness and the amount of Texas Genco’s cash and cash equivalents on hand, all as of the closing date.

The Acquisition Agreement contains customary terms and conditions, including representations and warranties of NRG, Texas Genco and the Sellers and covenants of NRG and Texas Genco with respect to the conduct of their businesses prior to the closing of the Acquisition. Pending closing of the Acquisition, Texas Genco and NRG are obligated to conduct their businesses in the ordinary course of business, to preserve their business, assets, properties and relationships, and to refrain from certain activities without prior written consent of the other party, such consent not to be unreasonably withheld or delayed.

The obligations of NRG, on the one hand, and Texas Genco and the Sellers, on the other, to consummate the Acquisition are subject to the satisfaction or waiver of various conditions, including: the other party or parties having performed their agreements, covenants and obligations required by the Acquisition Agreement in all material respects and having delivered certain certificates and other documents, the representations and warranties of the other party or parties being true and correct on the date of the Acquisition Agreement and the closing date (except for inaccuracies that would not, individually or in the aggregate, have a Material Adverse Effect (as defined in the Acquisition Agreement)), no Law or Order (each as defined in the Acquisition Agreement) being in effect on the closing date that would prohibit the consummation of the acquisition or related transactions, no Material Adverse Effect on the other party having occurred since June 30, 2005, the parties having received all consents and approvals of, and made all filings with various governmental authorities necessary to consummate the acquisition and related transactions, including with respect to the NRC and FERC, and any applicable terminations or expirations of waiting periods having 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.”

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

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Sources⁽¹⁾	Amount

	(in millions)
Gross proceeds of 2014 floating rate notes offered hereby		$	300
Gross proceeds of 2014 fixed rate notes offered hereby			1,100
Gross proceeds of 2016 notes offered hereby			2,200
New senior secured term loan facility			3,575
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	⁽²⁾
Gross proceeds of mandatory convertible preferred stock offering			500

NRG’s cash on hand			383

Total		$	11,014


Uses			Amount

			(in millions)
Purchase price less acquisition costs⁽²⁾				$	6,005
Texas Genco’s cash on hand to reduce consideration					(222	)
Refinancing:
	Repayment of NRG’s existing credit facilities		877
	Repayment of Texas Genco’s existing credit facilities		1,614

		Total repayment of existing credit facilities			2,491
Repurchase of NRG’s Second Priority Notes					1,080
Repurchase of Texas Genco’s Unsecured Senior Notes					1,125
Accrued interest for NRG and Texas Genco outstanding debt					52
Estimated underwriting commissions, tender offer premiums, fees and expenses					483

		Total		$	11,014


(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 fair value of $45.37 per share of NRG’s common stock and the Other Consideration is valued based on an average common stock price of $40.73, as prescribed 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	$	137.3	$	153.9

Restricted cash			91.5		91.5		91.5		91.5		91.5

Long-term debt (including revolving line of credit):
Old Senior Secured Credit Facility:
	Old Term Loan Facility		796.6		796.6		—		—		—
	Old Revolving Credit Facility⁽²⁾		80.0		80.0		—		—		—
Outstanding Second Priority Notes⁽³⁾			1,080.4		1,080.4		—		—		—
Xcel Energy Note⁽⁴⁾			9.6		9.6		9.6		9.6		9.6
New Senior Secured Credit Facility			—		—		446.6		3,575		3,575
2016 Notes offered hereby			—		—		1,080.4		2,200		2,200
2014 Fixed Rate Notes offered hereby			—		—		—		1,100		1,100
2014 Floating Rate Notes offered hereby			—		—		—		300		300
Existing non-guarantor debt ⁽⁵⁾			607.2		607.2		607.2		607.2		607.2

	Total debt, before capital leases		2,573.8		2,573.8		2,143.8		7,791.8		7,791.8

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		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⁽⁸⁾		Acquisition		for the Transactions⁽¹⁾

Capital leases			470.4		230.5		230.5		234.4		234.4

	Total debt and capital leases	$	3,044.2	$	2,804.3	$	2,374.3	$	8,026.2	$	8,026.2
3.625% Convertible Preferred Stock			246.2		246.2		246.2		246.2		246.2
Mandatory Convertible Preferred Stock⁽⁶⁾			—		—		—		486.2		486.2
Convertible Perpetual Preferred Stock			406.2		406.2		406.2		406.2		406.2
	Other stockholders’ equity⁽⁷⁾		1,613.0		1,628.2		1,538.6		4,085.7		4,060.5

Total capitalization		$	5,309.6	$	5,084.9	$	4,565.3	$	13,250.5	$	13,225.3


(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)	As of September 30, 2005, existing non-guarantor debt has been reduced by $59.0 million as a result of marking the debt to a market rate in connection with NRG’s Fresh Start reporting on December 5, 2003. For more information on the various components of NRG’s debt, refer to Note 18 to NRG’s audited consolidated financial statements as of and for the year ended December 31, 2004 as amended on our Current Report on Form 8-K filed on December 20, 2005 incorporated herein by reference.

(6)	The Mandatory Preferred Convertible Stock will be converted on March 16, 2009 and is subject to a 6% 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.

(7)	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 impacted by a $15.3 million gain on the sale of Audrain, a $25.2 million loss from the sale of Rocky Road and closing costs net of tax of $115.7 million.

(8)	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	)	$	0.14	$	(0.13	)	$	2.05
Net income (loss) per share—diluted			2.15			1.60			(1.16	)		3.13			(1.25	)		(2.13	)		0.14		(0.13	)		1.98
Weighted average shares outstanding—basic (in millions) ⁽¹⁰⁾			80.0			80.0			80.0			80.0			79.4			80.0			64.8		156.5			168.6
Weighted average shares outstanding—diluted (in millions) ⁽¹⁰⁾			80.0			80.0			80.0			80.0			79.4			80.0			64.8		156.5			175.1
Other Financial Data:
Capital expenditures		$	252		$	409		$	258		$	157		$	73		$	46.0		$	9	$	6		$	74
Balance Sheet Data (at period end):
Property, plant and equipment, net⁽¹¹⁾		$	3,667		$	3,905		$	4,096		$	4,126		$	474		$	478		$	474	$	2,446		$	3,542
Total assets⁽¹²⁾			4,032			4,323			4,508			4,640			1,395			4,272			996		4,588			6,099
Total debt			—			—			—			—			—			—			75		2,280			2,743
Net capitalization			2,323			2,624			—			—			—			—			—		—
Shareholders’ equity			—			—			2,824			3,033			454			2,680			466		—			—
Members’ equity^(12)(13)			—			—			—			—			—			—			—		772			773


	(1)	Texas Genco LLC was formed on July 19, 2004 to facilitate the acquisition of Texas Genco Holdings, Inc. in a multi-step transaction from CenterPoint Energy, Inc. and other minority public stockholders. On December 13, 2004, Texas Genco Holdings, Inc. divided its nuclear and non-nuclear generating assets and liabilities between two of its wholly-owned subsidiaries. Its non-nuclear generating assets and liabilities were allocated to Texas Genco II, LP and its nuclear assets and liabilities and its cash were

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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)	Texas Genco Holdings, Inc.’s Board of Directors declared an 80,000-for-one stock split that was effected on December 18, 2002. On January 6, 2003, CenterPoint Energy distributed approximately 19% of the 80 million outstanding shares of Texas Genco’s common stock to CenterPoint Energy’s shareholders. Earnings per share has been presented as if the 80,000,000 shares were outstanding for all historical periods in accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share.”

(11)	In accordance with ERCOT rules, Texas Genco has placed four units into mothball status for more than 180 days, retired one unit, sold one unit and intends to sell eight units, together representing approximately 3,378 MW of available capacity. Texas Genco placed one additional unit representing approximately 461 MW of net capacity, which was operated pursuant to a “reliability must run” contract with the ERCOT, into mothball status for more than 180 days when the contract terminated on October 29, 2005. On November 14, 2005, Texas Genco completed the sale of its natural gas-fired generation plant at Deepwater, representing 174 MW of available capacity.

(12)	Total assets and members’ equity as of September 30, 2005 reflects distributions to members of an aggregate of $85.8 million from July 1, 2005 through September 30, 2005, representing preliminary distributions of net proceeds relating to certain asset sales.

(13)	Members’ equity includes capital contributions from Texas Genco’s existing equityholders of $899.5 million, of which $892.2 million was contributed by the investment funds affiliated with The Blackstone Group, Hellman & Friedman LLC, Kohlberg Kravis Roberts & Co. L.P. and Texas Pacific Group and $7.3 million was contributed by certain members of Texas Genco’s management team.

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LIQUIDITY AND CAPITAL RESOURCES DISCUSSION

Our unaudited pro forma combined financial information incorporated by reference into this prospectus supplement does not purport to represent what our financial condition would actually have been had the Acquisition and the Financing Transactions in fact occurred on the dates specified below or to project our results of operations for any future period. See “Risk Factors—Risks Related to the Acquisition—Because the historical and pro forma financial information incorporated by reference or included elsewhere in this prospectus supplement may not be representative of our 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 Form 8-K/ A as filed on January 5, 2006 and our current report on Form 8-K/A as filed on January 23, 2006, and incorporated by reference into this prospectus supplement.

This pro forma financial information may not reflect what our financial position would have been had we operated on a combined basis and may not be indicative of what our financial position will be in the future.

The discussion below contains certain statements of a forward-looking nature that involve risks and uncertainties. As a result of many factors, including those set forth under the sections entitled “Disclosure Regarding Forward-Looking Statements” and “Risk Factors” and those appearing elsewhere in this prospectus supplement, actual results may differ materially from those anticipated by such forward-looking statements.

Liquidity and Capital Resources

We plan to enter into a new senior secured credit facility for up to an aggregate amount of $5.575 billion to replace our existing senior credit facility. The senior secured credit facility is expected to consist of a $3.575 billion senior first priority secured term loan facility, a $1.0 billion senior first priority secured revolving credit facility and a $1.0 billion senior first priority secured synthetic letter of credit facility. 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. 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

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underwriter or an affiliate of one of the underwriters for this offering, will be lenders under the new senior secured credit facility.

We expect to draw down approximately $3.575 billion from the term loan facility to be used together with the net proceeds (after giving effect to underwriting discounts and commissions) of $ billion from this unsecured note offering, the offerings of common stock of $1.0 billion, $0.5 billion in mandatory convertible preferred stock and additional cash on hand, to finance the Acquisition, to repay $2 billion of our indebtedness and $2.7 billion of Texas Genco’s outstanding indebtedness and to pay related fees and expenses. Also see “Use of Proceeds—Sources and Uses of Funds.”

The new senior secured credit facility will be guaranteed by substantially all of our subsidiaries, with certain customary or agreed-upon exceptions for immaterial subsidiaries and subsidiaries defined as “unrestricted” foreign subsidiaries and certain project subsidiaries. In addition, it will be secured by liens on substantially all of our 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 seven 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 $3.575 billion would have been our secured indebtedness and the secured indebtedness of our subsidiaries. Interest payments on the notes and on borrowings under the new senior secured credit facility will significantly increase our liquidity requirements. See “Capitalization.”

Certain of our subsidiaries and affiliates are subject to project financing. Such entities will not guarantee our obligations on the notes. The debt agreements of these subsidiaries and project affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. On a pro forma basis, giving effect to (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 90% of our consolidated assets as of September 30, 2005, and our non-guarantor subsidiaries would have had approximately $781 million in aggregate principal amount of funded indebtedness as of September 30, 2005. Our outstanding consolidated trade payables would have been $339 million as of September 30, 2005, on a

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pro forma basis. On a pro forma basis, approximately 77% of these trade payables would have constituted obligations of NRG Energy, Inc. and our guarantor subsidiaries.

We expect that our 2006 total capital expenditures will be approximately $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 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

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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.

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:

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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.

Our Competitive Strengths

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


Approximate U.S. Portfolio Net	Approximate U.S. Portfolio Net	Approximate U.S. Portfolio Net
Capacity By Fuel Type⁽¹⁾	Capacity By Dispatch Level	Capacity By Region


(1)	Reflects only domestic generation capacity; 19 MW of wood-fired generation capacity not shown. Also includes 461 MW of generation capacity from facilities that were mothballed after September 30, 2005.

Reliability of future cash flows. We have sold forward a significant amount of our expected baseload generation capacity for 2006 and 2007. As of September 30, 2005 the combined company would have sold forward 68% of its baseload generation in the Texas (ERCOT) market for 2006 through 2009. As of the same date, the combined company would have sold approximately 83% of its expected annual baseload generation in the Southeastern Electric Reliability Council/ Entergy, or SERC— Entergy, market for 2006 through 2009, and approximately 70% of its expected annual baseload generation in the Northeast region for 2006. In addition, as of September 30, 2005, the combined company would have purchased forward under fixed price contracts (with contractually-specified price escalators) to provide fuel for approximately 81% of its expected baseload coal generation output from 2006 to 2009.

Favorable market dynamics for baseload power plants. As of September 30, 2005, approximately 38% of the combined company’s domestic generation capacity would have been fueled by coal or nuclear fuel. In many of the competitive markets where we operate, the price of power typically is set by the marginal costs of natural gas-fired and oil-fired power plants that currently have substantially higher variable costs than our solid fuel baseload power plants. For example, in the ERCOT market, a 2004 report by Henwood found that natural gas-fired power plants set the market price of power more than 90% of the time. As a result of our lower marginal cost for baseload coal and nuclear generation assets, we expect such assets to generate power nearly 100% of the time they are available.

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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:

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 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

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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 transportation alternatives. As of September 30, 2005, on a pro forma basis, the combined company would have had approximately 6,000 privately leased or owned rail cars in its transportation fleet. In addition, we intend to

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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 ₃O 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.

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,

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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 NO_x burners and over fired air, which have led to reductions in NO_x. A significant portion of this investment may be recovered from NRG’s cooperative customers. Texas Genco has spent over $700 million on NO_x reduction initiatives since 1999 to ensure both regulatory compliance and continued performance.

The following table summarizes the key existing and planned environmental controls on our coal-fired units:

SO₂

NO_x

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

SCR & LNB/OFA ⁽³⁾

2000-04

None

—

1988

WA Parish U 8

FGD

1982

SCR & LNB/OFA ⁽³⁾

2000-04

Co-Benefit of Scrubber

—

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 NO_x 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 suppliers with our combined volumes and to incorporate existing and future Texas Genco processes under the FORNRG program.

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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.

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,

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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, respectively. All four units are serviced by two competing railroads that diversify Texas Genco’s coal transportation options at competitive prices. Texas Genco has invested approximately $430.0 million in nitrogen oxide, or NO_x, control systems from 1999 to 2004. Each of the four coal-fired units has low-NO_x

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burners and selective catalytic reduction, or SCR, installed to reduce NO_x emissions. In addition, W. A. Parish Unit 8 has a scrubber installed to reduce sulfur dioxide, or SO₂, emissions. Plant 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-NO_x burners to reduce NO_x 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.


	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

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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.

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 implementa-

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tion 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.

In the event power prices decline in the future and J. Aron fails to perform under the J. Aron PPA, Texas Genco would have the right to terminate the J. Aron PPA and collect from J. Aron an amount equal to the difference between the contract price and the lower market price; however, Texas Genco’s ability to collect would be dependent on the amount of collateral then posted and the creditworthiness of J. Aron and Goldman at the time. Conversely, in the event power prices rise and Texas Genco fails to perform, J. Aron would have the right to terminate and collect an amount equal to the difference between the contract price and the higher market price. In the event J. Aron terminates, it would have the right to draw on certain letters of credit Texas Genco has posted as collateral. To the extent such letters of credit do not cover the amount of the termination payment, J. Aron retains a second lien on Texas Genco’s assets as collateral. J. Aron’s right to enforce its lien is limited to higher priority debt having taken such action.

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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.

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

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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 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%

Coal

Keystone

Shelocta, PA

3.7%

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

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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 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 NO_x and SO_x 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

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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.

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

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

Market Framework

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

As of September 30, 2005, NRG had long-term all-requirements contracts with 11 Louisiana distribution cooperatives. The agreements are standardized into three types, 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.

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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 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.

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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%

Natural Gas

Total WCP

904

Other Western Region Assets

Saguaro

Henderson, NV

50.0%

Natural Gas

Chowchilla

Northern CA

100.0%

Natural Gas

Red Bluff

Northern CA

100.0%

Natural Gas

140

Total Western Region

1,044


(1)	On December 27, 2005, NRG entered into a purchase and sale agreement to acquire Dynegy’s 50% ownership interest in WCP Holdings to become the sole owner of power plants totaling approximately 1,800 MW of generation capacity in the Western region. The transaction, which is subject to regulatory approval, is expected to close in the first quarter of 2006.

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

El Segundo. The El Segundo plant, of which NRG currently owns 50%, is located in El Segundo, California and produces aggregate generation capacity of 670 MW from two gas-fired intermediate load units (Units 3 and 4). These units, which have a generation capacity of 335 MW each, were installed in 1964 and 1965, respectively. The plant also contains two retired gas-fired intermediate load units that were installed in 1955 and 1956 (Units 1 and 2). These units, retired in 2002, were capable of producing 175 MW each. WCP is currently in the process of developing a 630 MW combined cycle plant on the property where the retired Units 1 and 2 reside. See “—Regulatory Developments—Regional Businesses—Market Developments—Western Region.”

Encina. The Encina Station, of which NRG currently owns 50%, is located in Carlsbad, California and has a combined generating capacity of 965 MW from five fossil-fuel steam-electric generating units and one combustion turbine. The five fossil-fuel steam-electric units, which all primarily use natural gas (and oil for emergency backup only under a gas supply force majeure condition), provide intermediate load services. The combustion turbine only provides peaking services of 14 MW. Units 1, 2 and 3 each have a generation capacity of approximately 107 MW and were installed in 1954, 1956 and 1958, respectively. Units 4 and 5 have a generation capacity of approximately 300 MW and 330 MW respectively, and were installed in 1973 and 1978.

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The combustion turbine was installed in 1966. Units 1, 2 and 3 are projected to be retired after 2010. Low NO_x burner modifications and selective catalytic reduction equipment has been installed on Units 1, 2, 3, 4 and 5.

NRG’s assets in the Western region consist primarily of older, higher heat rate, gas-fired plants in southern California. These plants, while older and less efficient than newer combined cycle plants, possess locational advantages during peak hours when the newer, remotely located plants are unable to get through transmission congestion in southern California. As a result, the Cal ISO designated NRG’s El Segundo, Encina and Cabrillo II plants as RMR qualifying units in 2005, and therefore those plants are entitled to certain fixed-cost payments from the Cal ISO for the right to dispatch those units during periods of locational constraints. Initially, transmission upgrades by Southern California Edison and San Diego Gas and Electric in 2005 caused the Cal ISO to drop the RMR designation for both El Segundo and the Encina Unit 4 for 2006. However, Cal ISO designated Encina Unit 4 as an RMR unit in a letter to Cabrillo Power I dated 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 encourage new investment and enable generators to earn acceptable returns on new and existing investments. See “Regulatory Developments—Regional Businesses—Market Developments—Western Region.”

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	*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

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%

Natural Gas

Ilion Cogeneration*

New York

100.0%

Natural Gas

James River

Virginia

50.0%

Coal

Cadillac*

Cadillac, MI

50.0%

Wood

Paxton Creek

Harrisburg, PA

100.0%

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

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%

Coal

Itiquira

Brazil

98.7%

156

Hydro

Total International Assets

1,916


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

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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 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.

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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.

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

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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 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.

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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 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.

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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 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

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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 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

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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 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.

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	*U.S. Federal Environmental Initiatives*


	*Air*

On May 18, 2005, the US Environmental Protection Authority, or USEPA, published the Clean Air Mercury Rule, or CAMR, to permanently cap and reduce mercury emissions from coal-fired power plants. CAMR imposes limits on mercury emissions from new and existing coal-fired plants and creates a market-based cap-and-trade program that will reduce nationwide utility emissions of mercury in two phases (2010 and 2018). Consistent with the significant debate on whether the USEPA has authority to regulate mercury emissions through a cap-and-trade mechanism (as opposed to a command-and-control requirement to install “maximum achievable control technology”, or MACT, on a unit basis), 14 states, together with five environmental organizations, have filed petitions for reconsideration of CAMR. The states (including California, Connecticut, Delaware, Illinois, Maine, Massachusetts, New Hampshire, New Jersey, New Mexico, New York, Pennsylvania, Rhode Island, Vermont and Wisconsin) allege that the rule violates the Clean Air Act, or CAA, because it fails to treat mercury as a hazardous air pollutant. On August 4, 2005, the U.S. Court of Appeals for the District of Columbia Circuit denied the environmental petitioners’ request for a stay of CAMR. On October 28, 2005, the USEPA published notices of reconsideration of seven specific aspects of CAMR (including state allocations). Each of our coal-fired electric power plants will be subject to mercury regulation. However, since the rule has yet to be implemented by individual states and given the USEPA’s pending reconsideration of the rule, it is difficult to assess with certainty how CAMR will affect our operations. Nevertheless, we continue to actively review emerging mercury monitoring and mitigation strategies and technologies to identify the most cost-effective options for NRG in implementing required mercury emission controls on the stipulated schedule.

On May 12, 2005, the USEPA published the Clean Air Interstate Rule, or CAIR. This rule applies to 28 Eastern States and the District of Columbia and caps SO₂ and NO_x emissions from power plants in two phases (2010 and 2015 for SO₂ and 2009 and 2015 for NO_x). CAIR will apply to certain of the combined company’s power plants in New York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois, Pennsylvania, Maryland and Texas. States must achieve the required emission reductions through: (a) requiring power plants to participate in a USEPA-administered interstate cap-and-trade system; or (b) measures to be selected by individual states. On August 24, 2005, the USEPA published a proposed Federal Implementation Plan, or FIP, to ensure that generators affected by CAIR reduce emissions on schedule. In addition, on December 20, 2005, the USEPA signed proposed revisions to the National Ambient Air Quality Standards (“NAAQS”) for fine particulates (PM2.5) and inhalable coarse particulates (PM10-PM2.5), that would require affected states to implement further rules to address SO₂ and NO_x emissions (as precursors of fine particulates in the atmosphere). Further, on November 22, 2005, the USEPA granted requests to reconsider four specific aspects of CAIR (including the inclusion of certain states) with final action 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 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 NO_x emissions controls at its plants. These emissions controls were installed to comply with regulations adopted by the Texas Commission

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on Environmental Quality to attain the one-hour national ambient air quality standard for ozone, as well as provisions of the Texas electric restructuring law. As a result, emissions from its plants in the Houston-Galveston area have been reduced by approximately 88% from 1998 levels and its fleet overall operates at one of the lowest NO_x emissions rates in the country. In aggregate, the Texas Genco plants are in compliance with current NO_x emission limits and are not expected to incur material environmental capital expenditures to ensure NO_x emissions compliance in the next several years. The Texas Commission on Environmental Quality has, however, initiated a rulemaking process for establishing lower NO_x emissions limits to assure compliance with the USEPA 8-hour ozone standard in the Houston-Galveston and Dallas-Fort Worth areas. It is possible that any new regulations implemented may require additional NO_x emission controls on Texas Genco plants in 2009 or beyond. We have currently estimated approximately $70 million in additional capital expenditures with respect to compliance with air pollution control requirements (primarily replacement of catalyst for NO_x emission controls) between 2006 and 2014.

The USEPA had also proposed MACT standards for nickel from oil-fired units that would essentially require the installation of electrostatic precipitators on certain oil-fired units. These proposed requirements were originally included in drafts of CAMR. However, reflecting further dialogue with generation industry participants and additional scientific review, the nickel MACT provisions were omitted from CAMR. In fact, the USEPA issued a delisting rule on March 29, 2005 effectively removing the MACT standards for nickel (i.e., specific control technologies to be installed at each affected plant) at oil-fired power plants. A number of environmental groups lodged legal challenges to the USEPA’s delisting rule and the agency has agreed to reconsider this delisting, although it has not specified which issues will be reconsidered. As the delisting challenge relates to both nickel from oil-fired power plants and mercury from coal-fired plants, it is not possible to predict the outcome of the pending legal action.

NRG’s facilities in the eastern United States are subject to a cap-and-trade program governing NO_x emissions during the “ozone season” (May 1 through September 30). These rules essentially require that one NO_x allowance be held for each ton of NO_x emitted from fossil fuel-fired stationary boilers, combustion turbines, or combined cycle systems. Each of NRG’s facilities that is subject to these rules has been allocated NO_x emissions allowances. NRG currently estimates that the portfolio total is currently sufficient to generally cover operations at these facilities through 2009. However, if at any point allowances are insufficient for the anticipated operation of each of these facilities, NRG must purchase NO_x allowances. Any obligation to purchase a substantial number of additional NO_x allowances could have a material adverse effect on NRG’s operations.

The Clean Air Visibility Rule (or so-called BART rule) was published by the USEPA on July 6, 2005. This rule is designed to improve air quality in national parks and wilderness areas. The rule requires regional haze controls (by targeting SO₂ and NO_x emissions from sources including power plants of a certain vintage) through the installation of Best Available Retrofit Technology, or BART, in certain cases. States must develop implementation plans by December 2007 which may be satisfied through an emissions trading program for BART sources. Although the BART rule will apply to many of the Company’s facilities, sources that are also subject to CAIR (which include most of our facilities) will likely be able to satisfy their obligations under the BART rule through compliance with the more stringent CAIR. Accordingly, no material additional expenditures are anticipated for compliance with the Clean Air Visibility Rule, beyond those required by CAIR.

In addition to federal regulation, national legislation has been proposed that would impose annual caps on U.S. power plant emissions of NO_x, 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 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.

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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.

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.

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	*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.


	*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,

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2006, Texas Genco has not received this letter and has not had any further communications on this issue with the USEPA.

Northeast Region. Massachusetts air regulations prescribe schedules under which six existing coal-fired power plants in-state are required to meet stringent emission limits for NO_x, 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 NO_x 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 NO_x emissions associated with fuel switching and use such reductions to extend the timeframe for implementing technological controls, which could ultimately include the addition of flue gas desulfurization, or FGD, and selective catalytic reduction, or SCR, equipment. On January 11, 2005, NRG reached an agreement with the State of New York and the NYSDEC in connection with voluntary emissions reductions at the Huntley and Dunkirk facilities, as discussed below in Legal Proceedings. The Consent Decree was entered by the U.S. District Court for the Western District of New York on June 3, 2005. NRG does not anticipate that any additional material capital expenditures, beyond those already spent, will be required for our Huntley and Dunkirk plants to meet the current compliance standards under the Consent Decree through 2010, although, this does not reflect any additional capital expenditures that may be required to satisfy other federal and state laws.

Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC entered into a Consent Order with NYSDEC, effective March 31, 2004, regarding certain alleged opacity exceedances. The Consent Order required the respondents to pay a civil penalty of $1.0 million which was paid in April 2004. The Order also stipulates penalties (payable quarterly) for future violations of opacity requirements and a compliance schedule. NRG recently resolved a dispute with NYSDEC over the method of calculation for stipulated penalties. NRG paid NYSDEC $1.3 million at the end of 2005 to cover the stipulated penalty payments that had been withheld pending resolution of the dispute.

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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, NO_x and mercury. Delaware is pursuing such rule-making based on recent determinations that portions of the state are in non-attainment for NAAQS for fine particulates, and all of the state is in non-attainment for the NAAQS for 8-Hour Ozone. We are evaluating emissions reduction opportunities which may include blending low sulfur western coals. NRG will actively participate in the Delaware rule-making as a stakeholder and will continue to be involved in environmental policy-making efforts in Delaware through the Governor’s Energy Task Force and interactions with legislators, the PSC and the Delaware Department of Natural Resources and Environmental Control, or DNREC.

The Ozone Transport Commission, or OTC, was established by Congress and governs ozone and the NOx budget program in certain eastern states, including Massachusetts, Connecticut, New York and Delaware. In January 2005, the OTC redoubled its efforts to develop a multi-pollutant regime (SO₂, NO_x, 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 NO_x (to 1.87 million tons) and SO₂ (to 3.0 million tons) apply; (d) 2012 Phase II reductions of NO_x (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 NO_x 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 compliance with applicable NAAQS. NRG participated in development of the revisions, which require the reduction of NO_x emissions at the gas-fired Big Cajun I Power Station and coal-fired Big Cajun II Power Station to 0.1 lbs/ MMBtu and 0.21 lbs/ MMBtu NO_x, respectively (both based on heat input). This revision of the Louisiana air rules would constitute a change-in-law covered by agreement between Louisiana Generating, LLC and the electric cooperatives (power offtakers), allowing the costs of added combustion controls to be passed through to the cooperatives. The combustion controls required at the Big Cajun II Generating Station to meet the state’s NO_x regulations have been installed.

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On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the CAA from USEPA seeking information primarily related to physical changes made at Big Cajun II and subsequently received a notice of violation, or NOV, based on alleged NSR violations. See “—Legal Proceedings” for a discussion of this matter. NRG is up-to-date with all USEPA information requests it has received in connection with this matter and has not been contacted by USEPA pursuant to the NOV since May 2005.

Western Region. The El Segundo Generating Station is regulated by the South Coast Air Quality Management District, or SCAQMD. Before its retirement as of January 1, 2005, the Long Beach Generating Station was also regulated by SCAQMD. SCAQMD approved amendments to its Regional Clean Air Incentives Market, or RECLAIM, NO_x regulations on January 7, 2005. RECLAIM is a regional emission-trading program targeting NO_x reductions to achieve state and federal ambient air quality standards for ozone. Among other changes, the amendments reduce the NO_x RECLAIM Trading Credit, or RTC, holdings of El Segundo Power, LLC and Long Beach Generation LLC facilities by certain amounts. Notwithstanding these amendments, retained RTCs are expected to be sufficient to operate El Segundo Units 3 and 4 as high as 100% capacity factor for the life of those units.

On October 6, 2005, the California Public Utilities Commission, or CPUC, adopted a policy statement on GHG Performance Standards as part of a focus on emissions from conventional fossil-fuel resources. The adopted policy statement directs the CPUC to investigate a GHG emissions performance standard for energy procurement by the state’s Investor-Owned Utilities, or IOUs, that is no higher than the GHG emissions levels of a combined-cycle natural gas turbine for all energy procurement contracts longer than three years in length and for all new IOU owned generation. While this policy statement does not impose new requirements at this time, instead requiring CPUC staff to investigate possible new requirements that would apply to all IOU procured energy and capacity, including in and out-of-state generation, it gives some basis for expecting the development of carbon constrained standards within the California wholesale power market.


	*Domestic Site Remediation Matters*

Under certain federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products at the facility. We may also be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, or SARA, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault) and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills or other occurrences during our operations. Although both NRG and Texas Genco have been involved in on-site contamination matters, to date, neither has been named as a potentially responsible party with respect to any off-site waste disposal matter.

Texas (ERCOT) Region. The lignite used to fuel the Limestone facility is obtained from a surface mine adjacent to the facility under an amended long-term contract with Texas Westmoreland Coal Co., or TWCC, entered into in August 1999. TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, Texas Genco is responsible for final mine reclamation obligations. The Railroad Commission of Texas has imposed a bond obligation of approximately $70 million on TWCC for the reclamation of this lignite mine. Final reclamation activity is expected to commence in 2015. Pursuant to the contract with TWCC, an affiliate of CenterPoint Energy, Inc. has guaranteed $50 million of this obligation until 2010. The remaining sum of approximately $20 million has been bonded by the mine operator, TWCC. Under the terms of Texas Genco’s agreement, Texas Genco is required to post a corporate guarantee in the amount of $50 million of TWCC’s

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reclamation bond when CenterPoint’s obligation lapses. As of December 31, 2005, Texas Genco had accrued $10 million related to the mine reclamation obligation.

Northeast Region. Significant amounts of ash are contained in landfills at on and off-site locations. At Dunkirk, Huntley, Somerset and Indian River, ash is disposed of at landfills owned and operated by NRG. NRG maintains financial assurance to cover costs associated with landfill closure, post-closure care and monitoring activities. NRG has funded a trust in the amount of approximately $6.0 million to provide such financial assurance in New York and $6.9 million in Delaware. NRG must also maintain financial assurance for closing interim status “RCRA (Resource Conservation and Recovery Act) facilities” at the Devon, Middletown, Montville and Norwalk Harbor Generating Stations and has funded a trust in the amount of $1.5 million accordingly.

NRG inherited historical clean-up liabilities when it acquired the Somerset, Devon, Middletown, Montville, Norwalk Harbor, Arthur Kill and Astoria Generating Stations. During installation of a sound wall at Somerset Station in 2003, oil contaminated soil was encountered. NRG has delineated the general extent of contamination, determined it to be minimal, and has placed an activity use limitation on that section of the property. Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Harbor Stations have been identified. NRG has proposed a remedial action plan to be implemented over the next two to eight years (depending on the station) to address historical ash contamination at the facilities. The total estimated cost is not expected to exceed $1.5 million. Remedial obligations at the Arthur Kill generating station have been established in discussions between NRG and the NYSDEC and are estimated to be approximately $1.1 million. Remedial investigations continue at the Astoria generating station with long-term clean-up liability expected to be approximately $2.9 million. While installing groundwater-monitoring wells at Astoria to track our remediation of an historical fuel oil spill, the drilling contractor encountered deposits of coal tar in two borings. NRG reported the coal tar discovery to the NYSDEC in 2003 and delineated the extent of this contamination. NRG may also be required to remediate the coal tar contamination and/or record a deed restriction on the property if significant contamination is to remain in place.

In September 2001, we experienced an underground fuel line leak at our Vienna Generating Station, resulting in a small release of oil free product, which was contained. NRG promptly reported the event to the relevant state agencies and continues to work with the Maryland Department of the Environment, or DEP, to develop any remediation requirements. Ongoing monitoring has indicated that the product is stable. NRG submitted a site assessment report and proposed remediation plan to Maryland DEP but the agency has not formally responded to those documents. Based upon work completed by a remediation contractor retained by NRG, long-term clean up liability in connection with this matter is not expected to exceed $0.5 million.

South Central Region. Liabilities associated with closure, post-closure care and monitoring of the ash ponds owned and operated on site at the Big Cajun II Generating Station are addressed through the use of a trust fund maintained by NRG in the amount of approximately $5.0 million. Annual payments are made to the fund in the amount of $0.12 million.

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

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allow the remaining contaminated soils to stay underneath the building foundation until the building is demolished.

A diesel fuel spill to on-site surface containment occurred at the Cabrillo Power II LLC Kearny Combustion Turbine facility (San Diego) in February 2003. Emergency response and subsequent remediation activities were completed. Confirmation sampling for the site was completed in 2004 and submitted to the San Diego County Department of Environmental Health. Three San Diego Combustion Turbine facilities, formerly operating pursuant to land leases with the U.S. Navy, are currently being decommissioned with equipment being removed from the sites and remediation activities occurring where necessary. All remedial activities are being completed pursuant to the requirements of the U.S. Navy and the San Diego County Department of Environmental Health. Remediation activities were completed in 2004 at the Naval Training Center and North Island facilities. At the 32nd Street Naval Station facility, additional contamination delineation is necessary and additional unquantified remediation in inaccessible areas may be required in the future. Given the current uncertainties at this facility, it is difficult to accurately estimate the resultant clean up liability.


	*International Environmental Matters*

Most of the foreign countries in which NRG owns or may acquire or develop independent power projects have environmental and safety laws or regulations relating to the ownership or operation of electric power generation facilities. These laws and regulations, like those in the U.S., are constantly evolving and have a significant impact on international wholesale power producers. In particular, NRG’s international power generation facilities will likely be affected by emissions limitations and operational requirements imposed by the Kyoto Protocol, which is an international treaty related to greenhouse gas emissions which entered into force on February 16, 2005, and country-based restrictions pertaining to global climate change concerns.

We retain appropriate advisors in foreign countries and seek to design our international asset management strategy to comply with each country’s environmental and safety laws and regulations. There can be no assurance that changes in such laws or regulations will not adversely effect our international operations.

Australia. With respect to Australia, climate change is considered a long-term issue (e.g. 2010 and beyond) and the Australian government’s response to date has included a number of initiatives, all of which have had no or minimal impact on our operations. The Australian government has stated that Australia will achieve its Kyoto Protocol target of 8% below 1990 greenhouse gas emission levels for the 2008 to 2012 reporting period, but that Australia will not ratify the Kyoto Protocol. Each Australian state government is considering implementing a number of climate change initiatives that will vary considerably state to state, with the possible exception of an interjurisdictional state-led carbon trading proposal (which is not supported by the federal government).

NRG Flinders disposes of ash to slurry ponds at Port Augusta in South Australia. At the end of life of the power station, NRG Flinders will have an obligation to remediate these ponds in accordance with a plan accepted by the South Australian Environment Protection Agency and confirmed in the Environment Compliance Agreement between the South Australian Minister for Environment and Heritage and NRG Flinders dated September 20, 2000, or the EC Agreement. The estimated cost of remediation including 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 NO_x emission limits for plants firing conventional fuels (Section 13 of the Directive) and co-firing waste products (Section 17 of the Directive). The new regulations will require the Mumsdorf and Deuben Power stations to install additional controls to reduce NO_x emissions in 2006. These plant modifications are proceeding on schedule.

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The European Union’s Groundwater Directive and Mine Wastewater Management Directive are in the rule-making stage with the final outcome still under debate. Given the uncertainty regarding the possible outcome of the debate on these directives, we cannot quantify at this time the effect such requirements would have on our future coal mining operations in Germany.

A new law specifically dealing with the relocation of the residents of Heuersdorf from the path of the mining plan was enacted by the legislature of Saxony in 2004. On November 25, 2005, the Saxony Constitutional Court upheld the constitutionality of the Heuersdorf act. This ruling cannot be appealed. Nuisance suits remain a possibility, but the court’s ruling brings the matter closer to final resolution.

The supply contracts under which MIBRAG mines lignite from the Profen mine expire on December 31, 2021. The contracts under which MIBRAG mines lignite from the Schleenhain mine expire in 2041. At the end of each mine’s productive lifetime, MIBRAG will be required to reclaim certain areas. MIBRAG accrues for these eventual expenses and estimates the cost of the final reclamation to approach approximately €176 million in the instance of the Schleenhain mine and €132 million for Profen.

Insurance


	*General*

Both NRG and Texas Genco carry insurance coverage consistent with companies engaged in similar commercial operations with similar properties, including business interruption insurance for the coal and lignite plants. However, both NRG’s and Texas Genco’s insurance policies are subject to certain limits and deductibles as well as policy exclusions. Adequate insurance coverage in the future may be more expensive or may not be available on commercially reasonable terms. Also, the insurance proceeds received for any loss of or any damage to any of our generation plants may not be sufficient to restore the loss or damage without negative impact on our financial condition, results of operations or cash flows.

We expect to receive a report from Moore-McNeil LLC, an internationally recognized independent insurance consulting firm, which concludes that the insurance program that is presently in effect for NRG and Texas Genco is consistent with prudent industry practice.


	*Nuclear*

Texas Genco and the other owners of STP maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of STP currently maintain $2.75 billion in property damage insurance coverage, which is above the legally required minimum. STPNOC currently carries accidental outage coverage with a 17 week deductible and a six week indemnity at a rate of $3,500,000 per week. This coverage may not be available on commercially renewable terms or may be more expensive in the future and any proceeds from such insurance may not be sufficient to indemnify the owners of STP for their losses. By the date of closing of the Acquisition, Texas Genco would have also purchased additional accidental outage coverage for its ownership percentage in STP. This coverage will provide maximum weekly indemnity of $1,980,000 for 52 weeks and $1,584,000 per week for the next 104 weeks after the 17-week waiting period and six-week indemnity period have been met. 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

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liability associated with any accident in the course of operation of the nuclear reactor, transportation of nuclear fuel to the reactor site, in the storage of nuclear fuel and waste at the reactor site and the transportation of the spent nuclear fuel and nuclear waste from the nuclear reactor. All other non-nuclear liabilities are not covered. Any substantial retrospective premiums imposed under the Price-Anderson Act or losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.

Legal Proceedings

We are, from time to time, a party to litigation or legal proceedings arising in the ordinary course of our business, most of which involves contract disputes or claims for personal injury, including exposure to asbestos and property damage incurred in connection with our operations. We believe that we have valid defenses to the legal proceedings and investigations described below and we intend to defend them vigorously. However, litigation is inherently subject to many uncertainties. There can be no assurance that additional litigation will not be filed against us or our subsidiaries in the future, asserting similar or different legal theories and seeking similar or different types of damages and relief. Unless specified below, we are unable to predict the outcome of these legal proceedings. An unfavorable outcome in one or more of these proceedings could have a material impact on our consolidated financial position, results of operations or cash flows. We also have indemnity rights for some of these proceedings to reimburse us for certain legal expenses and to offset certain amounts deemed to be owed in the event of an unfavorable litigation outcome.


	*Texas Commercial Energy Litigation*

In July 2003, Texas Commercial Energy filed in federal court in Corpus Christi, Texas a lawsuit against, as the lawsuit was subsequently amended, Texas Genco, LP, CenterPoint Energy, Inc., Reliant Energy, Inc., Reliant Electric Solutions, LLC, several other CenterPoint Energy, Inc. and Reliant Energy, Inc. subsidiaries and a number of other participants in the ERCOT market. The plaintiff, a retail electricity provider in the Texas market served by ERCOT, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws and committed fraud and negligent misrepresentation. The lawsuit sought damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys’ fees. In June 2004, the federal court dismissed plaintiff’s claims on jurisdictional grounds and, in July 2004, the plaintiff filed an appeal that Texas Genco, LP contested. The court of appeals affirmed the lower court’s decision in June 2005. The plaintiff moved for a rehearing en banc which was subsequently denied. 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

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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 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

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to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from Texas Genco LLC.

In addition, Congress is currently considering the proposed Fairness in Asbestos Injury Resolution Act of 2005, which, if it becomes law, would require asbestos defendants and insurers to make payments into a privately-funded national asbestos compensation fund. Under the bill as currently drafted, payments made by us would not be offset by any insurance recoveries. The proposed legislation remains subject to negotiation and modification.


	*California Wholesale Electricity Litigation and Related Investigations*

NRG, WCP, WCP’s four operating subsidiaries, Dynegy, Inc. and numerous other unrelated parties are the subject of numerous lawsuits arising based on events occurring in the California power market. The complaints primarily allege that the defendants engaged in unfair business practices, price fixing, antitrust violations, and other market “gaming” activities. Certain of these lawsuits originally commenced in 2000 and 2001, which seek unspecified treble damages and injunctive relief, were consolidated and made a part of a Multi-District Litigation proceeding before the U.S. District Court for the Southern District of California. In December 2002, the district court found that federal jurisdiction was absent and remanded the cases back to state court. On December 8, 2004, the U.S. Court of Appeals for the Ninth Circuit affirmed the district court in most respects. On March 3, 2005, the Ninth Circuit denied a motion for rehearing. On May 5, 2005, the case was remanded to California state court and, under a scheduling order, defendants filed their objections to the pleadings. On July 22, 2005, based upon the filed rate doctrine and federal preemption, the court dismissed NRG Energy, Inc. without prejudice, leaving only subsidiaries of WCP remaining in the case. On October 3, 2005, the court sustained defendants’ demurrer dismissing the case against all remaining defendants. On December 2, 2005, the plaintiffs filed their notice of appeal from the dismissal.

In 2002, a number of cases similar to those described above were filed against defendants, including WCP or one or more of its operating subsidiaries and/or Dynegy, Inc., which we refer to as the Northern California cases. On February 25, 2005, the Ninth Circuit affirmed the district court’s decision to dismiss all of the defendants’ Northern California cases. No appeal was taken from this decision.

In addition to the cases discussed above, other cases, including putative class actions, have been filed in state and federal court on behalf of business and residential electricity consumers that name NRG and/or WCP and/or certain subsidiaries of WCP, in addition to numerous other defendants. The complaints allege the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades, and violated California’s antitrust law and unfair business practices law. The complaints seek restitution and disgorgement, civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. Motion practice is proceeding in these cases and dispositive motions have been filed in several of these proceedings. In the above referenced cases relating to natural gas, Dynegy is defending WCP and/or its subsidiaries pursuant to an indemnification agreement and will be the responsible party for any loss. In cases relating to electricity, Dynegy’s counsel is representing it and WCP and/or its subsidiaries with each party responsible for half of the costs and each party shall be responsible for half of any loss. Where NRG is named as a party in an electricity case, it is defending the case and bears its own costs of defense.


	*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

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rehearing. The case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held December 8, 2004.


	*California Attorney General*

The California Attorney General has undertaken an investigation entitled “In the Matter of the Investigation of Possibly Unlawful, Unfair, or Anti-Competitive Behavior Affecting Electricity Prices in California.” Dynegy, NRG and subsidiaries of WCP have responded to interrogatories, document requests and to requests for interviews.


	*Canadian Claim*

On June 30, 2005, three individuals filed a lawsuit with the Ontario Superior Court of Justice against more than 20 power generating entities in the U.S. and Canada, including the Keystone and Conemaugh facility ownership groups. Two of NRG’s subsidiaries own less than four percent of each of these Pennsylvania coal-fired plants. The plaintiffs, on behalf of a purported class of Ontario residents, have alleged air pollution and associated health effects and asserted damages in excess of CA$50 billion (US $43.1 billion, based on conversion rates as of September 30, 2005). The claim was not served on any defendant by December 30, 2005. Accordingly, the claim is inactive and may be revived only if plaintiffs file a motion to extend the time for service and the court grants the motion. Alternatively, plaintiffs could seek to file a new claim.


	*New York Operating Reserve Markets*

Consolidated Edison and others petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of FERC’s refusal to order a re-determination of prices in the New York Independent System Operator, or NYISO, operating reserve markets for a two month period in 2000. On November 7, 2003, the court found that NYISO’s method of pricing spinning reserves violated the NYISO tariff. On March 4, 2005, FERC issued an order favorable to NRG stating that no refunds would be required for the tariff violation associated with the pricing of spinning reserves. In the order, FERC also stated that the exclusion of the Blenheim-Gilboa facility and western reserves from the non-spinning market was not a market flaw and NYISO was correct not to use its authority to revise the prices in this market. A motion for rehearing of the order was filed before the April 3, 2005 deadline and on November 17, 2005 FERC denied rehearing.


	*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

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supporting motion. On June 3, 2005, the U.S. District Court for the Western District of New York entered the Consent Decree permitting the settlement and ending the case.

On October 24, 2005, the U.S. Court of Appeals for the Second Circuit issued its opinion in New York Public Interest Research Group (NYPIRG) v. Stephen L. Johnson, Administrator, U.S. Environmental Protection Agency. In 2000, the NYSDEC issued a NOV to the prior owner of the Huntley and Dunkirk stations. After an unsuccessful challenge to the stations’ Title V air quality permits by NYPIRG, it appealed. The Second Circuit held that, during the Title V permitting process for the two stations, the 2000 NOV should have been sufficient for the NYSDEC to have made a finding that the stations were out of compliance. Accordingly, the court stated that the EPA should have objected to the Title V permits on that basis and the permits should have included compliance schedules. As discussed above, on June 3, 2005, the consent decree among NYSDEC, NiMo, and NRG was entered, settling the substantive issues discussed by the Second Circuit in its decision. NYSDEC is in the process of incorporating the consent decree obligations into the Huntley and Dunkirk Title V permits so as to make them permit conditions, an action we believe is supported by the decision. 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.

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	*Itiquira Energetica, S.A.*

NRG’s Brazilian project company, Itiquira Energetica S.A., or Itiquira, the owner of a 156 MW hydro project in Brazil, is in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes, or Inepar. The dispute was commenced in arbitration by Itiquira in September of 2002 and pertains to certain matters arising under the engineering procurement and construction contract between the parties. Itiquira sought Real 140 million and asserted that Inepar breached the contract. Inepar sought Real 39 million and alleged that Itiquira breached the contract. On September 2, 2005, the arbitration panel ruled in favor of Itiquira, awarding it Real 139 million (US $62.3 million, based on conversion rates as of September 30, 2005) and Inepar Real 4.7 million (US $2.1 million, based on conversion rates as of September 30, 2005). Due to interest accrued from the commencement of the arbitration to the award date, Itiquira’s award is increased to approximately Real 227 million (U.S. $100 million, based on conversion rates as of September 30, 2005). Itiquira has commenced the lengthy process in Brazil to execute on the arbitral award. We are unable to predict the outcome of this execution process. On October 14, 2005, Inepar filed with the arbitration panel a request for clarifications of the ruling. 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*

On July 1, 2004, the Commodities Futures Trading Commission, or CFTC, filed a civil complaint against NRG in Minnesota federal district court, alleging false reporting of natural gas trades from August 2001 to May 2002, and seeking an injunction against future violations of the Commodity Exchange Act. On November 17, 2004, a bankruptcy court hearing was held on the CFTC’s motion to reinstate its expunged bankruptcy claim, and on NRG’s motion to enforce the provisions of the NRG plan of reorganization, thereby precluding the CFTC from continuing its federal court action. The bankruptcy court has yet to schedule a hearing or rule on the CFTC’s pending motion to reinstate its expunged claim. On December 6, 2004, a federal magistrate judge issued a report and recommendation that NRG’s motion to dismiss be granted. That motion to dismiss was granted by the federal district court in Minnesota on March 16, 2005. On May 13, 2005 the CFTC filed a notice of appeal with the U.S. Court of Appeals for the Eighth Circuit. The CFTC filed its brief on August 9, 2005, and on September 29, 2005, NRG filed its brief.


	*Disputed Claims Reserve*

As part of the NRG plan of reorganization confirmed on November 24, 2003, NRG has funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, to the extent such claims are resolved now that NRG has emerged from bankruptcy, the claimants will be paid from the reserve on the same basis as if they had been paid out in the bankruptcy. That means that their allowed claims will be reduced to the same recovery percentage as other creditors would have received and will be paid in pro rata distributions of cash and common stock. We believe we have funded the disputed claims reserve at a sufficient level to settle the remaining unresolved proofs of claim we received during the bankruptcy proceedings. However, to the extent the aggregate amount of these payouts of disputed claims ultimately exceeds the amount of the funded claims reserve, we are obligated to provide additional cash, notes and common stock to the claimants. We will continue to monitor our obligation as the disputed claims are settled. If excess funds remain in the disputed claims reserve after payment of all obligations, such amounts will be reallocated to the creditor pool. NRG has contributed common stock and cash to an escrow agent to complete the distribution and settlement process. Since NRG has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from its balance sheet. Similarly, NRG removed the obligations relevant to the claims from its balance sheet when the common stock was issued and cash contributed.

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Properties

For a description of our interests in independent power production and cogeneration facilities, see “—Regional Business Descriptions—Texas (ERCOT)—Facilities,” “—Regional Business Descriptions—Northeast Region—Facilities,” “—Regional Business Descriptions—South Central Region—Facilities,” “—Regional Business Descriptions—Western Region—Facilities,” “—Regional Business Descriptions—Other—Other North American Assets” and “—Regional Business Descriptions—Other—Australia and All Other Generation and Non-Generation Assets.”

Listed below are descriptions of our interests in thermal and chilled water facilities as of September 30, 2005:

Thermal Energy

Name and Location of

Date of

Ownership

Purchaser/MSW

Facility

Acquisition

Generating Capacity⁽¹⁾

Interest

Supplier

NRG Energy Center Minneapolis, MN

1993

Steam: 1,203 mmBtu/hr. (353 MWt) Chilled Water: 41,630 tons (146 MWt)

100%

Approx. 100 steam customers and 47 chilled water customers

NRG Energy Center San Francisco, CA

1999

Steam: 482 mmBtu/Hr. (141 MWt)

100%

Approx. 165 steam customers

NRG Energy Center Harrisburg, PA

2000

Steam: 440 mmBtu/hr. (129 MWt) Chilled water: 2,400 tons (8 MWt)

100%

Approx. 265 steam customers and 3 chilled water customers

NRG Energy Center Pittsburgh, PA

1999

Steam: 266 mmBtu/hr. (78 MWt) Chilled water: 12,580 tons (44 MWt)

100%

Approx. 25 steam and 25 chilled water customers

NRG Energy Center San Diego, CA

1997

Chilled water: 7,425 tons (26 MWt)

100%

Approx. 20 chilled water customers

NRG Energy Center St. Paul, MN

1992

Steam: 430 mmBtu/hr. (126 MWt)

100%

Rock-Tenn Company

Camas Power Boiler, Washington

1997

Steam: 200 mm Btu/hr. (59 MWt)

100%

Georgia-Pacific Corp.

NRG Energy Center Dover, DE

2000

Steam: 190 mmBtu/hr. (56 MWt)

100%

Kraft Foods Inc.

NRG Energy Center Oak Park Heights, MN

1992

Steam: 200 mmBtu/Hr. (59 MWt)

100%

Andersen Corp., MN
Correctional Facility


(1)	Thermal production and transmission capacity is based on 1,000 Btus per pound of steam production or transmission capacity. The unit mmBtu is equal to one million Btus.

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Listed below are descriptions of our significant resource recovery assets as of September 30, 2005:

Name and Location

Date of

Ownership

of Facility

Acquisition

Processing Capacity⁽¹⁾

Interest

MSW Supplier

Newport, MN⁽¹⁾

1993

MSW: 1,500 tons/day

100%

Ramsey and Washington Counties

Elk River, MN⁽²⁾

2001

MSW: 1,500 tons/day

85%

Anoka, Hennepin and Sherburne Counties; Tri-County Solid Waste Management Commissioner


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

(2)	For the Elk River facility, NRG’s 85% interest is related strictly to garbage-sorting facilities.

In addition, we own various real property and facilities relating to our generation assets, other vacant real property unrelated to our generation assets, interests in other construction projects in various states of completion and properties not used for operational purposes. We believe we have satisfactory title to our plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in our opinion, would not have a material adverse effect on the use or value of our portfolio.

We lease our corporate offices at 211 Carnegie Center, Princeton, New Jersey 08540 and various other office spaces, including a 66 month lease of approximately 50,000 square feet in Houston, Texas, which serves as our regional headquarters for the ERCOT market.

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MANAGEMENT

Directors and Certain Officers of NRG

The following table sets out the names and ages of each of our directors and certain of our officers, after giving effect to the Acquisition, followed by a description of their business experience:


Name	Age		Position

Directors
Howard E. Cosgrove		62	Director, Chairman of the Board
John F. Chlebowski		60	Director and Chair, Audit Committee
Lawrence S. Coben		47	Director and Chair, Compensation Committee
David Crane		46	President, Chief Executive Officer and Director
Stephen L. Cropper		55	Director and Chair, Commercial Operations Oversight Committee
Maureen Miskovic		47	Director
Anne C. Schaumburg		56	Director
Herbert H. Tate		52	Director
Thomas H. Weidemeyer		58	Director
Walter R. Young		61	Director and Chair, Governance and Nominating Committee
Officers
David Crane		46	President, Chief Executive Officer and Director
Robert C. Flexon		47	Executive Vice President and Chief Financial Officer
Caroline Angoorly		41	Vice President, Environmental and New Business
John P. Brewster		52	Executive Vice President, International Operations and President, South Central Region
Scott J. Davido		44	Executive Vice President and President, Northeast Region
Kevin T. Howell		48	Executive Vice President, Commercial Operations
James J. Ingoldsby		48	Vice President and Controller
Christine A. Jacobs		53	Vice President, Plant Operations
Timothy W.J. O’Brien		46	Vice President and General Counsel
George P. Schaefer		55	Vice President and Treasurer
Steve Winn		40	Executive Vice President and President, Texas Region

Board of Directors

The Board is divided into three classes serving staggered three-year terms. Directors for each class are elected at our annual meeting of stockholders held in the year in which the term for their class expires. There are no family relationships among our officers and directors.

Class I Directors (Terms expire in 2007)

David Crane

Member of Commercial Operations Oversight Committee

Mr. Crane has served as the President, Chief Executive Officer and a director of NRG since December 2003. Prior to joining NRG, Mr. Crane served as Chief Executive Officer of International Power PLC, a UK-domiciled wholesale power generation company, from January 2003 to November 2003, and as Chief Operating Officer from March 2000 to December 2002. Mr. Crane was Senior Vice President—Global Power New York at Lehman Brothers Inc., an investment banking firm, from January 1999 to February 2000, and was Senior Vice President—Global Power Group, Asia (Hong Kong) at Lehman Brothers from June 1996 to January 1999.

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Stephen L. Cropper

Chair of Commercial Operations Oversight Committee

Mr. Cropper has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Mr. Cropper spent 25 years with The Williams Companies, an energy company, before retiring in 1998 as President and Chief Executive Officer of Williams Energy Services. Mr. Cropper is a director of Berry Petroleum Company, Sunoco Logistics Partners L.P. and Rental Car Finance Corporation, a subsidiary of Dollar Thrifty Automotive Group.

Maureen Miskovic

Member of Commercial Operations Oversight Committee

Ms. Miskovic has been a Director of NRG since September 2005. She currently serves as Chief Operating Officer of the Eurasia Group, a research and consulting firm focusing on political-risk analysis and industry research for global markets, where she oversees the firm’s continued expansion and serves as chief advisor for the company’s political risk services. She also acts as the principal liaison for Eurasia Group’s joint venture with Deutsche Bank, which includes the DESIX, the first global political risk index on Wall Street. Miskovic joined Eurasia Group in September 2002 after six years with Lehman Brothers, where she was Managing Director and Chief Global Risk Officer. Prior to joining Lehman Brothers, Miskovic was Treasurer at Morgan Stanley in London and before that she held various positions with SG Warburg, also in London.

Thomas H. Weidemeyer

Member of Compensation Committee

Mr. Weidemeyer has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Until his retirement in December 2003, Mr. Weidemeyer served as Director, Senior Vice President and Chief Operating Officer of United Parcel Service, Inc., the world’s largest transportation company and President of UPS Airlines. Mr. Weidemeyer became Manager of the Americas International Operation in 1989, and in that capacity directed the development of the UPS delivery network throughout Central and South America. In 1990, Mr. Weidemeyer became Vice President and Airline Manager of UPS Airlines and in 1994 was elected its President and Chief Operating Officer. Mr. Weidemeyer became Senior Vice President and a member of the Management Committee of United Parcel Service, Inc. that same year, and he became Chief Operating Officer of United Parcel Service, Inc. in 2001. Mr. Weidemeyer also serves as a director of Goodyear Tire & Rubber Co. and Waste Management, Inc.

Class II Directors (Terms expire in 2008)

Lawrence S. Coben

Chair of Compensation Committee

Mr. Coben has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. He is Chairman and CEO of Tremisis Energy Acquisition Corporation. From January 2001 to January 2004, he was a Senior Principal of Sunrise Capital Partners, a private equity firm. From 1997 to 2001, Mr. Coben was an independent consultant. From 1994 to 1996, Mr. Coben was Chief Executive Officer of Bolivian Power Company. Mr. Coben is also a director of Prisma Energy.

Herbert H. Tate

Member of Governance and Nominating Committee

Mr. Tate has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Mr. Tate joined NiSource, Inc. as Corporate Vice President, Regulatory Strategy in July 2004. He was Of Counsel of Wolf & Samson P.C., a law firm, since September 2002 to July 2004. Mr. Tate was Research Professor of Energy Policy Studies at the New Jersey Institute of Technology from April 2001 to September 2002 and President of New Jersey Board of Public Utilities from 1994 to March 2001. Mr. Tate is also a director of IDT Capital and IDT Spectrum. Previously, Mr. Tate was a member of the Board of Directors for Central Vermont Public Service from April 2001 to June 2004, where he was a member of the Audit Committee.

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Walter R. Young

Chair of Governance and Nominating Committee

Mr. Young has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Mr. Young was Chairman, Chief Executive Officer and President of Champion Enterprises, Inc., an assembler and manufacturer of manufactured homes, from May 1990 to June 2003. Mr. Young has held senior management positions with The Henley Group, The Budd Company and BFGoodrich.

Class III Directors (Terms expire in 2006)

John F. Chlebowski

Chair of Audit Committee

Member of Governance and Nominating Committee

Mr. Chlebowski has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization. Mr. Chlebowski served as the President and Chief Executive Officer of Lakeshore Operating Partners, LLC, a bulk liquid distribution firm, from March 2000 until his retirement in December 2004. From July 1999 until March 2000, Mr. Chlebowski was a senior executive and cofounder of Lakeshore Liquids Operating Partners, LLC, a private venture firm in the bulk liquid distribution and logistics business, and from January 1998 until July 1999, he was a private investor and consultant in bulk liquid distribution. Prior to that, he was employed by GATX Terminals Corporation, a subsidiary of GATX Corporation, as President and Chief Executive Officer from 1994 until 1997. Mr. Chlebowski is a director of Laidlaw International Inc.

Howard E. Cosgrove

Chairman of the Board
Member of Audit Committee

Mr. Cosgrove has been a director of NRG since December 2003, pursuant to the NRG plan of reorganization, and Chairman of the Board since December 2003. He was Chairman and Chief Executive Officer of Conectiv and its predecessor Delmarva Power and Light from December 1992 to August 2002. Prior to December 1992, Mr. Cosgrove held various positions with Delmarva Power and Light including Chief Operating Officer and Chief Financial Officer. Mr. Cosgrove serves as Chairman of the Board of Trustees at the University of Delaware.

Anne C. Schaumburg

Member of Audit Committee

Ms. Schaumburg has been a director of NRG since April 2005. From 1984 until her retirement in 2002, she was at Credit Suisse First Boston in the Global Energy Group, where she last served as Managing Director. From 1979 to 1984, she was in the Utilities Group at Dean Witter Financial Services Group, where she last served as Managing Director. From 1971 to 1978, she was at The First Boston Corporation in the Public Utilities Group.

Certain Officers

Our officers are elected by our board of directors annually to hold office until their successors are elected and qualified.

David Crane

President and Chief Executive Officer

For biographical information for David Crane, see “—Board of Directors.”

Robert C. Flexon

Executive Vice President and Chief Financial Officer

Mr. Flexon has been Executive Vice President and Chief Financial Officer of NRG since March 2004. In this capacity, he manages NRG’s corporate finance, accounting, tax, risk management, information technol-

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ogy, and overall internal control program. Prior to joining NRG, Mr. Flexon was Vice President, Corporate Development & Work Process and Vice President, Business Analysis and Controller of Hercules, Inc. for four years. Mr. Flexon also held various financial management positions, including General Auditor, Franchise Manager and Controller, during his 13 years with Atlantic Richfield Company. Mr. Flexon began his career with the former Coopers & Lybrand public accounting firm.

Caroline Angoorly

Vice President, Environmental and New Business

Ms. Angoorly has served as Vice President, Environmental & New Business for NRG since May 2004. She is responsible for our strategy and initiatives in the environmental and green business arenas. Prior to joining NRG, Ms. Angoorly served as Vice President and General Counsel at Enel North America, Inc., a Director and the Chief Financial Officer at Line56Media, and a partner in the Global Project Finance Group at Milbank, Tweed, Hadley & McCloy. Ms. Angoorly holds a Bachelor of Science degree in Geology and a Bachelor of Laws degree from Monash University in Melbourne, Australia. She also holds a Master of Business Administration degree, with an emphasis on international finance and economics, from Melbourne and Columbia Business Schools.

John P. Brewster

Executive Vice President, International Operations and President, South Central Region

Mr. Brewster has been Executive Vice President, International Operations and President, South Central Region of NRG since March 2004. He is responsible for managing the asset portfolio for NRG’s South Central Region and international operations. Previously, he served as Vice President, Worldwide Operations of NRG, Vice President, North American Operations and Vice President of Production for NRG Louisiana Generating, Inc. Prior to joining NRG, Mr. Brewster spent 22 years with Cajun Electric Power Cooperative where he served as Vice President of Production, Manager of Power System Operations and Assistant Plan Manager.

Scott J. Davido

Executive Vice President and President, Northeast Region

Mr. Davido has been Executive Vice President and President, Northeast Region of NRG since March 2004 and served as Senior Vice President, General Counsel and Secretary from October 2002 to March 2004. Mr. Davido also served as Chairman of the Board from May 2003 to December 2003, the period in which NRG was reorganizing under chapter 11 of the bankruptcy code. He served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary of the Elder-Beerman Stores Corp., a department store retailer, from March 1999 to May 2002 and Senior Vice President, General Counsel from January 1998 to March 1999. Mr. Davido was a Partner, Business Practice Group with Jones, Day, Reavis & Pogue, a law firm, in Pittsburgh, Pennsylvania, from January 1997 to December 1997 and an Associate, Business Practice Group from September 1987 to December 1996.

Kevin T. Howell

Executive Vice President, Commercial Operations

Mr. Howell has been Executive Vice President, Commercial Operations since August 2005 and is responsible for the commercial management of the North America asset portfolio. Prior to joining NRG, he served as President of Dominion Energy Clearinghouse since 2001. From 1995 to 2001, Mr. Howell held various positions within Duke Energy companies including Senior Vice President of Duke Energy Trading and Marketing, Senior Vice President of Duke Energy International, and most recently, Executive Vice President of Duke Energy Merchants where he managed a global trading group dealing in refined products, LNG and coal. Prior to his five years at Duke, Mr. Howell worked in a variety of trading, marketing and operations functions at MG Natural Gas Corp., Associated Natural Gas and Panhandle Eastern Pipeline.

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James J. Ingoldsby

Vice President and Controller

Mr. Ingoldsby has been Vice President and Controller of NRG since May 2004. He is responsible for directing NRG’s financial accounting and reporting activities, as well as ensuring our compliance with Sarbanes-Oxley legislation. Mr. Ingoldsby, who led the Sarbanes-Oxley implementation at chemical company Hercules, Inc., previously held various executive positions at GE Betz, formerly BetzDearborn from May 1993 to April 2003, including serving as Controller and Director of Business Analysis and Director of Financial Reporting. He also held various staff and managerial accounting and auditing positions at Mack Trucks, Inc from February 1982 to May 1993. Mr. Ingoldsby began his career with Deloitte and Touche where he became a Certified Public Accountant.

Christine A. Jacobs

Vice President, Plant Operations

Ms. Jacobs has been Vice President, Plant Operations of NRG since September 2004. She is responsible for domestic plant operations, including safety, physical security, engineering and procurement, and application of best operating practices. Ms. Jacobs has more than 30 years of diverse operating and commercial management experience. Prior to joining NRG, she served as Executive Vice President, Facility Services/ Healthcare Management for Aramark Corporation from 2003 to 2004. Additionally, Ms. Jacobs served as Senior Vice President, Exelon Generation, and President, Exelon Power from 2000 to 2002.

Timothy W.J. O’Brien

Vice President and General Counsel

Mr. O’Brien has been Vice President and General Counsel of NRG since April 2004. He is responsible for legal affairs at the Company. He served as Secretary from April 2004 to July 2005, as Deputy General Counsel of NRG from 2000 to 2004 and Assistant General Counsel from 1996 to 2000. Prior to joining NRG, Mr. O’Brien was an associate at Sheppard, Mullin, Richter & Hampton in Los Angeles and San Diego, California.

George P. Schaefer

Vice President and Treasurer

Mr. Schaefer has been Vice President and Treasurer since December 2002. He is responsible for all treasury functions, including bank relations and corporate and project finance activities. Prior to joining NRG, Mr. Schaefer served as Senior Vice President, Finance and Treasurer for PSEG Global, Inc., an operator of power plants and utilities, for one year, Vice President of Enron North America in its independent energy unit from June 2000 to April 2001 and Vice President and Treasurer of Reliant Energy International, an operator of power plants and utilities, from June 1995 to June 2000. Prior to 1995, he was the Vice President, Business Development for Entergy Power Group and held the Senior Vice President, Structured Finance Group position with General Electric Capital Corporation.

Steve Winn

Executive Vice President and President, Texas Region

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

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Acquisition Agreement

Pursuant to the Acquisition Agreement, the direct and indirect owners of equity units of Texas Genco, or the Sellers, will receive approximately $6.121 billion comprised of $4.399 billion in cash, subject to adjustment, a minimum of 35,406,320 shares of NRG common stock and, at NRG’s election, either an additional 9,038,125 shares of NRG common stock, additional cash, shares of NRG preferred stock or a combination of the foregoing. We have elected to pay this amount in cash. The Sellers will be prohibited from transferring the shares of common stock and preferred stock that they receive in connection with the Acquisition for 180 days following the closing date of the Acquisition.

Investor Rights Agreement

NRG and the Sellers will enter into an Investor Rights Agreement, dated the closing date of the Acquisition, pursuant to which NRG will file an “evergreen” shelf registration statement, registering for resale upon expiration of the 180-day lock-up period by the Sellers the shares of common stock and preferred stock that they will receive pursuant to the Acquisition Agreement on or before the date 120 days from the closing date of the Acquisition. Any Seller or group of Sellers holding in excess of 3% of the aggregate number of shares of NRG common stock issued and outstanding, or 20% of the aggregate number of shares of preferred stock originally issued pursuant to the Acquisition Agreement, may request that a resale under the shelf registration statement involve an underwritten offering, and NRG will use its commercially reasonable efforts to make its executive officers available to participate in “road shows” or other selling efforts reasonably requested by the Sellers, not to exceed one “road show” per 180-day period. The Sellers will also be entitled to include shares of NRG common stock and preferred stock they receive pursuant to the Acquisition Agreement on any registration statement filed by NRG that would permit registration of such shares of common stock and preferred stock for sale to the public.

In addition, until the second anniversary of the closing date of the Acquisition, the Sellers will agree not to acquire any additional voting securities of NRG (subject to certain exceptions), make any public announcement with respect to, or submit any proposal for, any merger, dissolution or restructuring involving NRG or any of its subsidiaries, solicit proxies to vote any voting security of NRG or seek to influence the vote of any voting securities of NRG, join, form or participate in any group with respect to voting securities of NRG, seek to call a meeting or execute a written consent of the stockholders of NRG, seek representation on NRG’s board of directors or seek removal of a director from the board. Certain Sellers will have the right to consult with and advise management of NRG on matters relating to its operation. NRG will agree to consider in good faith the reasonable recommendations of such Sellers, but ultimate discretion with respect to all matters will remain with NRG.

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DESCRIPTION OF THE NOTES

You can find the definitions of certain terms used in this description under the subheading “Certain Definitions.” In this description, “NRG” refers only to NRG Energy, Inc. and not to any of its subsidiaries, and the 2014 fixed rate notes, the 2014 floating rate notes and the 2016 notes are each referred to as a “series of notes.”

NRG will issue the 2014 floating rate notes under the 2014 floating rate indenture, the 2014 fixed rate notes under the 2014 fixed rate indenture and the 2016 notes under the 2016 indenture, all of which we collectively refer to as the “indentures.” The terms of the notes include those stated in the applicable indenture and those made part of such indenture by reference to the Trust Indenture Act of 1939, as amended. The escrow and security agreement referred to below under the caption “—Escrow of Proceeds; Special Mandatory Redemption” defines the terms of the escrow of the net proceeds from this offering and other funds pending consummation of the Acquisition.

The following description is a summary of the material provisions of the notes, the indentures and the escrow and security agreement. It does not restate those agreements in their entirety. We urge you to read those agreements because they, and not this description, define your rights as holders of the notes. We have filed a copy of the indentures and the escrow and security agreement as exhibits incorporated by reference in the registration statement relating to this prospectus supplement. Certain defined terms used in this description but not defined below under “—Certain Definitions” have the meanings assigned to them in the indenture.

The registered holder of a note is treated as the owner of it for all purposes. Only registered holders have rights under the applicable indenture.

Brief Description of the Notes

The notes:


	•	after consummation of the Acquisition, will be general unsecured obligations of NRG;

	•	will be secured by a security interest in the escrow account until the earlier of September 30, 2006 and the date on which NRG consummates the Acquisition;

	•	will be pari passu in right of payment with all existing and future unsecured senior Indebtedness of NRG;

	•	will be senior in right of payment to any future subordinated Indebtedness of NRG; and

	•	will be unconditionally guaranteed on a joint and several basis by the Guarantors.

However, the notes will be effectively subordinated to all borrowings under the Credit Agreement, which will be secured by substantially all of the assets of NRG and the Guarantors (other than the escrow account), and any other secured Indebtedness (including any Hedging Obligations secured by junior liens on assets of NRG or its Subsidiaries) we have. See “Risk Factors—Risks Related to the Offering—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.”

The Subsidiary Guarantees

The notes will be guaranteed by the Guarantors. Each guarantee of the notes:


	•	will be a general unsecured obligation of the Guarantor;

	•	will be pari passu in right of payment with all unsecured senior Indebtedness of that Guarantor; and

	•	will be senior in right of payment to any future subordinated Indebtedness of that Guarantor.

The operations of NRG are largely conducted through its subsidiaries and, therefore, NRG depends on the cash flow of its subsidiaries to meet its obligations, including its obligations under the notes. Not all of

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NRG’s subsidiaries will guarantee the notes. The notes will be effectively subordinated in right of payment to all Indebtedness and other liabilities and commitments (including trade payables and lease obligations) of these non-guarantor subsidiaries. Any right of NRG to receive assets of any of its subsidiaries upon the subsidiary’s liquidation or reorganization (and the consequent right of the holders of the notes to participate in those assets) will be effectively subordinated to the claims of that subsidiary’s creditors, except to the extent that NRG is itself recognized as a creditor of the subsidiary, in which case its claims would still be subordinate in right of payment to any security in the assets of the subsidiary and any indebtedness of the subsidiary senior to that held by NRG. After giving effect to this offering of notes, the pending acquisition of Texas Genco LLC, the Related Financing Transactions and the remaining Transactions, the guarantor subsidiaries would have accounted for approximately 90% of NRG’s revenues from wholly-owned operations for the nine-month period ended September 30, 2005. On such basis, such guarantor subsidiaries held approximately 90% of NRG’s consolidated assets as of September 30, 2005. As of September 30, 2005, on a pro forma basis, NRG’s non-guarantor subsidiaries had approximately $781 million in aggregate principal amount of external funded indebtedness and the outstanding trade payables of NRG and its subsidiaries was $339 million. Approximately 77% of these trade payables would have constituted obligations of NRG and the Guarantors. See “Risk Factors—Risks Relating to the Offering—Your right to receive payments on these notes could be adversely affected if any of our non-guarantor subsidiaries declare bankruptcy, liquidate, or reorganize.” See note 33 to the consolidated financial statements of NRG incorporated by reference into this prospectus supplement for more detail about the historical division of NRG Energy, Inc.’s consolidated revenues and assets between the Guarantor and non-Guarantor Subsidiaries.

Under the circumstances described below under the caption “—Certain Covenants—Designation of Restricted, Unrestricted and Excluded Project Subsidiaries,” NRG will be permitted to designate certain of its subsidiaries as “Unrestricted Subsidiaries” or “Excluded Project Subsidiaries.” NRG’s Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indentures. NRG’s Unrestricted Subsidiaries and Excluded Subsidiaries will not guarantee the notes.

Principal, Maturity and Interest

NRG will issue $ million in aggregate principal amount of Floating Rate Senior Notes due 2014, $ million in aggregate principal amount of % Senior Notes due 2014, and $ million in aggregate principal amount of % Senior Notes due 2016 in this offering. NRG may issue additional notes under any of the indentures from time to time after this offering. Any issuance of additional notes is subject to all of the covenants in each applicable indenture, including the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” The notes and any additional notes subsequently issued under any of the indentures will be treated as a single class for all purposes under that indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. NRG will issue notes in denominations of $5,000 and integral multiples of $5,000. The 2014 notes will mature on February 1, 2014 and the 2016 notes will mature on February 1, 2016.


	*2014 Fixed Rate Notes*

Interest on the 2014 fixed rate notes will accrue at the rate of % per annum and will be payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2006. NRG will make each interest payment to the holders of record on the immediately preceding January 15 and July 15.

Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.


	*2016 Notes*

Interest on the 2016 notes will accrue at the rate of % per annum and will be payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2006. NRG will make each interest payment to the holders of record on the immediately preceding January 15 and July 15.

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	*2014 Floating Rate Notes*

Interest on the 2014 floating rate notes will accrue at a rate per annum, reset quarterly, equal to LIBOR plus %, as determined by the calculation agent (the “Calculation Agent”), which will initially be the trustee. NRG will pay interest on the 2014 floating rate notes quarterly, in arrears, on every February 1, May 1, August 1 and November 1, commencing on May 1, 2006. NRG will make each interest payment to the holders of record of the 2014 floating rate notes on the January 15, April 15, July 15 and October 15 immediately preceding the applicable interest payment date. Interest on the 2014 floating rate notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid.

The amount of interest for each day that the 2014 floating rate notes are outstanding (the “Daily Interest Amount”) will be calculated by dividing the interest rate in effect for such day by 360 and multiplying the result by the principal amount of the 2014 floating rate notes then outstanding. The amount of interest to be paid on the 2014 floating rate notes for each Interest Period will be calculated by adding the Daily Interest Amounts for each day in the Interest Period. All percentages resulting from any of the above calculations will be rounded, if necessary, to the nearest one hundred thousandth of a percentage point, with five one-millionths of a percentage point being rounded upwards, and all dollar amounts used in or resulting from such calculations will be rounded to the nearest cent (with one-half cent being rounded upwards).

The Calculation Agent will, upon the request of any holder of floating rate notes, provide the interest rate then in effect with respect to the floating rate notes. All calculations made by the Calculation Agent in the absence of manifest error will be conclusive for all purposes and binding on NRG, the Guarantors and the holders of the floating rate notes.

Escrow of Proceeds; Special Mandatory Redemption

On the closing date for this offering, NRG will enter into the escrow and security agreement with the trustee in its capacity as escrow agent. At the same time, the initial purchasers will deposit the net proceeds of this offering, approximately $ million, into the escrow account created under the escrow and security agreement. All funds deposited into the escrow account will be held by the escrow agent for the benefit of the holders of the notes. If the closing of the Acquisition and the Related Financing Transactions do not occur on or before September 30, 2006 on substantially the terms described in this prospectus supplement, the indentures will require that we redeem all and not less than all of the notes then outstanding, upon not less than 10 days’ notice, 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 NRG redeems the notes as described herein, holders of notes will have to rely on NRG for payments of amounts in excess of the net proceeds of the offering. For more information, see “Risk Factors—Risks Relating to the Offering—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 indentures.” If the closing of the Acquisition and the Related Financing Transactions occur on or before September 30, 2006 on substantially the terms described in this prospectus supplement, then, subject to the conditions set forth below, all amounts in the escrow account will be released to NRG on the date that the Acquisition closes. Upon the closing of the Acquisition, the foregoing provisions regarding the special mandatory redemption will cease to apply.

Pending release of the funds in the escrow account (a) to NRG upon consummation of the Acquisition and the Related Financing Transactions, if any, occurring concurrently with the Acquisition, or (b) to the trustee in the event of a special mandatory redemption, such funds will be invested in Government Securities.

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The escrow and security agreement will provide that the escrow agent will release the funds from the escrow account as directed by the trustee:


	•	to NRG upon the satisfaction of the following conditions (and delivery to the trustee of a certificate from an officer of NRG confirming that these conditions have been satisfied):


	(1) all conditions to the closing of the Acquisition have been satisfied or waived;

	(2) the Acquisition will be consummated concurrently with the release of funds and on substantially the terms described in this prospectus supplement;

	(3) the Related Financing Transactions have been consummated or will be consummated prior to or concurrently with the consummation of the Acquisition;

	(4) the escrowed funds will be applied in the manner described under the caption “Use of Proceeds”; and

	(5) no Event of Default shall have occurred and be continuing or result therefrom; or


	•	to the trustee in connection with a special mandatory redemption.

NRG will also grant to the trustee for the benefit of the holders of the notes a security interest in the escrow account, and the escrow and security agreement will require that such security interest be perfected prior to the closing of this offering. See “Risk Factors—Risks Related to the Offering—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 at any time the escrow account contains cash and/or Government Securities having an aggregate value in excess of the special mandatory redemption price on September 30, 2006 (the latest date on which the special mandatory redemption can occur), such excess funds may be released to NRG at NRG’s option. Upon the acceleration of the maturity of the notes or the failure to pay principal at maturity or upon certain redemptions and repurchases of the notes, the escrow and security agreement will provide for the foreclosure by the trustee upon the funds and Government Securities held in the escrow account. In the event of such a foreclosure, the proceeds of the escrow account will be applied, first, to amounts owing to the trustee in respect of fees and expenses of the trustee, second, to the holders of notes to the full extent of all Obligations under the indentures and the notes and, third, any remainder to NRG or its estate, as the case may be.

Methods of Receiving Payments on the Notes

If a holder of notes has given wire transfer instructions to NRG, NRG will pay or cause to be paid all principal, interest and premium on that holder’s notes in accordance with those instructions. All other payments on notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless NRG elects to make interest payments by check mailed to the noteholders at their address set forth in the register of holders.

Paying Agent and Registrar for the Notes

The trustee will initially act as paying agent and registrar. NRG may change the paying agent or registrar without prior notice to the holders of the notes, and NRG or any of its Subsidiaries may act as paying agent or registrar.

Transfer and Exchange

A holder may transfer or exchange notes in accordance with the provisions of the applicable indenture pursuant to which such notes were issued. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer. NRG is not required to transfer or exchange any note selected for redemption. Also, NRG is not required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.

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Subsidiary Guarantees

NRG’s payment obligations under the notes will be guaranteed on an unconditional basis by each of NRG’s current and future Restricted Subsidiaries, other than the Excluded Subsidiaries for so long as they constitute Excluded Subsidiaries. These Subsidiary Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors—Risks Related to the Offering—Federal and state statutes allow courts, under specific circumstances, to void guarantees and require note holders to return payments received from guarantors.”

A Guarantor may not sell or otherwise dispose of all or substantially all of its assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person), another Person, other than NRG or another Guarantor, unless:


	(1) immediately after giving effect to that transaction, no Default or Event of Default exists; and

	(2) either:


	(a) the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger assumes all the obligations of that Guarantor under each applicable indenture and its Subsidiary Guarantee pursuant to supplemental agreements reasonably satisfactory to the trustee under such indenture;

	(b) the Net Proceeds of such sale or other disposition are applied in accordance with the applicable provisions of each applicable indenture; or

	(c) immediately after giving effect to that transaction, such Person qualifies as an Excluded Subsidiary.

The Subsidiary Guarantee of a Guarantor of any series of notes will be released automatically:


	(1) in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) NRG or a Restricted Subsidiary of NRG, if the sale or other disposition does not violate the “Asset Sale” provisions of the applicable indenture governing such series of notes;

	(2) in connection with any sale or other disposition of Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) NRG or a Restricted Subsidiary of NRG, if (a) the sale or other disposition does not violate the “Asset Sale” provisions of the applicable indenture governing such series of notes and (b) following such sale or other disposition, that Guarantor is not a direct or indirect Subsidiary of NRG;

	(3) if NRG designates any Restricted Subsidiary that is a Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the applicable indenture governing such series of notes;

	(4) the date that any Subsidiary that is not an Excluded Subsidiary becomes an Excluded Subsidiary;

	(5) upon defeasance or satisfaction and discharge of such notes as provided below under the captions “—Legal Defeasance and Covenant Defeasance” and “—Satisfaction and Discharge”;

	(6) upon a dissolution of a Guarantor that is permitted under the applicable indenture governing such series of notes;

	(7) as to any Subsidiary Guarantee issued on the date of the applicable supplemental indenture that is subject to Section 69 of the New York Public Service Law, on the 364th day after such issuance, unless on or before such 364th day such Guarantee is permitted under the New York Public Service Law, pursuant to an order issued by the New York Public Service Commission, to be outstanding after such 364th day; or

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	(8) otherwise with respect to the Guarantee of any Guarantor, upon:


	(a) the prior consent of holders of at least a majority in aggregate principal amount of such notes then outstanding;

	(b) the consent of requisite lenders under the Credit Agreement (as amended, restated, modified, renewed, refunded, replaced or refinanced from time to time) to the release of such Guarantor’s Guarantee of all Obligations under the Credit Agreement; or

	(c) the contemporaneous release of such Guarantor’s Guarantee of all Obligations under the Credit Agreement (as amended, restated, modified, renewed, refunded, replaced or refinanced from time to time).


	See “—Repurchase at the Option of Holders—Asset Sales.”

Optional Redemption


	*2014 Fixed Rate Notes*

At any time prior to February 1, 2009, NRG may on any one or more occasions redeem up to 35% of the aggregate principal amount of 2014 fixed rate notes issued under the 2014 fixed rate indenture, upon not less than 30 nor more than 60 days notice, at a redemption price of % of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of one or more Equity Offerings; provided that:


	(1) at least 65% of the aggregate principal amount of 2014 fixed rate notes issued in this offering (excluding 2014 fixed rate notes held by NRG and its Subsidiaries) remains outstanding immediately after the occurrence of such redemption; and

	(2) the redemption occurs within 90 days of the date of the closing of such Equity Offering.

In addition, the 2014 fixed rate indenture and the escrow and security agreement will allow NRG to redeem the 2014 fixed rate 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 2014 fixed rate 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. If we exercise this option, NRG will redeem the 2014 fixed rate notes, in part, with the amounts held in the escrow account upon 10 days prior notice. See “—Escrow of Proceeds; Special Mandatory Redemption.”

At any time prior to February 1, 2010, NRG may on any one or more occasions redeem all or a part of the 2014 fixed rate notes, upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to 100% of the principal amount of 2014 fixed rate notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest if any, to the redemption date, subject to the rights of holders of 2014 fixed rate notes on the relevant record date to receive interest due on the relevant interest payment date.

Except pursuant to the preceding three paragraphs, the 2014 fixed rate notes will not be redeemable at NRG’s option prior to February 1, 2010. NRG is not prohibited, however, from acquiring the 2014 fixed rate notes in market transactions by means other than a redemption, whether pursuant to a tender offer or otherwise, assuming such action does not otherwise violate the 2014 fixed rate indenture.

On or after February 1, 2010, NRG may on any one or more occasions redeem all or a part of the 2014 fixed rate notes upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest on the 2014 fixed rate notes redeemed, to the applicable redemption date, if redeemed during the twelve-month period beginning on

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February 1 of the years indicated below, subject to the rights of noteholders on the relevant record date to receive interest on the relevant interest payment date:


Year	Percentage

2010			%
2011			%
2012			%
2013 and thereafter		100.000	%


	*2016 Notes*

At any time prior to February 1, 2009, NRG may on any one or more occasions redeem up to 35% of the aggregate principal amount of 2016 notes issued under the 2016 indenture, upon not less than 30 nor more than 60 days notice, at a redemption price of % of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of one or more Equity Offerings; provided that:


	(1) at least 65% of the aggregate principal amount of 2016 notes issued in this offering (excluding 2016 notes held by NRG and its Subsidiaries) remains outstanding immediately after the occurrence of such redemption; and

	(2) the redemption occurs within 90 days of the date of the closing of such Equity Offering.

In addition, the 2016 indenture and the escrow and security agreement will allow NRG to redeem the 2016 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 2016 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. If we exercise this option, NRG will redeem the 2016 notes, in part, with the amounts held in the escrow account upon 10 days prior notice. See “—Escrow of Proceeds; Special Mandatory Redemption.”

At any time prior to February 1, 2011, NRG may on any one or more occasions redeem all or a part of the 2016 notes, upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to 100% of the principal amount of 2016 notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest if any, to the redemption date, subject to the rights of holders of 2016 notes on the relevant record date to receive interest due on the relevant interest payment date.

Except pursuant to the preceding three paragraphs, the 2016 notes will not be redeemable at NRG’s option prior to February 1, 2011. NRG is not prohibited, however, from acquiring the 2016 notes in market transactions by means other than a redemption, whether pursuant to a tender offer or otherwise, assuming such action does not otherwise violate the 2016 indenture.

On or after February 1, 2011, NRG may on any one or more occasions redeem all or a part of the 2016 notes upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest on the 2016 notes redeemed, to the applicable redemption date, if redeemed during the twelve-month period beginning on February 1 of the years indicated below, subject to the rights of noteholders on the relevant record date to receive interest on the relevant interest payment date:


Year	Percentage

2011			%
2012			%
2013			%
2014			%
2015 and thereafter		100.000	%

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	*2014 Floating Rate Notes*

At any time prior to February 1, 2008, NRG may on any one or more occasions redeem up to 35% of the aggregate principal amount of 2014 floating rate notes issued under the 2014 floating rate indenture, upon not less than 30 nor more than 60 days notice, at a redemption price of 100%, plus LIBOR as of the most recent Determination Date plus %, of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of one or more Equity Offerings; provided that:


	(1) at least 65% of the aggregate principal amount of 2014 floating rate notes issued in this offering (excluding 2014 floating rate notes held by NRG and its Subsidiaries) remains outstanding immediately after the occurrence of such redemption; and

	(2) the redemption occurs within 90 days of the date of the closing of such Equity Offering.

In addition, the 2014 floating rate indenture and the escrow and security agreement will allow NRG to redeem the 2014 floating rate 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 2014 floating rate 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. If we exercise this option, NRG will redeem the 2014 floating rate notes, in part, with the amounts held in the escrow account upon 10 days prior notice. See “—Escrow of Proceeds; Special Mandatory Redemption.”

Except pursuant to the preceding two paragraphs, the 2014 floating rate notes will not be redeemable at NRG’s option prior to February 1, 2008. NRG is not prohibited, however, from acquiring the 2014 floating rate notes in market transactions by means other than a redemption, whether pursuant to a tender offer or otherwise, assuming such action does not otherwise violate the 2014 floating rate indenture.

On or after February 1, 2008, NRG may on any one or more occasions redeem all or a part of the 2014 floating rate notes upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest on the 2014 floating rate notes redeemed, to the applicable redemption date, if redeemed during the twelve-month period beginning on February 1 of the years indicated below, subject to the rights of noteholders on the relevant record date to receive interest on the relevant interest payment date:


Year	Percentage

2008			%
2009			%
2010			%
2011 and thereafter		100.000	%

Mandatory Redemption

Except as set forth under the caption “—Escrow of Proceeds; Special Mandatory Redemption,” NRG is not required to make mandatory redemption or sinking fund payments with respect to the notes.

Repurchase at the Option of Holders


	*Change of Control*

If a Change of Control occurs, each holder of notes will have the right to require NRG to repurchase all or any part (equal to $5,000 or an integral multiple of $5,000) of that holder’s notes pursuant to a Change of Control Offer on the terms set forth in the applicable indenture governing such notes. In the Change of Control Offer, NRG will offer a Change of Control Payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest on the notes repurchased, to the date of purchase, subject to the rights of noteholders on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, NRG will mail a notice to each

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holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes on the Change of Control Payment Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the applicable indenture and described in such notice. NRG will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the applicable indenture, NRG will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the applicable indenture by virtue of such compliance.

On the Change of Control Payment Date, NRG will, to the extent lawful:


	(1) accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;

	(2) deposit with the applicable paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

	(3) deliver or cause to be delivered to the applicable trustee the notes properly accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by NRG.

The applicable paying agent will promptly mail to each holder of notes properly tendered the Change of Control Payment for such notes, and the applicable trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each new note will be in a principal amount of $5,000 or an integral multiple of $5,000. NRG will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

The provisions described above that require NRG to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the applicable indenture are applicable.

Except as described above with respect to a Change of Control, the indentures do not contain provisions that permit the holders of the notes to require that NRG repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

NRG will not be required to make a Change of Control Offer upon a Change of Control if (1) a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the applicable indenture applicable to a Change of Control Offer made by NRG and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, or (2) notice of redemption has been given pursuant to the applicable indenture as described above under the caption “—Optional Redemption,” unless and until there is a default in payment of the applicable redemption price. A Change in Control Offer may be made in advance of a Change of Control, with the obligation to pay and the timing of payment conditioned upon the consummation of the Change of Control, if a definitive agreement to effect a Change of Control is in place at the time of the Offer.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of NRG and its Subsidiaries taken as a whole. There is a limited body of case law interpreting the phrase “substantially all,” and there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require NRG to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of NRG and its Subsidiaries taken as a whole to another Person or group may be uncertain.

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	*Asset Sales*

NRG will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:


	(1) NRG (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the fair market value of the assets or Equity Interests issued or sold or otherwise disposed of or, in the case of Specified Joint Venture Sales, receives consideration at least equal to the value prescribed by the agreements relating to such specified joint ventures; and

	(2) at least 75% of the consideration received in the Asset Sale by NRG or such Restricted Subsidiary is in the form of cash. For purposes of this provision, each of the following will be deemed to be cash:


	(a) any liabilities, as shown on NRG’s most recent consolidated balance sheet, of NRG or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Subsidiary Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases NRG or such Restricted Subsidiary from further liability;

	(b) any securities, notes or other obligations received by NRG or any such Restricted Subsidiary from such transferee that are converted by NRG or such Restricted Subsidiary into cash within 180 days of the receipt of such securities, notes or other obligations, to the extent of the cash received in that conversion;

	(c) any stock or assets of the kind referred to in clauses (4) or (6) of the next paragraph of this covenant; and

	(d) any Designated Noncash Consideration received by NRG or any Restricted Subsidiary in such Asset Sale having an aggregate fair market value, taken together with all other Designated Noncash Consideration received pursuant to this clause (d) that is at the time outstanding, not to exceed the greater of (x) $500.0 million or (y) 2.5% of Total Assets at the time of the receipt of such Designated Noncash Consideration, with the fair market value of each item of Designated Noncash Consideration being measured at the time received and without giving effect to subsequent changes in value.

Within 365 days after the receipt of any Net Proceeds from an Asset Sale, other than Excluded Proceeds, NRG (or the applicable Restricted Subsidiary, as the case may be) may apply those Net Proceeds or, at its option, enter into a binding commitment to apply such Net Proceeds within the 365-day period following the date of such commitment (an “Acceptable Commitment”):


	(1) to repay Indebtedness and other Obligations under a Credit Facility and, if such Indebtedness is revolving credit Indebtedness, to correspondingly reduce commitments with respect thereto;

	(2) in the case of a sale of assets pledged to secure Indebtedness (including Capital Lease Obligations), to repay the Indebtedness secured by those assets;

	(3) in the case of an Asset Sale by a Restricted Subsidiary that is not a Guarantor, to repay Indebtedness of a Restricted Subsidiary that is not a Guarantor (other than Indebtedness owed to NRG or another Restricted Subsidiary of NRG);

	(4) to acquire all or substantially all of the assets of, or any Capital Stock of, another Person engaged primarily in a Permitted Business, if, after giving effect to any such acquisition of Capital Stock, such Person is or becomes a Restricted Subsidiary of NRG and a Guarantor;

	(5) to make a capital expenditure;

	(6) to acquire other assets that are not classified as current assets under GAAP and that are used or useful in a Permitted Business; or

	(7) any combination of the foregoing.

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Pending the final application of any such Net Proceeds and notwithstanding clause (1) above, NRG may temporarily reduce revolving credit borrowings or otherwise use the Net Proceeds in any manner that is not prohibited by the indentures.

Notwithstanding the preceding paragraph, in the event that regulatory approval is necessary for an asset or investment, or construction, repair or restoration on any asset or investment has commenced, then NRG or any Restricted Subsidiary shall have an additional 365 days to apply the Net Proceeds from such Asset Sale in accordance with the preceding paragraph.

Any Acceptable Commitment that is later canceled or terminated for any reason before such Net Proceeds are so applied shall be treated as a permitted application of the Net Proceeds if NRG or such Restricted Subsidiary enters into another Acceptable Commitment within the later of (a) nine months of such cancellation or termination or (b) the end of the initial 365-day period.

Any Net Proceeds from Asset Sales (other than Excluded Proceeds) that are not applied or invested as provided above will constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $100.0 million, or at such earlier date as may be selected by NRG, NRG will make an Asset Sale Offer to all holders of notes and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the applicable indenture with respect to offers to purchase or redeem with the proceeds of sales of assets to purchase the maximum principal amount of notes and such other pari passu Indebtedness that may be purchased out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount plus accrued and unpaid interest to the date of purchase and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, NRG may use those Excess Proceeds for any purpose not otherwise prohibited by the applicable indenture. If the aggregate principal amount of notes and other pari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such other pari passu Indebtedness to be purchased on a pro rata basis. Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

NRG will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the indentures, NRG will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indentures by virtue of such compliance.

The agreements governing NRG’s other Indebtedness, including the Credit Agreement, contain, and future agreements may contain, prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale and including repurchases of or other prepayments in respect of the notes. The exercise by the holders of notes of their right to require NRG to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on NRG. In the event a Change of Control or Asset Sale occurs at a time when NRG is prohibited from purchasing notes, NRG could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If NRG does not obtain a consent or repay those borrowings, NRG will remain prohibited from purchasing notes. In that case, NRG’s failure to purchase tendered notes would constitute an Event of Default under the indentures which could, in turn, constitute a default under the other indebtedness. Finally, NRG’s ability to pay cash to the holders of notes upon a repurchase may be limited by NRG’s then existing financial resources. See “Risk Factors—Risks Related to the Offering—We may not have the ability to raise the funds necessary to finance the change of control offer required by the indentures.”

Selection and Notice

If less than all of any series of notes are to be redeemed at any time, the trustee for such notes will select notes for redemption on a pro rata basis unless otherwise required by law or applicable stock exchange requirements.

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No notes of $5,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indentures. Notices of redemption may not be conditional.

If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of them called for redemption.

Certain Covenants


	*Changes in Covenants When Notes Rated Investment Grade*

If on any date following the date of the supplemental indenture for any series of notes:


	(1) the rating assigned to such notes by each of S&P and Moody’s is an Investment Grade Rating; and

	(2) no Default or Event of Default shall have occurred and be continuing, then, beginning on that day and subject to the provisions of the following two paragraphs, the covenants in such supplemental indenture specifically listed under the following captions will be suspended as to such notes:


	(a) “—Repurchase at the Option of Holders—Asset Sales;”

	(b) “—Certain Covenants— Restricted Payments;”

	(c) “—Certain Covenants— Incurrence of Indebtedness and Issuance of Preferred Stock;”

	(d) “—Certain Covenants— Dividend and Other Payment Restrictions Affecting Subsidiaries;”

	(e) “—Certain Covenants— Designation of Restricted, Unrestricted and Excluded Project Subsidiaries;”

	(f) “—Transactions with Affiliates;” and

	(g) clause (4) of the covenant described below under the caption “—Merger, Consolidation or Sale of Assets.”

Clauses (a) through (g) above are collectively referred to as the “Suspended Covenants.”

During any period that the foregoing covenants have been suspended, NRG’s Board of Directors may not designate any of its Subsidiaries as Unrestricted Subsidiaries or Excluded Project Subsidiaries pursuant to the covenant described below under the caption “—Designation of Restricted, Unrestricted and Excluded Project Subsidiaries,” the second paragraph of the definition of “Unrestricted Subsidiary,” or the definition of “Excluded Project Subsidiary,” unless it could do so if the foregoing covenants were in effect.

If at any time such notes are downgraded from an Investment Grade Rating by either S&P or Moody’s, the Suspended Covenants will thereafter be reinstated as if such covenants had never been suspended and be applicable pursuant to the terms of the applicable supplemental indenture (including in connection with performing any calculation or assessment to determine compliance with the terms of the applicable supplemental indenture), unless and until such notes subsequently attain an Investment Grade Rating from each of S&P and Moody’s (in which event the Suspended Covenants will again be suspended for such time that the notes maintain an Investment Grade Rating from each of S&P and Moody’s); provided, however, that no Default, Event of Default or breach of any kind will be deemed to exist under the applicable supplemental indenture, such notes or the related Subsidiary Guarantees with respect to the Suspended Covenants based on, and none of NRG or any of its Subsidiaries will bear any liability for, any actions taken or events occurring

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after such notes attain an Investment Grade Rating from each of S&P and Moody’s and before any reinstatement of the Suspended Covenants as provided above, or any actions taken at any time pursuant to any contractual obligation arising prior to the reinstatement, regardless of whether those actions or events would have been permitted if the applicable Suspended Covenant had remained in effect during such period.


	*Restricted Payments*

NRG will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:


	(1) declare or pay any dividend or make any other payment or distribution on account of NRG’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving NRG or any of its Restricted Subsidiaries) or to the direct or indirect holders of NRG’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of NRG or to NRG or a Restricted Subsidiary of NRG);

	(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving NRG) any Equity Interests of NRG or any direct or indirect parent of NRG (other than any such Equity Interests owned by NRG or any Restricted Subsidiary of NRG);

	(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness of NRG or any Guarantor that is contractually subordinated to the notes or any Subsidiary Guarantee of the notes (excluding any intercompany Indebtedness between or among NRG and any of its Restricted Subsidiaries), except (a) a payment of interest or principal at the Stated Maturity thereof or (b) a payment, purchase, redemption, defeasance, acquisition or retirement of any subordinated Indebtedness in anticipation of satisfying a sinking fund obligation, principal installment or payment at final maturity, in each case due within one year of the date of payment, purchase, redemption, defeasance, acquisition or retirement; or

	(4) make any Restricted Investment

(all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as “Restricted Payments”), unless, at the time of and after giving effect to such Restricted Payment:


	(1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment; and

	(2) NRG would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock”; and

	(3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by NRG and its Restricted Subsidiaries since the date of the supplemental indentures (excluding Restricted Payments permitted by clauses (2), (3), (4), (6), (7), (8), (9), (10), (11), (12) and (13) of the next succeeding paragraph), is less than the sum, without duplication, of:


	(a) 50% of the Consolidated Net Income of NRG for the period (taken as one accounting period) from the beginning of the first fiscal quarter commencing before the date of the supplemental indentures to the end of NRG’s most recently ended fiscal quarter for which financial statements are publicly available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus

	(b) 100% of the aggregate proceeds received by NRG after the date of the Acquisition as a contribution to its equity capital (unless such contribution would constitute Disqualified Stock) or

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	from the issue or sale of Equity Interests of NRG (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of NRG that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of NRG), plus

	(c) 100% of the aggregate proceeds received upon the sale or other disposition of any Investment (other than a Permitted Investment) made since the date of the supplemental indentures; plus the net reduction in Investments (other than Permitted Investments) in any Person resulting from dividends, repayments of loans or advances or other transfers of assets subsequent to the date of the supplemental indentures, in each case to NRG or any Restricted Subsidiary from such Person; plus to the extent that the ability to make Restricted Payments was reduced as the result of the designation of an Unrestricted Subsidiary or Excluded Project Subsidiary, the portion (proportionate to NRG’s equity interest in such Subsidiary) of the fair market value of the net assets of such Unrestricted Subsidiary or Excluded Project Subsidiary at the time such Unrestricted Subsidiary or Excluded Project Subsidiary is redesignated, or liquidated or merged into, a Restricted Subsidiary that is not an Excluded Subsidiary; provided, in each case, that the foregoing may not exceed, in the aggregate, the amount of all Investments which previously reduced the ability to make Restricted Payments; and provided further, that Concurrent Cash Distributions shall be excluded from this clause (c).

The preceding provisions will not prohibit:


	(1) the payment of any dividend within 90 days after the date of declaration of the dividend, if at the date of declaration the dividend payment would have complied with the provisions of the applicable indenture;

	(2) so long as no Default has occurred and is continuing or would be caused thereby, the making of any Restricted Payment in exchange for, or out of the aggregate proceeds of the substantially concurrent sale (other than to a Subsidiary of NRG) of, Equity Interests of NRG (other than Disqualified Stock) or from the contribution of equity capital (unless such contribution would constitute Disqualified Stock) to NRG; provided that the amount of any such proceeds that are utilized for any such Restricted Payment will be excluded from clause (3)(b) of the preceding paragraph;

	(3) so long as no Default has occurred and is continuing or would be caused thereby, the defeasance, redemption, repurchase or other acquisition of Indebtedness of NRG or any Guarantor that is contractually subordinated to the notes or to any Subsidiary Guarantee with the proceeds from a substantially concurrent incurrence of Permitted Refinancing Indebtedness;

	(4) the payment of any dividend (or, in the case of any partnership or limited liability company, any similar distribution) by a Restricted Subsidiary of NRG to the holders of its Equity Interests on a pro rata basis;

	(5) so long as no Default has occurred and is continuing or would be caused thereby, (a) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of NRG or any Restricted Subsidiary of NRG held by any current or former officer, director or employee of NRG or any of its Restricted Subsidiaries pursuant to any equity subscription agreement, stock option agreement, severance agreement, shareholders’ agreement or similar agreement or employee benefit plan or (b) the cancellation of Indebtedness owing to NRG or any of its Restricted Subsidiaries from any current or former officer, director or employee of NRG or any of its Restricted Subsidiaries in connection with a repurchase of Equity Interests of NRG or any of its Restricted Subsidiaries; provided that the aggregate price paid for the actions in clause (a) may not exceed $10.0 million in any twelve-month period (with unused amounts in any period being carried over to succeeding periods) and may not exceed $50.0 million in the aggregate since the date of the supplemental indentures; provided, further that (i) such amount in any calendar year may be increased by the cash proceeds of “key man” life insurance policies received by NRG and its Restricted Subsidiaries after the date of the supplemental indentures less any amount previously applied to the making of Restricted Payments pursuant to this clause (5) and

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	(ii) cancellation of the Indebtedness owing to NRG from employees, officers, directors and consultants of NRG or any of its Restricted Subsidiaries in connection with a repurchase of Equity Interests of NRG from such Persons shall be permitted under this clause (5) as if it were a repurchase, redemption, acquisition or retirement for value subject hereto;

	(6) the repurchase of Equity Interests in connection with the exercise of stock options to the extent such Equity Interests represent a portion of the exercise price of those stock options and the repurchases of Equity Interests in connection with the withholding of a portion of the Equity Interests granted or awarded to an employee to pay for the taxes payable by such employee upon such grant or award;

	(7) so long as no Default has occurred and is continuing or would be caused thereby, the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of (a) preferred stock issued pursuant to the Acquisition Agreement described in this prospectus supplement, (b) preferred stock outstanding on the date of the supplemental indentures, (c) Disqualified Stock of NRG or any Restricted Subsidiary of NRG issued on or after the date of the supplemental indentures in accordance with the terms of each applicable indenture or (d) preferred stock issued on or after the date of the supplemental indentures in accordance with the terms of each applicable indenture;

	(8) payments to holders of NRG’s Capital Stock in lieu of the issuance of fractional shares of its Capital Stock;

	(9) the purchase, redemption, acquisition, cancellation or other retirement for a nominal value per right of any rights granted to all the holders of Capital Stock of NRG pursuant to any shareholders’ rights plan adopted for the purpose of protecting shareholders from unfair takeover tactics; provided that any such purchase, redemption, acquisition, cancellation or other retirement of such rights is not for the purpose of evading the limitations of this covenant (all as determined in good faith by a senior financial officer of NRG);

	(10) so long as no Default has occurred and is continuing or would be caused thereby, upon the occurrence of a Change of Control or Asset Sale and after the completion of the offer to repurchase the notes as described above under the caption “—Repurchase at the Option of Holders—Change of Control” or “—Repurchase at the Option of Holders—Asset Sales,” as applicable (including the purchase of all notes tendered), any purchase, defeasance, retirement, redemption or other acquisition of Indebtedness that is contractually subordinated to the notes or any subsidiary guarantee required under the terms of such Indebtedness, with, in the case of an Asset Sale, Net Proceeds, as a result of such Change of Control or Asset Sale;

	(11) so long as no Default has occurred and is continuing or would be caused thereby, the purchase, redemption or other acquisition or retirement for value of the Sponsor Preferred Stock with the Net Proceeds of an Asset Sale; provided that, in connection with such Asset Sale, an Asset Sale Offer has been completed as described above under the caption “—Repurchase at the Option of Holders—Asset Sales” (including the purchase of all notes tendered in such Asset Sale Offer);

	(12) the Acquisition;

	(13) the purchase, redemption, acquisition, cancellation or other retirement of preferred stock of Itiquira to effectuate the Itiquira Refinancing; and

	(14) so long as no Default has occurred and is continuing or would be caused thereby, other Restricted Payments in an aggregate amount not to exceed $250.0 million since the date of the supplemental indentures.

The amount of all Restricted Payments (other than cash) will be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by NRG or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The fair market value of any assets or securities that are required to be valued by this covenant will be determined by a senior financial officer of NRG whose certification with respect thereto will be delivered to the applicable trustee.

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	*Incurrence of Indebtedness and Issuance of Preferred Stock*

NRG will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), and NRG will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock; provided, however, that NRG may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, and the Guarantors may incur Indebtedness (including Acquired Debt) or issue preferred stock, if the Fixed Charge Coverage Ratio for NRG’s most recently ended four full fiscal quarters for which financial statements are publicly available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or preferred stock is issued would have been at least 2.0 to 1, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness (including Acquired Debt) had been incurred or Disqualified Stock or the preferred stock had been issued, as the case may be, at the beginning of such four-quarter period.

The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Debt”):


	(1) the incurrence by NRG and PMI (and the guarantee thereof by the Guarantors) of additional Indebtedness and letters of credit under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of NRG and its Restricted Subsidiaries thereunder) not to exceed $6.0 billion less the aggregate amount of all repayments, optional or mandatory, of the principal of any term Indebtedness under a Credit Facility that have been made by NRG or any of its Restricted Subsidiaries since the date of the supplemental indentures with the Net Proceeds of Asset Sales (other than Excluded Proceeds) and less, without duplication, the aggregate amount of all repayments or commitment reductions with respect to any revolving credit borrowings under a Credit Facility that have been made by NRG or any of its Restricted Subsidiaries since the date of the supplemental indentures as a result of the application of the Net Proceeds of Asset Sales (other than Excluded Proceeds) in accordance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales” (excluding temporary reductions in revolving credit borrowings as contemplated by that covenant);

	(2) the incurrence by NRG and its Restricted Subsidiaries of (i) the Existing Indebtedness and (ii) Acquired Debt (other than Non-Recourse Debt and the Existing Genco Credit Facility and Notes Indebtedness) incurred pursuant to the Acquisition;

	(3) the incurrence by NRG and the Guarantors of Indebtedness represented by the notes and the related Subsidiary Guarantees to be issued on the date of the supplemental indentures;

	(4) the incurrence by NRG or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of design, construction, installation or improvement or lease of property (real or personal), plant or equipment used or useful in the business of NRG or any of its Restricted Subsidiaries or incurred within 180 days thereafter, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4), not to exceed at any time outstanding 5.0% of Total Assets;

	(5) the incurrence by NRG or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to refund, refinance, replace, defease or discharge Indebtedness (other than intercompany Indebtedness) that was permitted by the applicable supplemental indenture to be incurred under the first paragraph of this covenant or clauses (2), (3), (4), (5), (11), (16), (17) (18), (19), (20) and (21) of this paragraph;

	(6) the incurrence by NRG or any of its Restricted Subsidiaries of intercompany Indebtedness between or among NRG and any of its Restricted Subsidiaries; provided, however, that: (a) if NRG or any Guarantor is the obligor on such Indebtedness and the payee is not NRG or a Guarantor, such

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	Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations then due with respect to the notes, in the case of NRG, or the Subsidiary Guarantee, in the case of a Guarantor; and (b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than NRG or a Restricted Subsidiary of NRG and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either NRG or a Restricted Subsidiary of NRG will be deemed, in each case, to constitute an incurrence of such Indebtedness by NRG or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

	(7) the issuance by any of NRG’s Restricted Subsidiaries to NRG or to any of its Restricted Subsidiaries of shares of preferred stock; provided, however, that:


	(a) any subsequent issuance or transfer of Equity Interests that results in any such preferred stock being held by a Person other than NRG or a Restricted Subsidiary of NRG; and

	(b) any sale or other transfer of any such preferred stock to a Person that is not either NRG or a Restricted Subsidiary of NRG;


	will be deemed, in each case, to constitute an issuance of such preferred stock by such Restricted Subsidiary that was not permitted by this clause (7);


	(8) the incurrence by NRG or any of its Restricted Subsidiaries of Hedging Obligations;

	(9) the guarantee by (i) NRG or any of the Guarantors of Indebtedness of NRG or a Guarantor that was permitted to be incurred by another provision of this covenant; (ii) any of the Excluded Project Subsidiaries of Indebtedness of any other Excluded Project Subsidiary; and (iii) any of the Excluded Foreign Subsidiaries of Indebtedness of any other Excluded Foreign Subsidiary; provided that if the Indebtedness being guaranteed is subordinated to or pari passu with the notes, then the guarantee shall be subordinated to the same extent as the Indebtedness guaranteed;

	(10) the incurrence by NRG or any of its Restricted Subsidiaries of Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (except in the case of daylight overdrafts) inadvertently drawn against insufficient funds in the ordinary course of business, so long as such Indebtedness is covered within five business days;

	(11) the Xcel Note;

	(12) the incurrence by NRG or any of its Restricted Subsidiaries of Indebtedness in respect of (i) workers’ compensation claims, self-insurance obligations, bankers’ acceptance and (ii) performance and surety bonds provided by NRG or a Restricted Subsidiary in the ordinary course of business;

	(13) (i) the incurrence of Non-Recourse Debt by any Excluded Project Subsidiary, (ii) the incurrence of Indebtedness and guarantees pursuant to the Itiquira Refinancing, and (iii) the incurrence of the Existing Genco Credit Facility and Notes Indebtedness; provided that such Existing Genco Credit Facility and Notes Indebtedness is paid in full on the first Business Day after the Acquisition is consummated;

	(14) the incurrence of Indebtedness that may be deemed to arise as a result of agreements of NRG or any Restricted Subsidiary of NRG providing for indemnification, adjustment of purchase price or any similar obligations, in each case, incurred in connection with the disposition of any business, assets or Equity Interests of any Subsidiary; provided that the aggregate maximum liability associated with such provisions may not exceed the gross proceeds (including non-cash proceeds) of such disposition;

	(15) the incurrence by NRG or any Restricted Subsidiary of NRG of Indebtedness represented by letters of credit, guarantees or other similar instruments supporting Hedging Obligations of NRG or any of its Restricted Subsidiaries (other than Excluded Subsidiaries) permitted to be incurred by the applicable indenture;

	(16) Indebtedness, Disqualified Stock or preferred stock of Persons or assets that are acquired by NRG or any Restricted Subsidiary of NRG or merged into NRG or a Restricted Subsidiary of NRG in accordance with the terms of the applicable indenture; provided that such Indebtedness, Disqualified

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	Stock or preferred stock is not incurred in contemplation of such acquisition or merger; and provided further that after giving effect to such acquisition or merger, either:


	(a) NRG would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first sentence of this covenant; or

	(b) the Fixed Charge Coverage Ratio would be greater than immediately prior to such acquisition or merger;


	(17) Environmental CapEx Debt; provided, that prior to the incurrence of any Environmental CapEx Debt, NRG shall deliver to the applicable trustee an officers’ certificate designating such Indebtedness as Environmental CapEx Debt;

	(18) Indebtedness incurred to finance Necessary Capital Expenditures; provided, that prior to the incurrence of any Indebtedness to finance Necessary Capital Expenditures, NRG shall deliver to the applicable trustee an officers’ certificate designating such Indebtedness as Necessary CapEx Debt;

	(19) Indebtedness of NRG or any Restricted Subsidiary consisting of (i) the financing of insurance premiums or (ii) take-or-pay obligations contained in supply arrangements, in each case, in the ordinary course of business;

	(20) the incurrence by NRG and the Guarantors of Indebtedness represented by the Related Financing Transactions on or before the date the Acquisition is consummated; and

	(21) the incurrence by NRG and/or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, including all Permitted Refinancing Indebtedness incurred to refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (21), not to exceed $500.0 million.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of proposed Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (21) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, NRG will be permitted to classify such item of Indebtedness on the date of its incurrence, or later reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant. Indebtedness under the Credit Agreement outstanding on the date of the Acquisition will initially be deemed to have been incurred on such date in reliance on the exception provided by clause (1) of the definition of Permitted Debt. The accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; provided, in each such case, that the amount thereof is included in Fixed Charges of NRG as accrued.

For purposes of determining compliance with any U.S. dollar-denominated restriction on the incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency will be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was incurred; provided that if such Indebtedness is incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-dominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-dominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of the Indebtedness being refinanced.

The amount of any Indebtedness outstanding as of any date will be:


	(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;

	(2) the principal amount of the Indebtedness, in the case of any other Indebtedness; and

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	(3) in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:


	(a) the fair market value of such asset at the date of determination, and

	(b) the amount of the Indebtedness of the other Person;

provided that any changes in any of the above shall not give rise to a default under this covenant.


	*Antilayering*

NRG will not incur, and will not permit any Guarantor to incur, any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of NRG or such Guarantor unless such Indebtedness is also contractually subordinated in right of payment to the notes and the applicable Guarantee on substantially identical terms; provided, however, that no Indebtedness will be deemed to be contractually subordinated in right of payment to any other Indebtedness of NRG solely by virtue of being unsecured or by virtue of being secured on a first or junior Lien basis.


	*Liens*

Prior to the payment of the Existing Genco Credit Facility and Notes Indebtedness, NRG will not, and will not permit any of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind securing Indebtedness or Attributable Debt upon the escrow account related to the escrow and security agreement or any property contained in or credited to the escrow account related to the escrow and security agreement.

On and after the payment of the Existing Genco Credit Facility and Notes Indebtedness, NRG will not and will not permit any of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness or Attributable Debt upon any of their property or assets, now owned or hereafter acquired, unless all payments due under the indentures and the notes are secured on an equal and ratable basis with the obligations so secured until such time as such obligations are no longer secured by a Lien.


	*Sale and Leaseback Transactions*

NRG will not, and will not permit any of its Restricted Subsidiaries to, enter into any sale and leaseback transaction; provided that NRG or any Guarantor may enter into a sale and leaseback transaction if:


	(1) NRG or that Guarantor, as applicable, could have (a) incurred Indebtedness in an amount equal to the Attributable Debt relating to such sale and leaseback transaction under the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock” and (b) incurred a Lien to secure such Indebtedness pursuant to the covenant described above under the caption “—Liens”;

	(2) the gross proceeds of that sale and leaseback transaction are at least equal to the fair market value of the property that is subject of that sale and leaseback transaction, as determined in good faith by a senior financial officer of NRG; and

	(3) if such sale and leaseback transaction constitutes an Asset Sale, the transfer of assets in that sale and leaseback transaction is permitted by, and NRG applies the proceeds of such transaction in compliance with, the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales.”


	*Dividend and Other Payment Restrictions Affecting Subsidiaries*

NRG will not, and will not permit any of its Restricted Subsidiaries (other than Excluded Subsidiaries) to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiaries (other than Excluded Subsidiaries) to:


	(1) pay dividends or make any other distributions on its Capital Stock to NRG or any of its Restricted Subsidiaries (other than Excluded Subsidiaries), or with respect to any other interest or

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	participation in, or measured by, its profits, or pay any indebtedness owed to NRG or any of its Restricted Subsidiaries (other than Excluded Subsidiaries);

	(2) make loans or advances to NRG or any of its Restricted Subsidiaries (other than Excluded Subsidiaries); or

	(3) transfer any of its properties or assets to NRG or any of its Restricted Subsidiaries (other than Excluded Subsidiaries).

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:


	(1) agreements governing Existing Indebtedness, on the date of the supplemental indentures, and the Credit Agreement, on the date of the Acquisition;

	(2) the indentures, the notes, the security documents and the Subsidiary Guarantees (including the exchange notes and related Subsidiary Guarantees);

	(3) applicable law, rule, regulation or order;

	(4) customary non-assignment provisions in contracts, agreements, leases, permits and licenses;

	(5) purchase money obligations for property acquired and Capital Lease Obligations that impose restrictions on the property purchased or leased of the nature described in clause (3) of the preceding paragraph;

	(6) any agreement for the sale or other disposition of the stock or assets of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending the sale or other disposition;

	(7) Permitted Refinancing Indebtedness; provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

	(8) Liens permitted to be incurred under the provisions of the covenant described above under the caption “—Liens” and associated agreements that limit the right of the debtor to dispose of the assets subject to such Liens;

	(9) provisions limiting the disposition or distribution of assets or property in joint venture, partnership, membership, stockholder and limited liability company agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements and other similar agreements, including owners’, participation or similar agreements governing projects owned through an undivided interest, which limitation is applicable only to the assets that are the subject of such agreements;

	(10) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in connection with a Permitted Business;

	(11) restrictions or conditions contained in any trading, netting, operating, construction, service, supply, purchase, sale or similar agreement to which NRG or any Restricted Subsidiary of NRG is a party entered into in connection with a Permitted Business; provided that such agreement prohibits the encumbrance of solely the property or assets of NRG or such Restricted Subsidiary that are the subject of that agreement, the payment rights arising thereunder and/or the proceeds thereof and not to any other asset or property of NRG or such Restricted Subsidiary or the assets or property of any other Restricted Subsidiary;

	(12) any instrument governing Indebtedness or Capital Stock of a Person acquired by NRG or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired; provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the applicable indenture to be incurred;

	(13) Indebtedness of a Restricted Subsidiary of NRG existing at the time it became a Restricted Subsidiary if such restriction was not created in connection with or in anticipation of the transaction or series of transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was acquired by NRG;

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	(14) with respect to clause (3) of the first paragraph of this covenant only, restrictions encumbering property at the time such property was acquired by NRG or any of its Restricted Subsidiaries, so long as such restriction relates solely to the property so acquired and was not created in connection with or in anticipation of such acquisition;

	(15) provisions limiting the disposition or distribution of assets or property in agreements governing Non-Recourse Debt, which limitation is applicable only to the assets that are the subject of such agreements; and

	(16) any encumbrance or restrictions of the type referred to in clauses (1), (2) and (3) of the first paragraph of this covenant imposed by any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of the contracts, instruments or obligations referred to in clauses (1) through (15) above; provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are, in the good faith judgment of a senior financial officer of NRG, no more restrictive with respect to such dividend and other payment restrictions than those contained in the dividend or other payment restrictions prior to such amendment, modification, restatement, renewals, increase, supplement, refunding, replacement or refinancing.


	*Merger, Consolidation or Sale of Assets*

NRG may not, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not NRG is the surviving corporation); or (2) sell, assign, transfer, convey or otherwise dispose of all or substantially all of the properties or assets of NRG and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person; unless:


	(1) either: (a) NRG is the surviving corporation; or (b) the Person formed by or surviving any such consolidation or merger (if other than NRG) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a corporation, partnership or limited liability company organized or existing under the laws of the United States, any state of the United States or the District of Columbia; provided that if the Person is a partnership or limited liability company, then a corporation wholly-owned by such Person organized or existing under the laws of the United States, any state of the United States or the District of Columbia that does not and will not have any material assets or operations shall become a co-issuer of each series of notes pursuant to supplemental indentures duly executed by the applicable trustee;

	(2) the Person formed by or surviving any such consolidation or merger (if other than NRG) or the Person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all the obligations of NRG under the notes and the indentures pursuant to supplemental indentures or other documents and agreements reasonably satisfactory to the trustee;

	(3) immediately after such transaction, no Default or Event of Default exists; and

	(4) (i) NRG or the Person formed by or surviving any such consolidation or merger (if other than NRG), or to which such sale, assignment, transfer, conveyance or other disposition has been made will, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock” or (ii) NRG’s Fixed Charge Coverage Ratio is greater after giving pro forma effect to such consolidation or merger and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period than NRG’s actual Fixed Charge Coverage Ratio for the period.

In addition, NRG may not, directly or indirectly, lease all or substantially all of its properties or assets, in one or more related transactions, to any other Person.

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This “Merger, Consolidation or Sale of Assets” covenant will not apply to:


	(1) a merger of NRG with an Affiliate solely for the purpose of reincorporating NRG in another jurisdiction or forming a direct holding company of NRG; and

	(2) any sale, transfer, assignment, conveyance, lease or other disposition of assets between or among NRG and its Restricted Subsidiaries, including by way of merger or consolidation.


	*Transactions with Affiliates*

NRG will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of NRG (each, an “Affiliate Transaction”) involving aggregate payments in excess of $10.0 million, unless:


	(1) the Affiliate Transaction is on terms that are no less favorable to NRG (as reasonably determined by NRG) or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by NRG or such Restricted Subsidiary with an unrelated Person; and

	(2) NRG delivers to the trustee:


	(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $50.0 million, a resolution of the Board of Directors set forth in an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors; and

	(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $100.0 million, an opinion as to the fairness to NRG or such Restricted Subsidiary of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:


	(1) any employment agreement or director’s engagement agreement, employee benefit plan, officer and director indemnification agreement or any similar arrangement entered into by NRG or any of its Restricted Subsidiaries or approved by the Board of Directors of NRG in good faith;

	(2) transactions between or among NRG and/or its Restricted Subsidiaries;

	(3) transactions with a Person (other than an Unrestricted Subsidiary of NRG) that is an Affiliate of NRG solely because NRG owns, directly or through a Restricted Subsidiary, an Equity Interest in, or controls, such Person;

	(4) payment of directors’ fees;

	(5) any issuance of Equity Interests (other than Disqualified Stock) of NRG or its Restricted Subsidiaries;

	(6) Restricted Payments that do not violate the provisions of the applicable indenture described above under the caption “—Restricted Payments”;

	(7) any agreement in effect as of the date of the supplemental indentures or any amendment thereto or replacement thereof and any transaction contemplated thereby or permitted thereunder, so long as any such amendment or replacement agreement taken as a whole is not more disadvantageous to the Holders than the original agreement as in effect on the date of the supplemental indentures;

	(8) payments or advances to employees or consultants that are incurred in the ordinary course of business or that are approved by the Board of Directors of NRG in good faith;

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	(9) the existence of, or the performance by NRG or any of its Restricted Subsidiaries of its obligations under the terms of, any stockholders agreement (including any registration rights agreement or purchase agreement related thereto) to which it is a party as of the date of the supplemental indentures and any similar agreements which it may enter into thereafter; provided, however, that the existence of, or the performance by NRG or any of its Restricted Subsidiaries of obligations under, any future amendment to any such existing agreement or under any similar agreement entered into after the date of the supplemental indentures shall only be permitted by this clause (9) to the extent that the terms of any such amendment or new agreement are not otherwise more disadvantageous to the holders of the notes in any material respect;

	(10) transactions permitted by, and complying with, the provisions of the covenant described under “—Merger, Consolidation or Sale of Assets”;

	(11) transactions with customers, clients, suppliers, joint venture partners or purchasers or sellers of goods or services (including pursuant to joint venture agreements) otherwise in compliance with the terms of the applicable indenture that are fair to NRG and its Restricted Subsidiaries, in the reasonable determination of a senior financial officer of NRG, or are on terms not materially less favorable taken as a whole as might reasonably have been obtained at such time from an unaffiliated party;

	(12) any repurchase, redemption or other retirement of Capital Stock of NRG held by employees of NRG or any of its Subsidiaries;

	(13) loans or advances to employees or consultants;

	(14) the transactions contemplated by the Acquisition Agreement and the payment of all fees and expenses related thereto;

	(15) any Permitted Investment in another Person involved in a Permitted Business;

	(16) transactions in which NRG or any Restricted Subsidiary of NRG, as the case may be, delivers to the trustee a letter from an Independent Financial Advisor stating that such transaction is fair to NRG or such Restricted Subsidiary from a financial point of view or meets the requirements of clause (1) of the preceding paragraph;

	(17) the guarantee of Permitted Itiquira Indebtedness; and

	(18) any agreement to do any of the foregoing.


	*Additional Subsidiary Guarantees*

If,


	•	NRG or any of its Restricted Subsidiaries acquires or creates another Domestic Subsidiary (other than an Excluded Subsidiary or a Domestic Subsidiary that does not Guarantee any other Indebtedness of NRG) after the date of the supplemental indentures,

	•	any Excluded Subsidiary that is a Domestic Subsidiary ceases to be an Excluded Subsidiary after the date of the supplemental indentures, or

	•	any Domestic Subsidiary that does not Guarantee any other Indebtedness of NRG subsequently Guarantees other Indebtedness of NRG,

then such newly acquired or created Subsidiary, former Excluded Subsidiary, or Domestic Subsidiary, as the case may be, will become a Guarantor and execute a supplemental indenture and deliver an opinion of counsel satisfactory to the trustee within 30 business days of the date on which it was acquired or created or ceased to be an Excluded Subsidiary or Guaranteed other Indebtedness of NRG, as the case may be.

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	*Designation of Restricted, Unrestricted and Excluded Project Subsidiaries*

The Board of Directors may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate fair market value of all outstanding Investments owned by NRG and its Restricted Subsidiaries in the Subsidiary designated as Unrestricted will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption “—Restricted Payments” or under one or more clauses of the definition of Permitted Investments, as determined by NRG. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. The Board of Directors may redesignate any Unrestricted Subsidiary to be a Restricted Subsidiary if that redesignation would not cause a Default.

The Board of Directors may designate any Restricted Subsidiary to be an Excluded Project Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary that is not an Excluded Project Subsidiary is designated as an Excluded Project Subsidiary, the aggregate fair market value of all outstanding Investments owned by NRG and its Restricted Subsidiaries in the Subsidiary designated as an Excluded Project Subsidiary will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption “—Restricted Payments” or under one or more clauses of the definition of Permitted Investments, as determined by NRG. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Excluded Project Subsidiary. The Board of Directors may redesignate any Excluded Project Subsidiary to be a Restricted Subsidiary that is not an Excluded Project Subsidiary if that redesignation would not cause a Default.


	*Payments for Consent*

NRG will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, pay or cause to be paid any consideration to or for the benefit of any holder of any series of notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture governing such notes or such notes unless such consideration is offered to be paid and is paid to all holders of such notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or agreement.


	*New York Public Service Law*

NRG will use commercially reasonable efforts to obtain an order, on or before the date that is 364 days after the date of the supplemental indentures, from the New York Public Service Commission permitting each Subsidiary Guarantee issued on the date of the supplemental indentures that is subject Section 69 of the New York Public Service Law to remain outstanding after such 364th day.

Reports

Whether or not required by the Commission’s rules and regulations, so long as any notes are outstanding, NRG will furnish to the holders of notes or cause the trustee to furnish to the holders of notes, within the time periods (including any extensions thereof) specified in the Commission’s rules and regulations:


	(1) all quarterly and annual reports that would be required to be filed with the Commission on Forms 10-Q and 10-K if NRG were required to file such reports; and

	(2) all current reports that would be required to be filed with the Commission on Form 8-K if NRG were required to file such reports.

All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on NRG’s consolidated financial statements by NRG’s independent registered public accounting firm. In addition, NRG will file a copy of each of the reports referred to in clauses (1) and (2) above with the Commission for public

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availability within the time periods specified in the rules and regulations applicable to such reports (unless the Commission will not accept such a filing). To the extent such filings are made, the reports will be deemed to be furnished to the trustee and holders of notes.

If NRG is no longer subject to the periodic reporting requirements of the Exchange Act for any reason, NRG will nevertheless continue filing the reports specified in the preceding paragraph with the Commission within the time periods specified above unless the Commission will not accept such a filing. NRG agrees that it will not take any action for the purpose of causing the Commission not to accept any such filings. If, notwithstanding the foregoing, the Commission will not accept NRG’s filings for any reason, NRG will post the reports referred to in the preceding paragraph on its website within the time periods that would apply if NRG were required to file those reports with the Commission.

In addition, NRG and the Guarantors agree that, for so long as any notes remain outstanding, at any time they are not required to file the reports required by the preceding paragraphs with the Commission, they will furnish to the holders and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Events of Default and Remedies

Each of the following is an Event of Default with respect to each series of notes:


	(1) default for 30 days in the payment when due of interest on such notes;

	(2) default in payment when due of the principal of, or premium, if any, on such notes;

	(3) failure by NRG or any of its Restricted Subsidiaries for 30 days after written notice given by the trustees or holders, to comply with any of the other agreements in the indenture governing such notes;

	(4) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by NRG or any of its Restricted Subsidiaries (or the payment of which is guaranteed by NRG or any of its Restricted Subsidiaries) whether such Indebtedness or guarantee now exists, or is created after the date of the supplemental indentures, if that default:


	(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”); or

	(b) results in the acceleration of such Indebtedness prior to its express maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $100.0 million or more; provided that this clause (4) shall not apply to (i) secured Indebtedness that becomes due as a result of the voluntary sale or transfer of the property or assets securing such Indebtedness to a Person that is not an Affiliate of NRG; (ii) Non-Recourse Debt of NRG Peaker Finance Company LLC; and (iii) Non-Recourse Debt of NRG or any of its Subsidiaries (except to the extent that NRG or any of its Restricted Subsidiaries that are not parties to such Non-Recourse Debt becomes directly or indirectly liable, including pursuant to any contingent obligation, for any Indebtedness thereunder and such liability, individually or in the aggregate, exceeds $100.0 million);


	(5) one or more judgments for the payment of money in an aggregate amount in excess of $100.0 million (excluding therefrom any amount reasonably expected to be covered by insurance) shall be rendered against NRG any Restricted Subsidiary or any combination thereof and the same shall not have been paid, discharged or stayed for a period of 60 days after such judgment became final and non-appealable;

	(6) failure by NRG to comply with any material term of the escrow and security agreement that is not cured within 10 days;

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	(7) the escrow and security agreement or any other security document or any Lien purported to be granted thereby on the escrow account or the cash or Government Securities therein is held in any judicial proceeding to be unenforceable or invalid, in whole or in part, or ceases for any reason (other than pursuant to a release that is delivered or becomes effective as set forth in the indenture governing such notes) to be fully enforceable and perfected;

	(8) except as permitted by the indenture governing such notes, any Subsidiary Guarantee shall be held in any final and non-appealable judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any Guarantor (or any group of Guarantors) that constitutes a Significant Subsidiary, or any Person acting on behalf of any Guarantor (or any group of Guarantors) that constitutes a Significant Subsidiary, shall deny or disaffirm its or their obligations under its or their Subsidiary Guarantee(s); and

	(9) certain events of bankruptcy or insolvency described in the indenture governing such notes with respect to NRG or any of its Restricted Subsidiaries (other than the Exempt Subsidiaries) that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

In the case of an Event of Default with respect to any series of notes arising from certain events of bankruptcy or insolvency, with respect to NRG, any Restricted Subsidiary (other than the Exempt Subsidiaries) that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all of such notes that are outstanding will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of such notes that are outstanding may declare all such notes to be due and payable immediately.

Subject to certain limitations, holders of a majority in principal amount of the notes of any series that are then outstanding may direct the trustee for such notes in its exercise of any trust or power. The trustee for any series of notes may withhold from holders of such notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal or interest.

Subject to the provisions of the indenture for any series of notes relating to the duties of the applicable trustee, in case an Event of Default occurs and is continuing under such indenture, the applicable trustee for such notes will be under no obligation to exercise any of the rights or powers under such indenture at the request or direction of any holders of such notes unless such holders have offered to such trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium (if any) or interest when due, no holder of a note of any series may pursue any remedy with respect to the indenture governing such series of notes or such notes unless:


	(1) such holder has previously given the trustee for such series notice that an Event of Default is continuing;

	(2) holders of at least 25% in aggregate principal amount of the notes of such series that are then outstanding have requested the trustee to pursue the remedy;

	(3) such holders have offered such trustee reasonable security or indemnity against any loss, liability or expense;

	(4) such trustee has not complied with such request within 60 days after the receipt thereof and the offer of security or indemnity; and

	(5) holders of a majority in aggregate principal amount of such notes that are then outstanding have not given such trustee a direction inconsistent with such request within such 60-day period.

The holders of a majority in aggregate principal amount of the notes of any series then outstanding by notice to the trustee for such series of notes may, on behalf of the holders of all of such notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under such indenture for

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such series except a continuing Default or Event of Default in the payment of interest on, or the principal of, such notes.

NRG is required to deliver to the trustee annually a statement regarding compliance with the indentures. Upon becoming aware of any Default or Event of Default, NRG is required to deliver to the trustee for each series of notes a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder of NRG or any Guarantor, as such, will have any liability for any obligations of NRG or the Guarantors under the notes, the indentures, the Subsidiary Guarantees, or the escrow and security agreement, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Legal Defeasance and Covenant Defeasance

NRG may, at its option and at any time, elect to have all of its obligations discharged with respect to notes of any series that are outstanding and all obligations of the Guarantors of such notes discharged with respect to their Subsidiary Guarantees (“Legal Defeasance”) except for:


	(1) the rights of holders of such notes that are then outstanding to receive payments in respect of the principal of, or interest or premium on such notes when such payments are due from the trust referred to below;

	(2) NRG’s obligations with respect to such notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

	(3) the rights, powers, trusts, duties and immunities of the trustee for such notes, and NRG’s and the Guarantors’ obligations in connection therewith; and

	(4) the Legal Defeasance provisions of the indenture for such notes.

In addition, NRG may, at its option and at any time, elect to have the obligations of NRG and the Guarantors released with respect to certain covenants (including its obligation to make Change of Control Offers and Asset Sale Offers) that are described in the indenture governing a series of notes (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to such notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, receivership, rehabilitation and insolvency events) described under “—Events of Default and Remedies” will no longer constitute an Event of Default with respect to such notes.

In order to exercise either Legal Defeasance or Covenant Defeasance:


	(1) NRG must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the notes subject to Legal Defeasance or Covenant Defeasance, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants to pay the principal of, or interest and premium on such notes that are then outstanding on the Stated Maturity or on the applicable redemption date, as the case may be, and NRG must specify whether such notes are being defeased to maturity or to a particular redemption date;

	(2) in the case of Legal Defeasance, NRG has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee for the applicable series of notes confirming that (a) NRG has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the date of the supplemental indentures, there has been a change in the applicable federal income tax law, in

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	either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of such notes that are then outstanding will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

	(3) in the case of Covenant Defeasance, NRG has delivered to the trustee for the applicable series of notes an opinion of counsel reasonably acceptable to the trustee confirming that the holders of such notes that are then outstanding will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

	(4) no Default or Event of Default with respect to such series of notes has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit);

	(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under any material agreement or instrument (other than the indenture governing such notes) to which NRG or any of its Subsidiaries is a party or by which NRG or any of its Subsidiaries is bound;

	(6) NRG must deliver to the trustee for the applicable series of notes an officers’ certificate stating that the deposit was not made by NRG with the intent of preferring the holders of notes over the other creditors of NRG with the intent of defeating, hindering, delaying or defrauding creditors of NRG or others; and

	(7) NRG must deliver to the trustee for the applicable series of notes an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Amendment, Supplement and Waiver

Except as provided in the next two succeeding paragraphs, the indenture governing any series of notes or the notes outstanding thereunder may be amended or supplemented with the consent of the holders of at least a majority in principal amount of such notes then outstanding under that indenture (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, such notes), and any existing default or compliance with any provision of such indenture or the notes outstanding thereunder may be waived with the consent of the holders of a majority in principal amount of the notes that are then outstanding under that indenture (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, such notes).

Without the consent of each holder of a series of notes affected, an amendment or waiver may not (with respect to any such notes held by a non-consenting holder):


	(1) reduce the principal amount of such notes whose holders must consent to an amendment, supplement or waiver;

	(2) reduce the principal of or change the fixed maturity of any such note or alter the provisions with respect to the redemption of such notes (other than provisions relating to the covenants described above under the caption “—Repurchase at the Option of Holders”);

	(3) reduce the rate of or change the time for payment of interest on any such note;

	(4) waive a Default or Event of Default in the payment of principal of, or interest or premium on such notes (except a rescission of acceleration of such notes by the holders of at least a majority in aggregate principal amount of such notes and a waiver of the payment default that resulted from such acceleration);

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	(5) make any such note payable in currency other than that stated in such notes;

	(6) make any change in the provisions of the indenture governing such notes relating to waivers of past Defaults or the rights of holders of such notes to receive payments of principal of, or interest or premium on such notes;

	(7) waive a redemption payment with respect to any such note (other than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders”);

	(8) amend or waive any term of the escrow and security agreements; or

	(9) make any change in the preceding amendment and waiver provisions.

Notwithstanding the preceding, without the consent of any holder of notes, NRG, the Guarantors and the trustee may amend or supplement any indenture or the notes:


	(1) to cure any ambiguity, defect or inconsistency;

	(2) to provide for uncertificated notes in addition to or in place of certificated notes;

	(3) to provide for the assumption of NRG’s obligations to holders of notes in the case of a merger or consolidation or sale of all or substantially all of NRG’s assets;

	(4) to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under any indenture of any such holder;

	(5) to comply with requirements of the Commission in order to effect or maintain the qualification of any indenture under the Trust Indenture Act;

	(6) to conform the text of any indenture or the notes to any provision of this Description of Notes to the extent that such provision in this Description of Notes was intended to be a verbatim recitation of a provision of that indenture or the notes outstanding thereunder;

	(7) to evidence and provide for the acceptance and appointment under any indenture of a successor trustee pursuant to the requirements thereof;

	(8) to provide for the issuance of additional notes in accordance with the limitations set forth in the indentures as of the date hereof; or

	(9) to allow any Guarantor to execute a supplemental indenture and/or a Subsidiary Guarantee with respect to the notes.

Satisfaction and Discharge

The indenture for any series of notes will be discharged and will cease to be of further effect as to all notes issued thereunder, when:


	(1) either:


	(a) all such notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to NRG, have been delivered to the trustee for such notes for cancellation; or

	(b) all such notes that have not been delivered to the trustee for such notes for cancellation have become due and payable by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year and NRG or any Guarantor has irrevocably deposited or caused to be deposited with the trustee for such notes as trust funds in trust solely for the benefit of the holders of such notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on such notes not delivered to the trustee for cancellation for principal, premium and accrued interest to the date of maturity or redemption;

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	(2) no Default or Event of Default under such indenture has occurred and is continuing on the date of the deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which NRG or any Guarantor is a party or by which NRG or any Guarantor is bound;

	(3) NRG or any Guarantor has paid or caused to be paid all sums payable by it under such indenture; and

	(4) NRG has delivered irrevocable instructions to the trustee under such indenture to apply the deposited money toward the payment of such notes at maturity or the redemption date, as the case may be.

In addition, NRG must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Concerning the Trustee

If the trustee becomes a creditor of NRG or any Guarantor, the indentures limit its right to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the Commission for permission to continue (if such indenture has been qualified under the Trust Indenture Act) or resign.

The holders of a majority in principal amount of the notes of each series that are outstanding will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee for such series, subject to certain exceptions. The indentures provide that in case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indentures at the request of any holder of notes, unless such holder has offered to the trustee security and indemnity satisfactory to it against any loss, liability or expense.

Certain Definitions

Set forth below are certain defined terms used in the indentures. Reference is made to the indentures for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

“Acquired Debt” means, with respect to any specified Person:


	(1) Indebtedness of any other Person or asset existing at the time such other Person or asset is merged with or into, is acquired by, or became a Subsidiary of such specified Person, as the case may be, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and

	(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

“Acquisition” means the acquisition of all of the outstanding Equity Interests of Texas Genco LLC by NRG pursuant to the Acquisition Agreement, among Texas Genco LLC, NRG, and the direct and indirect owners of Texas Genco LLC party thereto, dated as of September 30, 2005.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; provided that beneficial ownership of 10% or more of the Voting

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Stock of a Person will be deemed to be control. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

“Applicable Law” shall mean, as to any Person, any ordinance, law, treaty, rule or regulation or determination by an arbitrator or a court or other Governmental Authority, including ERCOT, in each case, applicable to or binding on such Person or any of its property or assets or to which such Person or any of its property is subject.

“Applicable Premium” means, (a) with respect to any 2014 fixed rate note on any redemption date, the greater of:


	(1) 1.0% of the principal amount of such note; or

	(2) the excess of:


	(A) the present value at such redemption date of (i) the redemption price of such note at February 1, 2010, (such redemption price being set forth in the table appearing above under the caption “—Optional Redemption”) plus (ii) all required interest payments due on the note through February 1, 2010 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

	(B) the principal amount of the note, if greater; and


	(b) with respect to any 2016 note on any redemption date, the greater of:


	(1) 1.0% of the principal amount of such note; or

	(2) the excess of:


	(A) the present value at such redemption date of (i) the redemption price of such note at February 1, 2011, (such redemption price being set forth in the table appearing above under the caption “—Optional Redemption”) plus (ii) all required interest payments due on the note through February 1, 2011 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

	(B) the principal amount of the note, if greater.

“Asset Sale” means:


	(1) the sale, lease, conveyance or other disposition of any assets or rights; provided that the sale, conveyance or other disposition of all or substantially all of the assets of NRG and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indentures described above under the caption “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant; and

	(2) the issuance of Equity Interests in any of NRG’s Restricted Subsidiaries or the sale of Equity Interests in any of its Subsidiaries.

Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:


	(1) any single transaction or series of related transactions for which NRG or its Restricted Subsidiaries receive aggregate consideration of less than $50.0 million;

	(2) a transfer of assets or Equity Interests between or among NRG and its Restricted Subsidiaries;

	(3) an issuance of Equity Interests by a Restricted Subsidiary of NRG to NRG or to a Restricted Subsidiary of NRG;

	(4) the sale or lease of products or services and any sale or other disposition of damaged, worn-out or obsolete assets;

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	(5) the sale or discount, in each case without recourse, of accounts receivable, but only in connection with the compromise or collection thereof;

	(6) the licensing of intellectual property;

	(7) the sale, lease, conveyance or other disposition for value of energy, fuel or emission credits or contracts for any of the foregoing;

	(8) the sale or other disposition of cash or Cash Equivalents;

	(9) a Restricted Payment that does not violate the covenant described above under the caption “—Certain Covenants—Restricted Payments” or a Permitted Investment;

	(10) to the extent allowable under Section 1031 of the Internal Revenue Code of 1986, any exchange of like property (excluding any “boot” thereon) for use in a Permitted Business; and

	(11) a disposition of assets in connection with a foreclosure, transfer or deed in lieu of foreclosure or other exercise of remedial action.

“Asset Sale Offer” has the meaning assigned to that term in the indentures governing the notes.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP; provided, however, that if such sale and leaseback transaction results in a Capital Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capital Lease Obligation.”

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.

“Board of Directors” means:


	(1) with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;

	(2) with respect to a partnership, the Board of Directors of the general partner of the partnership;

	(3) with respect to a limited liability company, the managing member or members or any controlling committee of managing members thereof; and

	(4) with respect to any other Person, the board or committee of such Person serving a similar function.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty.

“Capital Stock” means:


	(1) in the case of a corporation, corporate stock;

	(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

	(3) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and

	(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the

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	foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.

“Cash Equivalents” means:


	(1) United States dollars, Euros or, in the case of any Foreign Subsidiary, any local currencies held by it from time to time;

	(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than twelve months from the date of acquisition;

	(3) certificates of deposit and eurodollar time deposits with maturities of twelve months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding 12 months and overnight bank deposits, in each case, with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of “B” or better;

	(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

	(5) commercial paper having one of the two highest ratings obtainable from Moody’s Investors Service, Inc. or Standard & Poor’s Rating Services and in each case maturing within 12 months after the date of acquisition;

	(6) readily marketable direct obligations issued by any state of the United States or any political subdivision thereof, in either case having one of the two highest rating categories obtainable from either Moody’s or S&P; and

	(7) money market funds that invest primarily in securities described in clauses (1) through (6) of this definition.

“Change of Control” means the occurrence of any of the following:


	(1) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of NRG and its Subsidiaries taken as a whole to any “person” (as that term is used in Section 13(d) of the Exchange Act, but excluding any employee benefit plan of NRG or any of its Restricted Subsidiaries, and any person or entity acting in its capacity as trustee, agent or other fiduciary or administrator of such plan);

	(2) the adoption of a plan relating to the liquidation or dissolution of NRG;

	(3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” (as defined above) becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of NRG, measured by voting power rather than number of shares; or

	(4) the first day on which a majority of the members of the Board of Directors of NRG are not Continuing Directors.

“Change of Control Offer” has the meaning assigned to it in the indentures governing the notes.

“Concurrent Cash Distributions” has the meaning assigned to it in the definition of “Investments.”

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus, without duplication:


	(1) an amount equal to any extraordinary loss (including any loss on the extinguishment or conversion of Indebtedness) plus any net loss realized by such Person or any of its Restricted Subsidiaries

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	in connection with an Asset Sale (without giving effect of the threshold provided in the definition thereof), to the extent such losses were deducted in computing such Consolidated Net Income; plus

	(2) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus

	(3) the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income; plus

	(4) any expenses or charges related to any equity offering, Permitted Investment, acquisition, disposition, recapitalization or Indebtedness permitted to be incurred by the indenture including a refinancing thereof (whether or not successful), including such fees, expenses or charges related to the offering of the notes and the Credit Agreement, and deducted in computing Consolidated Net Income; plus

	(5) any professional and underwriting fees related to any equity offering, Permitted Investment, acquisition, recapitalization or Indebtedness permitted to be incurred under the indenture and, in each case, deducted in such period in computing Consolidated Net Income; plus

	(6) the amount of any minority interest expense deducted in calculating Consolidated Net Income (less the amount of any cash dividends paid to the holders of such minority interests); plus

	(7) any non cash gain or loss attributable to Mark to Market Adjustments in connection with Hedging Obligations; plus

	(8) without duplication, any writeoffs, writedowns or other non-cash charges reducing Consolidated Net Income for such period, excluding any such charge that represents an accrual or reserve for a cash expenditure for a future period, plus

	(9) all items classified as extraordinary, unusual or nonrecurring non-cash losses or charges (including, without limitation, severance, relocation and other restructuring costs), and related tax effects according to GAAP to the extent such non-cash charges or losses were deducted in computing such Consolidated Net Income; plus

	(10) depreciation, depletion, amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period) and other non-cash charges and expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion, amortization and other non-cash expenses were deducted in computing such Consolidated Net Income; minus

	(11) non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business; in each case, on a consolidated basis and determined in accordance with GAAP (including, without limitation, any increase in amortization or depreciation or other non-cash charges resulting from the application of purchase accounting in relation to the Acquisition or any acquisition that is consummated after the date of the supplemental indenture); minus

	(12) interest income for such period;

provided, however, that Consolidated Cash Flow of NRG will exclude the Consolidated Cash Flow attributable to Excluded Subsidiaries to the extent that the declaration or payment of dividends or similar distributions by the Excluded Subsidiary of that Consolidated Cash Flow is not, as a result of an Excluded Subsidiary Debt Default, then permitted by operation of the terms of the relevant Excluded Subsidiary Debt Agreement; provided that the Consolidated Cash Flow of the Excluded Subsidiary will only be so excluded for that portion of the period during which the condition described in the preceding proviso has occurred and is continuing.

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“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:


	(1) the Net Income of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included only to the extent of the amount of dividends or similar distributions (including pursuant to other intercompany payments but excluding Concurrent Cash Distributions) paid in cash to the specified Person or a Restricted Subsidiary of the Person;

	(2) for purposes of the covenant described above under the caption “—Restricted Payments” only, the Net Income of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders;

	(3) the cumulative effect of a change in accounting principles will be excluded;

	(4) any net after-tax non-recurring or unusual gains, losses (less all fees and expenses relating thereto) or other charges or revenue or expenses (including, without limitation, relating to severance, relocation, one-time compensation charges and the Acquisition) shall be excluded;

	(5) any non-cash compensation expense recorded from grants of stock appreciation or similar rights, stock options, restricted stock or other rights to officers, directors or employees shall be excluded, whether under FASB 123R or otherwise;

	(6) any net after-tax income (loss) from disposed or discontinued operations and any net after-tax gains or losses on disposal of disposed or discontinued operations shall be excluded;

	(7) any gains or losses (less all fees and expenses relating thereto) attributable to asset dispositions shall be excluded;

	(8) any impairment charge or asset write-off pursuant to Financial Accounting Statement No. 142 and No. 144 or any successor pronouncement shall be excluded; and

	(9) any accruals or reserves or other charges related to the Acquisition and the Related Financing Transactions incurred on or before January 1, 2007, shall be excluded.

“Continuing Director” means, as of any date of determination, any member of the Board of Directors of NRG who:


	(1) was a member of such Board of Directors on the date of the supplemental indentures; or

	(2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election.

“Credit Agreement” means the Credit and Guaranty Agreement, described in this prospectus supplement under the heading “Description of Other Indebtedness and Preferred Stock—New Senior Secured Credit Facility,” to be dated the date of the Acquisition, among NRG, the lenders from time to time party hereto, Morgan Stanley Senior Funding, Inc. and Citigroup Global Markets Inc., as joint lead book runners, joint lead arrangers and as co-documentation agents, Morgan Stanley Senior Funding, Inc., as administrative agent and as collateral agent, and Citigroup Global Markets Inc., as syndication agent, providing for up to $5,300,000,000 of credit facilities.

“Credit Facilities” means (i) one or more debt facilities (including, without limitation, the Credit Agreement) or commercial paper facilities, in each case with banks or other institutional lenders providing for revolving credit loans, term loans, credit-linked deposits (or similar deposits) receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such

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lenders against such receivables) or letters of credit and (ii) debt securities sold to institutional investors, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.

“Designated Noncash Consideration” means the fair market value of non-cash consideration received by NRG or a Guarantor in connection with an Asset Sale that is so designated as Designated Noncash Consideration pursuant to an officers’ certificate, setting forth the basis of such valuation, executed by a senior financial officer of NRG, less the amount of cash or Cash Equivalents received in connection with a subsequent sale of such Designated Noncash Consideration.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Determination Date” means, with respect to an Interest Period, the second London Banking Day preceding the first day of such Interest Period.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require NRG to repurchase such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that NRG may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The amount of Disqualified Stock deemed to be outstanding at any time for purposes of the indentures will be the maximum amount that NRG and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.

“Domestic Subsidiary” means any Restricted Subsidiary of NRG that was formed under the laws of the United States or any state of the United States or the District of Columbia or that guarantees or otherwise provides direct credit support for any Indebtedness of NRG.

“Environmental CapEx Debt” shall mean Indebtedness of NRG or its Restricted Subsidiaries incurred for the purpose of financing Environmental Capital Expenditures.

“Environmental Capital Expenditures” shall mean capital expenditures deemed necessary by NRG or its Restricted Subsidiaries to comply with Environmental Laws.

“Environmental Law” shall mean any applicable Federal, state, foreign or local statute, law, rule, regulation, ordinance, code and rule of common law now or hereafter in effect and in each case as amended, and any binding judicial or administrative interpretation thereof, including any binding judicial or administrative order, consent decree or judgment, relating to the environment, human health or safety or Hazardous Materials.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means a sale of Capital Stock (other than Disqualified Stock) of NRG pursuant to (1) a public offering or (2) a private placement to Persons who are not Affiliates of NRG.

“ERCOT” means the Electric Reliability Council of Texas.

“Excluded Foreign Subsidiary” means, at any time, any Foreign Subsidiary that is (or is treated as) for United States federal income tax purposes either (1) a corporation or (2) a pass-through entity owned directly or indirectly by another Foreign Subsidiary that is (or is treated as) a corporation; provided that notwithstanding the foregoing, the following entities will be deemed to be “Excluded Foreign Subsidiaries”:

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Sterling Luxembourg (No. 4) S.a.r.l., Tosli Acquisition BV, NRGenerating Luxembourg (No. 6) S.a.r.l., NRG Pacific Corporate Services Pty Ltd., NRGenerating III (Gibraltar), NRGenerating IV (Gibraltar), NRGenerating Holdings (No. 21) B.V., Tosli Acquisition B.V., Flinders Power Finance Pty Ltd. and any subsidiary of Tosli Acquisition BV incorporated or formed in connection with the Itiquira Refinancing.

“Excluded Proceeds” means any Net Proceeds of an Asset Sale involving the sale of up to $300,000,000 in the aggregate received from one or more Asset Sales of Equity Interests in, or property or assets of, any Foreign Subsidiaries or any Foreign Subsidiary Holding Company.

“Excluded Project Subsidiary” shall mean, at any time,


	(a) each Subsidiary of NRG that is an obligor or otherwise bound with respect to Non-Recourse Debt on the date of the supplemental indenture,

	(b) any Person that becomes a Subsidiary of NRG after the date of the supplemental indenture that is an obligor or otherwise bound solely with respect to Non-Recourse Debt, and

	(c) any Subsidiary of NRG that is designated by NRG’s Board of Directors as an Excluded Project Subsidiary pursuant to a Board Resolution,

in each case, in accordance with the other provisions of the indenture and if and for so long as the provision of a full and unconditional guarantee by such subsidiary of the notes will constitute or result in a breach, termination or default under the agreement or instrument governing the applicable Non-Recourse Debt of such subsidiary; provided that such subsidiary shall be an Excluded Project Subsidiary only to the extent that and for so long as the requirements and consequences above shall exist.

“Excluded Subsidiaries” means the Excluded Project Subsidiaries, the Excluded Foreign Subsidiaries and the Immaterial Subsidiaries.

“Excluded Subsidiary Debt Agreement” means the agreement or documents governing the relevant Indebtedness referred to in the definition of “Excluded Subsidiary Debt Default.”

“Excluded Subsidiary Debt Default” means, with respect to any Excluded Subsidiary, the failure of such Excluded Subsidiary to pay any principal or interest or other amounts due in respect of any Indebtedness, when and as the same shall become due and payable, or the occurrence of any other event or condition that results in any Indebtedness of such Excluded Subsidiary becoming due prior to its scheduled maturity or that enables or permits (with or without the giving of notice, lapse of time or both) the holder or holders of such Indebtedness or any trustee or agent on its or their behalf to cause such Indebtedness to become due, or to require the prepayment, repurchase, redemption or defeasance thereof, prior to its scheduled maturity.

“Exempt Subsidiaries” means, collectively, NRG Ilion LP LLC, NRG Ilion Limited Partnership, Meriden Gas Turbine LLC, LSP-Pike Energy LLC, LSP-Nelson Energy LLC, NRG Nelson Turbines LLC, NRG Jackson Valley Energy I, Inc., NRG McClain LLC, NRG Audrain Holding LLC, NRG Audrain Generating LLC, NRG Peaker Finance Company LLC, Bayou Cove Peaking Power, LLC, Big Cajun I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC, NRG Rockford Equipment II LLC, NRG Sterlington Power LLC and NRG Rockford Acquisition LLC.

“Existing Genco Credit Facility and Notes Indebtedness” means Acquired Debt incurred pursuant to the Acquisition to the extent such Acquired Debt is governed by Texas Genco LLC’s senior secured credit facility dated December 14, 2004, as amended, or the indenture for Texas Genco LLC’s 6.875% Senior Notes due 2014, as amended.

“Existing Indebtedness” means Indebtedness of NRG and its Subsidiaries (other than the Existing Genco Credit Facility and Notes Indebtedness and Indebtedness under the Credit Agreement) in existence on the date of the supplemental indenture, until such amounts are repaid.

“Facility” means a power or energy related facility.

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“Facility Instruments” has the meaning set forth in the (i) Affirmation Agreement, dated as of August 9, 1993, by and among Northern States Power Company, NRG and Ramsey and Washington Counties and (ii) the Agreement and Consent for Transfer to NRG, dated as of August 20, 2001, between Northern States Power Company, NRG, Anoka County, Hennepin County, Sherburne County and Tri-County Solid Waste Management Commission, as in effect on the date of the supplemental indentures.

“fair market value” means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of NRG (unless otherwise provided in the applicable indenture).

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, Guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period.

In addition, for purposes of calculating the Fixed Charge Coverage Ratio:


	(1) Investments and acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations, or any Person or any of its Restricted Subsidiaries acquired by the specified Person or any of its Restricted Subsidiaries, and including any related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date will be given pro forma effect (in accordance with Regulation S-X under the Securities Act, but including all Pro Forma Cost Savings) as if they had occurred on the first day of the four-quarter reference period and Consolidated Cash Flow for such reference period will be calculated on the same pro forma basis;

	(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded;

	(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

	(4) any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period;

	(5) any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period; and

	(6) if any Indebtedness that is being incurred on the Calculation Date bears a floating rate of interest, the interest expense on such Indebtedness will be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligation applicable to such Indebtedness.

If since the beginning of such period any Person (that subsequently became a Restricted Subsidiary or was merged with or into NRG or any Restricted Subsidiary since the beginning of such period) shall have made any Investment, acquisition, disposition, merger, consolidation or disposed operation that would have required adjustment pursuant to this definition, then the Fixed Charge Coverage Ratio shall be calculated giving pro forma effect thereto (including any Pro Forma Cost Savings) for such period as if such Investment,

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acquisition or disposition, or classification of such operation as discontinued had occurred at the beginning of the applicable four-quarter period.

“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:


	(1) the consolidated interest expense of such Person and its Restricted Subsidiaries (other than interest expense of any Excluded Subsidiary the Consolidated Cash Flow of which is excluded from the Consolidated Cash Flow of such Person pursuant to the definition of “Consolidated Cash Flow”) for such period, whether paid or accrued, including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates; plus

	(2) the consolidated interest of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

	(3) any interest accruing on Indebtedness of another Person that is Guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon; plus

	(4) the product of (a) all dividends, whether paid or accrued and whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable in Equity Interests of NRG (other than Disqualified Stock) or to NRG or a Restricted Subsidiary of NRG, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state and local statutory tax rate of such Person, expressed as a decimal, in each case, on a consolidated basis and in accordance with GAAP; minus

	(5) interest income for such period.

“Foreign Subsidiary” means any Restricted Subsidiary that is not a Domestic Subsidiary.

“Foreign Subsidiary Holding Company” means any Domestic Subsidiary that is a direct parent of one or more Foreign Subsidiaries and holds, directly or indirectly, no other assets other than Equity Interests of Foreign Subsidiaries and other de minimis assets related thereto.

“GAAP” means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect from time to time.

“Guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise).

“Guarantors” means each of:


	(1) NRG’s Restricted Subsidiaries other than the Excluded Foreign Subsidiaries, the Excluded Project Subsidiaries, and the Immaterial Subsidiaries; and

	(2) any other Restricted Subsidiary that executes a Subsidiary Guarantee in accordance with the provisions of the indentures;

and their respective successors and assigns.

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“Goldman Sachs Hedge Agreement” means the Master Power Purchase and Sale Agreement dated as of July 21, 2004, between an affiliate of Goldman, Sachs & Co. and Texas Genco, LP, as amended to the date of the supplemental indentures, and any agreements related thereto.

“Governmental Authority” shall mean any nation or government, any state, province, territory or other political subdivision thereof, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government, or any non-governmental authority regulating the generation and/or transmission of energy.

“Government Securities” means direct obligations of, or obligations guaranteed by, the United States of America (including any agency or instrumentality thereof) for the payment of which obligations or guarantees the full faith and credit of the United States of America is pledged and which are not callable or redeemable at the issuer’s option.

“Hazardous Materials” shall mean (a) any petroleum or petroleum products, radioactive materials, friable asbestos, urea formaldehyde foam insulation, transformers or other equipment that contain dielectric fluid containing regulated levels of polychlorinated biphenyls and radon gas; (b) any chemicals, materials or substances defined as or included in the definition of “hazardous substances,” “hazardous waste,” “hazardous materials,” “extremely hazardous waste,” “restricted hazardous waste,” “toxic substances,” “toxic pollutants,” “contaminants,” or “pollutants” or words of similar import, under any applicable Environmental Law; and (c) any other chemical, material or substance, which is prohibited, limited or regulated by any Environmental Law.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person under:


	(1) currency exchange, interest rate or commodity swap agreements, currency exchange, interest rate or commodity cap agreements and currency exchange, interest rate or commodity collar agreements, and

	(2) (i) agreements or arrangements designed to protect such Person against fluctuations in currency exchange, interest rates, commodity prices or commodity transportation or transmission pricing or availability, including but not limited to the Goldman Sachs Hedge Agreement; (ii) any netting arrangements, power purchase and sale agreements, fuel purchase and sale agreements, swaps, options and other agreements, in each case, that fluctuate in value with fluctuations in energy, power or gas prices; and (iii) agreements or arrangements for commercial or trading activities with respect to the purchase, transmission, distribution, sale, lease or hedge of any energy related commodity or service.

“Immaterial Subsidiary” shall mean, at any time, any Restricted Subsidiary of NRG that is designated by NRG as an “Immaterial Subsidiary” if and for so long as such Restricted Subsidiary, together with all other Immaterial Subsidiaries, has (i) total assets at such time not exceeding 5% of NRG’s consolidated assets as of the most recent fiscal quarter for which balance sheet information is available and (ii) total revenues and operating income for the most recent 12-month period for which income statement information is available not exceeding 5% of NRG’s consolidated revenues and operating income, respectively; provided that such Restricted Subsidiary shall be an Immaterial Subsidiary only to the extent that and for so long as all of the above requirements are satisfied.

“Indebtedness” means, with respect to any specified Person, any indebtedness of such Person (excluding accrued expenses and trade payables, except as provided in clause (5) below), whether or not contingent:


	(1) in respect of borrowed money;

	(2) evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);

	(3) in respect of banker’s acceptances;

	(4) representing Capital Lease Obligations or Attributable Debt in respect of sale and leaseback transactions;

	(5) representing the balance deferred and unpaid of the purchase price of any property (including trade payables) or services due more than six months after such property is acquired or such services are completed; or

	(6) representing the net amount owing under any Hedging Obligations,

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if and to the extent any of the preceding items (other than letters of credit, Attributable Debt and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and, to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person; provided, that the amount of such Indebtedness shall be deemed not to exceed the lesser of the amount secured by such Lien and the value of the Person’s property securing such Lien.

“Independent Financial Advisor” means an accounting, appraisal, investment banking firm or consultant to Persons engaged in a Permitted Business of nationally recognized standing that is, in the good faith judgment of NRG, qualified to perform the task for which it has been engaged.

“Interest Period” means, for purposes of the 2014 floating rate notes, the period commencing on and including an interest payment date and ending on and including the day immediately preceding the next succeeding interest payment date, with the exception that the first Interest Period shall commence on and include the date of the 2014 floating rate indenture and end on and include April 30, 2006.

“Investment Grade Rating” means a rating equal to or higher than BBB- (or the equivalent) by S&P and equal to or higher than Baa3 (or the equivalent) by Moody’s.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If NRG or any Subsidiary of NRG sells or otherwise disposes of any Equity Interests of any direct or indirect Subsidiary of NRG such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary of NRG, NRG will be deemed to have made an Investment on the date of any such sale or disposition equal to the fair market value of NRG’s Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The acquisition by NRG or any Subsidiary of NRG of a Person that holds an Investment in a third Person will be deemed to be an Investment by NRG or such Subsidiary in such third Person in an amount equal to the fair market value of the Investments held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” Except as otherwise provided in the indentures, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value.

Notwithstanding anything to the contrary herein, in the case of any Investment made by NRG or a Restricted Subsidiary of NRG in a Person substantially concurrently with a cash distribution by such Person to NRG or a Guarantor (a “Concurrent Cash Distribution”), then:


	(a) the Concurrent Cash Distribution shall be deemed to be Net Proceeds received in connection with an Asset Sale and applied as set forth above under the caption “Asset Sales”; and

	(b) the amount of such Investment shall be deemed to be the fair market value of the Investment, less the amount of the Concurrent Cash Distribution.

“Itiquira” shall mean Itiquira Energetica S.A.

“Itiquira Acquisition Sub” shall have the meaning assigned to such term in the definition of Itiquira Refinancing.

“Itiquira Refinancing” means the transaction or series of related transactions pursuant to which (a) any or all of the outstanding preferred stock of Itiquira directly or indirectly held by Eletrobrás is acquired by Itiquira or a subsidiary of Tosli Acquisition BV (“Itiquira Acquisition Sub”) for an aggregate consideration not to exceed to $70,000,000, and, following such acquisition, such preferred stock is redeemed, repaid or otherwise retired or held as treasury stock or otherwise treated in accordance with the requirements of

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Brazilian law, and (b) pursuant to which Itiquira or the Itiquira Acquisition Sub may incur up to $70,000,000 in aggregate principal amount of Indebtedness secured by Liens on the assets of Itiquira and the Itiquira Acquisition Sub (“Permitted Itiquira Indebtedness”), in each case on terms and conditions (which may include terms and conditions other than those set forth in this definition) reasonably satisfactory to the Administrative Agent under the Credit Agreement.

“Lenders” means, at any time, the parties to the Credit Agreement then holding (or committed to provide) loans, letters of credit, Credit-Linked Deposits or other extensions of credit that constitute (or when provided will constitute) Indebtedness outstanding under the Credit Agreement.

“LIBOR” means, with respect to an Interest Period, the rate (expressed as a percentage per annum) for deposits in U.S. dollars for a three month period beginning on the second London Banking Day after the Determination Date that appears on Telerate Page 3750 as of 11:00 a.m., London time, on the Determination Date. If Telerate Page 3750 does not include such a rate or is unavailable on a Determination Date, the Calculation Agent will request the principal London office of each of four major banks in the London interbank market, as selected by the Calculation Agent, to provide such bank’s offered quotation (expressed as a percentage per annum), as of approximately 11:00 a.m., London time, on such Determination Date, to prime banks in the London interbank market for deposits in a Representative Amount in U.S. dollars for a three month period beginning on the second London Banking Day after the Determination Date. If at least two such offered quotations are so provided, the rate for the Interest Period will be the arithmetic mean of such quotations. If fewer than two such quotations are so provided, the Calculation Agent will request each of three major banks in New York City, as selected by the Calculation Agent, to provide such bank’s rate (expressed as a percentage per annum), as of approximately 11:00 a.m., New York City time, on such Determination Date, for loans in a Representative Amount in U.S. dollars to leading European banks for a three month period beginning on the second London Banking Day after the Determination Date. If at least two such rates are so provided, the rate for the Interest Period will be the arithmetic mean of such rates. If fewer than two such rates are so provided, then the rate for the Interest Period will be the rate in effect with respect to the immediately preceding Interest Period. Notwithstanding the foregoing, LIBOR for the first Interest Period will be %.

“Lien” means, with respect to any asset:


	(1) any mortgage, deed of trust, deed to secure debt, lien (statutory or otherwise), pledge, hypothecation, encumbrance, restriction, collateral assignment, charge or security interest in, on or of such asset;

	(2) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset; and

	(3) in the case of Equity Interests or debt securities, any purchase option, call or similar right of a third party with respect to such Equity Interests or debt securities.

“London Banking Day” means any business day in which dealings in U.S. dollar deposits are transacted in the London interbank market.

“Mark-to-Market Adjustments” means:


	(1) any non-cash loss attributable to the mark-to-market movement in the valuation of Hedging Obligations (to the extent the cash impact resulting from such loss has not been realized) or other derivative instruments pursuant to Financial Accounting Standards Board Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities;” plus


	(a) any loss relating to amounts paid in cash prior to the stated settlement date of any Hedging Obligation that has been reflected in Consolidated Net Income in the current period; plus

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	(b) any gain relating to Hedging Obligations associated with transactions recorded in the current period that has been reflected in Consolidated Net Income in prior periods and excluded from Consolidated Cash Flow pursuant to clauses (2)(a) and (2)(b) below; less,


	(2) any non-cash gain attributable to the mark-to-market movement in the valuation of Hedging Obligations (to the extent the cash impact resulting from such gain has not been realized) or other derivative instruments pursuant to Financial Accounting Standards Board Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities;” less


	(a) any gain relating to amounts received in cash prior to the stated settlement date of any Hedging Obligation that has been reflected in Consolidated Net Income in the current period; less

	(b) any loss relating to Hedging Obligations associated with transactions recorded in the current period that has been reflected in Consolidated Net Income in prior periods and excluded from Consolidated Cash Flow pursuant to clauses (1)(a) and (1)(b) above.

“Material Adverse Effect” shall mean a material adverse change in or material adverse effect on the condition (financial or otherwise), results of operations, assets, liabilities or prospects of NRG and its Subsidiaries, taken as a whole.

“Moody’s” means Moody’s Investors Service, Inc. or any successor entity.

“Necessary CapEx Debt” shall mean Indebtedness of NRG or its Restricted Subsidiaries incurred for the purpose of financing Necessary Capital Expenditures.

“Necessary Capital Expenditures” shall mean capital expenditures that are required by Applicable Law (other than Environmental Laws) or undertaken for health and safety reasons. The term “Necessary Capital Expenditures” does not include any capital expenditure undertaken primarily to increase the efficiency of, expand or re-power any power generation facility.

“Net Income” means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends or accretion, excluding, however:


	(1) any gain or loss, together with any related provision for taxes on such gain or loss, realized in connection with: (a) any Asset Sale (without giving effect to the threshold provided for in the definition thereof); or (b) the disposition of any securities by such Person or any of its Restricted Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Restricted Subsidiaries; and

	(2) any extraordinary gain or loss, together with any related provision for taxes on such extraordinary gain or loss.

“Net Proceeds” means the aggregate cash proceeds received by NRG or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale, taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax deductions and any tax sharing arrangements, and amounts required to be applied to the repayment of Indebtedness, other than Indebtedness under a Credit Facility, secured by a Lien on the asset or assets that were the subject of such Asset Sale and any reserve for adjustment in respect of the sale price of such asset or assets established in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness:


	(1) as to which neither NRG nor any of its Restricted Subsidiaries (other than an Excluded Project Subsidiary) (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness) other than pursuant to a Non-Recourse Guarantee or any arrangement to provide or guarantee to provide goods and services on an arm’s length basis, (b) is

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	directly or indirectly liable as a guarantor or otherwise, other than pursuant to a Non-Recourse Guarantee, or (c) constitutes the lender;

	(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness of NRG (other than the notes and the Credit Agreement) or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of such other Indebtedness to be accelerated or payable prior to its Stated Maturity; and

	(3) in the case of Non-Recourse Debt incurred after the date of the supplemental indentures, as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of NRG or any of its Restricted Subsidiaries except as otherwise permitted by clauses (1) or (2) above;

provided, however, that the following shall be deemed to be Non-Recourse Debt: (i) Guarantees with respect to debt service reserves established with respect to a Subsidiary to the extent that such Guarantee shall result in the immediate payment of funds, pursuant to dividends or otherwise, in the amount of such Guarantee; (ii) contingent obligations of NRG or any other Subsidiary to make capital contributions to a Subsidiary; (iii) any credit support or liability consisting of reimbursement obligations in respect of Letters of Credit issued under and subject to the terms of, the Credit Agreement to support obligations of a Subsidiary; and (iv) any Investments in a Subsidiary, to the extent in the case of (i) through (iv) otherwise permitted by the indentures.

“Non-Recourse Guarantee” means any Guarantee by NRG or a Guarantor of Non-Recourse Debt incurred by an Excluded Project Subsidiary as to which the lenders of such Non-Recourse Debt have acknowledged that they will not have any recourse to the stock or assets of NRG or any Guarantor, except to the limited extent set forth in such guarantee.

“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.

“Permitted Business” means the business of acquiring, constructing, managing, developing, improving, maintaining, leasing, owning and operating Facilities, together with any related assets or facilities, as well as any other activities reasonably related to, ancillary to, or incidental to, any of the foregoing activities (including acquiring and holding reserves), including investing in Facilities.

“Permitted Investments” means:


	(1) any Investment in NRG or in a Restricted Subsidiary of NRG that is a Guarantor;

	(2) any Investment in an Immaterial Subsidiary;

	(3) any Investment in an Excluded Foreign Subsidiary for so long as the Excluded Foreign Subsidiaries do not collectively own more than 20% of the consolidated assets of NRG as of the most recent fiscal quarter end for which financial statements are publicly available;

	(4) any issuance of letters of credit in an aggregate amount not to exceed $250.0 million solely for working capital requirements and general corporate purposes of any of the Excluded Subsidiaries;

	(5) any Investment in Cash Equivalents (and, in the case of Excluded Subsidiaries only, Cash Equivalents or other liquid investments permitted under any Credit Facility to which it is a party);

	(6) any Investment by NRG or any Restricted Subsidiary of NRG in a Person, if as a result of such Investment:


	(a) such Person becomes a Restricted Subsidiary of NRG and a Guarantor or an Immaterial Subsidiary; or

	(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, NRG or a Restricted Subsidiary of NRG that is a Guarantor;

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	(7) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales”;

	(8) Investments made as a result of the sale of Equity Interests of any Person that is a Subsidiary of NRG such that, after giving effect to any such sale, such Person is no longer a Subsidiary of NRG, if the sale of such Equity Interests constitutes an Asset Sale and the Net Proceeds received from such Asset Sale are applied as set forth above under the caption “—Repurchase at the Option of Holders—Asset Sales”;

	(9) Investments to the extent made in exchange for the issuance of Equity Interests (other than Disqualified Stock) of NRG;

	(10) any Investments received in compromise or resolution of (a) obligations of trade creditors or customers of NRG or any of its Restricted Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; or (b) litigation, arbitration or other disputes with Persons who are not Affiliates;

	(11) Investments represented by Hedging Obligations;

	(12) loans or advances to employees;

	(13) repurchases of the notes or pari passu Indebtedness;

	(14) any Investment in securities of trade creditors, trade counter-parties or customers received in compromise of obligations of those Persons, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of such trade creditors or customers;

	(15) negotiable instruments held for deposit or collection;

	(16) receivables owing to NRG or any Restricted Subsidiary of NRG and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as NRG of any such Restricted Subsidiary of NRG deems reasonable under the circumstances;

	(17) payroll, travel and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes;

	(18) Investments resulting from the acquisition of a Person that at the time of such acquisition held instruments constituting Investments that were not acquired in contemplation of the acquisition of such Person;

	(19) any Investment in any Person engaged primarily in one or more Permitted Businesses (including, without limitation, Excluded Subsidiaries, Unrestricted Subsidiaries, and Persons that are not Subsidiaries of NRG) made for cash since the date of the supplemental indentures;

	(20) the contribution of any one or more of the Specified Facilities to a Restricted Subsidiary that is not a Guarantor;

	(21) Investments made pursuant to a commitment that, when entered into, would have complied with the provisions of the applicable indenture; and

	(22) other Investments made since the date of the supplemental indentures in any Person having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (22) that are at the time outstanding not to exceed the greater of (a) $500.0 million and (b) 2.5% of Total Assets; provided, however, that if any Investment pursuant to this clause (22) is made in any Person that is not a Restricted Subsidiary of NRG and a Guarantor at the date of the making of the Investment and such Person becomes a Restricted Subsidiary and a Guarantor after such date, such

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	Investment shall thereafter be deemed to have been made pursuant to clause (1) above, and shall cease to have been made pursuant to this clause (22).

“Permitted Itiquira Indebtedness” shall have the meaning assigned to such term in the definition of Itiquira Refinancing.

“Permitted Liens” means:


	(1) Liens on assets of NRG or any Guarantor securing Indebtedness and other Obligations under Credit Facilities, in an aggregate principal amount not exceeding, on the date of the creation of such Liens, the greater of (a) 30.0% of Total Assets or (b) $6.0 billion less the aggregate amount of all repayments, optional or mandatory, of the principal of any term Indebtedness under a Credit Facility that have been made by NRG or any of its Restricted Subsidiaries since the date of the supplemental indentures with the Net Proceeds of Asset Sales (other than Excluded Proceeds) and less, without duplication, the aggregate amount of all repayments or commitment reductions with respect to any revolving credit borrowings under a Credit Facility that have been made by NRG or any of its Restricted Subsidiaries since the date of the supplemental indentures as a result of the application of the Net Proceeds of Asset Sales (other than Excluded Proceeds) in accordance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales” (excluding temporary reductions in revolving credit borrowings as contemplated by that covenant);

	(2) Liens to secure obligations with respect to (i) contracts (other than for Indebtedness) for commercial and trading activities for the purchase, transmission, distribution, sale, lease or hedge of any energy related commodity or service, and (ii) Hedging Obligations;

	(3) Liens on assets of Excluded Subsidiaries securing Indebtedness of Excluded Subsidiaries that was permitted by the terms of the indentures to be incurred;

	(4) Liens (a) in favor of NRG or any of the Guarantors; (b) incurred by Excluded Project Subsidiaries in favor of any other Excluded Project Subsidiary; or (c) incurred by Excluded Foreign Subsidiaries in favor of any other Excluded Foreign Subsidiary;

	(5) Liens to secure the performance of statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature;

	(6) Liens to secure Indebtedness (including Capital Lease Obligations) permitted by clause (4), (13) and (20) of the second paragraph of the covenant entitled “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” covering only the assets acquired with or financed by such Indebtedness;

	(7) Liens existing on the date of the supplemental indentures;

	(8) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded; provided that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;

	(9) Liens imposed by law, such as carriers’, warehousemen’s, landlord’s and mechanics’ Liens;

	(10) survey exceptions, easements or reservations of, or rights of others for, licenses, rights-of-way, sewers, electric lines, telegraph and telephone lines, oil, gas and other mineral interests and leases, and other similar purposes, or zoning or other restrictions as to the use of real property that were not incurred in connection with Indebtedness and that do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

	(11) Liens created for the benefit of (or to secure) the notes (or the Subsidiary Guarantees);

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	(12) Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the applicable indenture; provided, however, that:


	(a) the new Lien shall be limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and

	(b) the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount or, if greater, committed amount, of the Permitted Referencing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such refinancings, refunding, extension, renewal or replacement;


	(13) Liens incurred or deposits made in connection with workers’ compensation, unemployment insurance and other types of social security;

	(14) Liens encumbering deposits made to secure obligations arising from statutory, regulatory, contractual or warranty requirements of NRG or any of its Restricted Subsidiaries, including rights of offset and set-off;

	(15) leases or subleases granted to others that do not materially interfere with the business of NRG and its Restricted Subsidiaries;

	(16) statutory Liens arising under ERISA;

	(17) Liens on property (including Capital Stock) existing at the time of acquisition of the property by NRG or any Subsidiary of NRG; provided that such Liens were in existence prior to, such acquisition, and not incurred in contemplation of, such acquisition;

	(18) Liens arising from Uniform Commercial Code financing statements filed on a precautionary basis in respect of operating leases intended by the parties to be true leases (other than any such leases entered into in violation of the applicable indenture);

	(19) Liens on assets and Equity Interests of a Subsidiary that is an Excluded Subsidiary;

	(20) Liens granted in favor of Xcel Energy, Inc. pursuant to the Xcel Indemnification Agreements as in effect on the date of the supplemental indentures on NRG’s interest in all revenues received by NRG pursuant to the Facility Instruments;

	(21) Liens to secure Indebtedness incurred to finance Necessary Capital Expenditures that encumber only the assets purchased, installed or otherwise acquired with the proceeds of such Indebtedness;

	(22) Liens to secure Environmental CapEx Debt that encumber only the assets purchased, installed or otherwise acquired with the proceeds of such Environmental CapEx Debt;

	(23) Liens relating to the escrow and security agreement in effect on the date of the supplemental indentures and future escrow arrangements securing Indebtedness incurred in accordance with the indentures;

	(24) Liens on assets or securities deemed to arise in connection with the execution, delivery or performance of contracts to sell such assets or stock otherwise permitted under the indentures;

	(25) Liens on assets of Itiquira incurred pursuant to the Itiquira Refinancing; and

	(26) any restrictions on any Equity Interest or undivided interests, as the case may be, of a Person providing for a breach, termination or default under any joint venture, stockholder, membership, limited liability company, partnership, owners’, participation or other similar agreement between such Person and one or more other holders of Equity Interests or undivided interests of such Person, as the case may be, if a security interest or Lien is created on such Equity Interest or undivided interest, as the case may be, as a result thereof;

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	(27) any customary provisions limiting the disposition or distribution of assets or property (including without limitation Equity Interests) or any related restrictions thereon in joint venture, partnership, membership, stockholder and limited liability company agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements and other similar agreements, including owners’, participation or similar agreements governing projects owned through an undivided interest; provided, however, that any such limitation is applicable only to the assets that are the subjects of such agreements;

	(28) those Liens or other exceptions to title, in either case on or in respect of any facility of NRG or any Subsidiary, arising as a result of any shared facility agreement entered into after the closing date with respect to such facility, except to the extent that any such Liens or exceptions, individually or in the aggregate, materially adversely affect the value of the relevant property or materially impair the use of the relevant property in the operation of the business of NRG or such Subsidiary;

	(29) Liens on cash deposits and other funds maintained with a depositary institution, in each case arising in the ordinary course of business by virtue of any statutory or common law provision relating to banker’s liens, including Section 4-210 of the Uniform Commercial Code;

	(30) any Liens on property and assets (other than certain properties or assets defined as “core” collateral) designated as Excluded Assets from time to time by NRG under clause (xiii) of the related definition under the Credit Agreement, which shall not have, when taken together with all other “non-core” property and assets that constitute Excluded Assets pursuant to such clause at the relevant time of determination, a fair market value in excess of $250 million in the aggregate (and, to the extent that such fair market value of such asset exceeds $250 million in the aggregate, such property or assets shall cease to be an Excluded Asset only to the extent of such excess fair market value); and

	(31) Liens incurred by NRG or any Subsidiary of NRG with respect to obligations that do not exceed $100.0 million at any one time outstanding.

“Permitted Refinancing Indebtedness” means any Indebtedness of NRG or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to refund, refinance, replace, defease or discharge other Indebtedness of NRG or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:


	(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness extended, refinanced, renewed, replaced, defeased or refunded (plus all accrued interest on the Indebtedness and the amount of all expenses and premiums incurred in connection therewith);

	(2) such Permitted Refinancing Indebtedness has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

	(3) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the notes, such Permitted Refinancing Indebtedness is subordinated in right of payment to, the notes on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

	(4) such Indebtedness is incurred either by NRG (and may be guaranteed by any Guarantor) or by the Restricted Subsidiary who is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and

	(5) (a) if the Stated Maturity of the Indebtedness being refinanced is earlier than the Stated Maturity of the notes, the Permitted Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the notes, the Permitted Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the notes.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“PMI” means NRG Power Marketing Inc., a Delaware corporation.

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“Pro Forma Cost Savings” means, without duplication, with respect to any period, reductions in costs and related adjustments that have been actually realized or are projected by NRG’s Chief Financial Officer in good faith to result from reasonably identifiable and factually supportable actions or events, but only if such reductions in costs and related adjustments are so projected by NRG to be realized during the consecutive four-quarter period commencing after the transaction giving rise to such calculation.

“Related Financing Transactions” means the incurrence of Indebtedness and issuance of Capital Stock of NRG described in this prospectus supplement under the heading “The Acquisition—The Financing Transactions”.

“Representative Amount” means a principal amount of not less than $1,000,000 for a single transaction in the relevant market at the relevant time.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Payments” has the meaning assigned to such term under the caption “—Certain Covenants—Restricted Payments.” For purposes of determining compliance with the covenant described above under the caption “—Certain Covenants—Restricted Payments,” no Hedging Obligation shall be deemed to be contractually subordinated to the notes or any Subsidiary Guarantee.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

“Revolving Loans” means the revolving loans and commitments made by the Lenders under the Credit Agreement.

“S&P” means Standard & Poor’s Ratings Group or any successor entity.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the supplemental indentures.

“Specified Facility” means each of the following Facilities: (a) the Facilities held on the date of the indentures by Vienna Power LLC, Meriden Gas Turbine LLC, Norwalk Power LLC, Connecticut Jet Power LLC (excluding the Cos Cob assets), Devon Power LLC, Montville Power LLC (including the Capital Stock of the entities owning such Facilities provided that such entities do not hold material assets other than the Facilities held on the date of the supplemental indentures); (b) the following Facilities: P.H. Robinson, H.O. Clarke, Webster, Unit 3 at Cedar Bayou, Unit 2 at T.H. Wharton; and (c) the Capital Stock of the following Subsidiaries of NRG if such Subsidiary holds no assets other than the Capital Stock of a Foreign Subsidiary of NRG: NRG Latin America, Inc., NRG International LLC, NRG Insurance Ltd. (Cayman Islands), NRG Asia Pacific, Ltd., NRG International II Inc. and NRG International III Inc.

“Specified Joint Venture Sale” means the sale after the date of the supplemental indentures by NRG or a Subsidiary of NRG of its Equity Interest in those joint ventures specified in the Credit Agreement to one or more holders of the remaining Equity Interest therein pursuant to the terms of the joint venture agreements relating thereto.

“Sponsor Preferred Stock” means the shares of NRG’s preferred stock issued pursuant to the terms of the Acquisition Agreement, among Texas Genco LLC, NRG, and the direct and indirect owners of Texas Genco LLC party thereto, dated as of September 30, 2005.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the documentation governing such Indebtedness as of the date of the supplemental indentures, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

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“Subsidiary” means, with respect to any specified Person:


	(1) any corporation, association or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency and after giving effect to any voting agreement or stockholders’ agreement that effectively transfers voting power) to vote in the election of directors, managers or trustees of the corporation, association or other business entity is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

	(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof).

“Subsidiary Guarantee” means the Guarantee by each Guarantor of NRG’s obligations under the indentures and on the notes, executed pursuant to the provisions of the indentures.

“Telerate Page 3750” means the display designated at “Page 3750” on the Moneyline Telerate service (or such other page as may replace Page 3750 on that service).

“Total Assets” means the total consolidated assets of NRG and its Restricted Subsidiaries, determined on a consolidated basis in accordance with GAAP, as shown on the most recent balance sheet of NRG.

“Treasury Rate” means, as of any redemption date, the yield to maturity as of such redemption date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to February 1, 2010, with respect to the 2014 fixed rate notes, and February 1, 2011, with respect to the 2016 notes; provided, however, that if the period from the redemption date to February 1, 2010, with respect to the 2014 fixed rate notes, and February 1, 2011, with respect to the 2016 notes, is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.

“UCC” means the Uniform Commercial Code as in effect in the State of New York or any other applicable jurisdiction.

“Unrestricted Subsidiary” means any Subsidiary of NRG that is designated by the Board of Directors as an Unrestricted Subsidiary pursuant to a Board Resolution, but only to the extent that such Subsidiary:


	(1) has no Indebtedness other than Non-Recourse Debt;

	(2) except as permitted by the covenant described above under the caption “—Certain Covenants—Affiliate Transactions,” is not party to any agreement, contract, arrangement or understanding with NRG or any Restricted Subsidiary of NRG unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to NRG or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of NRG;

	(3) is a Person with respect to which neither NRG nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results except as otherwise permitted by the Credit Agreement as in effect on the date of the supplemental indentures; and

	(4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of NRG or any of its Restricted Subsidiaries except as otherwise permitted by the Credit Agreement as in effect on the date of the supplemental indentures.

Any designation of a Subsidiary of NRG as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of the Board Resolution giving effect to such designation and an officers’ certificate certifying that such designation complied with the conditions described above under the caption

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“—Certain Covenants—Designation of Restricted, Unrestricted and Excluded Project Subsidiaries” and was permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments.” If, at any time, any Unrestricted Subsidiary fails to meet the requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indentures and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of NRG as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” NRG will be in default of such covenant. The Board of Directors of NRG may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of NRG of any outstanding Indebtedness of such Unrestricted Subsidiary and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period; and (2) no Default or Event of Default would be in existence following such designation.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:


	(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

	(2) the then outstanding principal amount of such Indebtedness.

“Xcel” means Xcel Energy Inc., a Minnesota corporation.

“Xcel Indemnification Agreements” means: (i) the Indemnification Agreement, dated as of December 5, 2003, between Xcel Energy Inc., Northern States Power Company and NRG; and (ii) the Indemnification Agreement, dated as of December 5, 2003, between Xcel Energy Inc., Northern States Power Company and NRG.

“Xcel Note” means that certain promissory note made by NRG in favor of Xcel in an initial principal amount of $10.0 million and issued pursuant to the terms and conditions of the Joint Plan of Reorganization approved by the United States Bankruptcy Court for the Southern District of New York on November 24, 2003.

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DESCRIPTION OF CERTAIN OTHER INDEBTEDNESS AND PREFERRED STOCK

New Senior Secured Credit Facility

We plan to enter into a new senior secured credit facility for up to an aggregate amount of $5.575 billion to replace NRG’s existing senior secured credit facility. The new senior secured credit facility is expected to consist of a $3.575 billion senior first priority secured term loan facility, a $1.0 billion senior first priority secured revolving credit facility and a $1.0 billion senior first priority secured synthetic letter of credit facility. We 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.

We plan to use initial borrowings under our new senior secured credit facility, together with the net proceeds from this offering, the offerings of common stock and mandatory convertible preferred stock and cash on hand, to finance the Acquisition, to repay certain of our and Texas Genco’s outstanding indebtedness and to pay related premiums, fees and expenses. See “Use of Proceeds.”

The following is a summary description of the principal terms and conditions of the new senior secured credit facility. This description is not intended to be exhaustive and is qualified in its entirety by reference to the provisions that will be contained in the definitive credit agreement. As the final terms of the senior secured credit facility have not been agreed upon, the final terms may differ from those set forth herein and such differences may be significant.

The senior secured credit facility’s $3.575 billion term facility will mature on the seventh anniversary of its closing date, and will amortize in 27 consecutive equal quarterly installments in an aggregate annual amount equal to 1.0% of the original principal amount of the term facility during the first 6³/4 years thereof with the balance payable on the seventh anniversary thereof. The $1.0 billion synthetic letter of credit facility will mature on the seventh anniversary of the closing date of the senior secured credit facility. The $1.0 billion revolving facility will mature on the fifth anniversary of the closing date of the senior secured credit facility, and no amortization will be required in respect thereof. 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, including pro forma compliance with financial covenants. Up to $50 million of the revolving credit facility will be available as a swing-line facility; the full amount of the revolving facility is available for the issuance of letters of credit.

The revolving credit facility is expected to be undrawn at the time of closing.


	*Guarantees and Collateral*

The senior secured credit facility will be guaranteed by substantially all of our existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries and certain other subsidiaries. In addition, it will be secured by liens on substantially all of the assets of NRG and the assets of its subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries and certain other subsidiaries. The capital stock of substantially all of our subsidiaries, with certain exceptions for unrestricted subsidiaries, foreign subsidiaries and project subsidiaries, will be pledged for the benefit of the senior secured credit facility lenders.

In addition to the foregoing, the senior secured credit facility will be secured by a first-priority perfected security interest in all of the property and assets owned at-any time or acquired by NRG and its subsidiaries, other than (a) the assets of certain unrestricted subsidiaries excluded project subsidiaries, foreign subsidiaries and certain other subsidiaries, and (b) (i) any lease, license, contract, property right or agreement of NRG or any subsidiary guarantor, if and only for so long as the grant of a security interest under the security documents would result in a breach, termination or default under that lease, license, contract, property right or agreement; (ii) certain interests in real property owned or leased by NRG and certain subsidiary guarantors; (iii) equity interests in certain of NRG’s project affiliates that have non-recourse debt financing; (iv) any voting equity

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interests in excess of 66% of the total outstanding voting equity interest of certain of our foreign subsidiaries; and (v) certain other limited exceptions.


	*Interest*

At NRG’s option, loans under the senior secured credit facility will be available as “Alternate Base Rate” loans or “Eurodollar” loans, as follows:


	•	Alternate Base Rate loans. Interest is expected to be at a spread (the “Applicable Margin”) over the Alternate Base Rate for term loans and for revolving loans and swing-line loans, calculated on a 365-day or 366-day basis, as the case may be, when the Alternate Base Rate is determined by reference to the prime rate, and on a 360-day basis at all other times. The “Alternate Base Rate” shall mean, for any day, a rate per annum equal to the greater of (a) the “prime rate” publicly announced from time to time by The Wall Street Journal as the “base rate on corporate loans posted by at least 75% of the nation’s 30 largest banks” and (b) the federal funds effective rate in effect on such day plus ¹/2 of 1%.

	•	Eurodollar loans. Interest will be determined for periods to be selected by NRG, or “interest periods,” of one, two, three or six months and, to the extent available to all of the lenders, nine or twelve months, and is expected be at a spread (the “Applicable Margin”) over the Adjusted LIBO Rate for term loans and for revolving loans and swing-line loans, calculated on a 360-day basis. The “Adjusted LIBO Rate” shall mean, with respect to any Eurodollar loan for any interest period and as determined from time to time, an interest rate per annum equal to the product of (a) the rate per annum determined by the Administrative Agent at approximately 11:00 a.m., London time, on the date that is two business days prior to the commencement of the relevant interest period by reference to the British Bankers’ Association Interest Settlement Rates for deposits in dollars (as set forth by the Bloomberg Information Service or any successor thereto or any other service selected by the Administrative Agent which has been nominated by the British Bankers’ Association as an authorized information vendor for the purpose of displaying such rates) for a period equal to the relevant interest period and (b) certain statutory reserves as agreed upon in the senior secured credit facility.

The “Applicable Margin” shall mean, for any day, for each type of loan, the rate per annum set forth under the relevant column heading below based upon the consolidated senior leverage ratio of NRG as of the relevant date of determination:


									ABR Revolving
	Eurodollar		ABR Term			Eurodollar			Loans and
Consolidated Senior Leverage Ratio	Term Loans		Loans			Revolving Loans			Swingline Loans

Category 1
Greater than 3.50 to 1.00		2.0%		1.0	%		2.00	%		1.00	%
Category 2
Greater than 3.00 to 1.00 but less than or equal to 3.50 to 1.00		1.75%		0.75	%		1.75	%		0.75	%
Category 3
Less than or equal to 3.00 to 1.00		1.75%		0.75	%		1.50	%		0.50	%

Interest on the loans will be payable (a) with respect to any Alternate Base Rate Loan (other than a Swingline Loan), on the last business day of each March, June, September and December (beginning with March 31, 2006), (b) with respect to any Eurodollar Loan, the last day of the interest period applicable to such loan is a part and, in the case of a Eurodollar Loan with an interest period of more than three months’ duration, each day that would have been an interest payment date had successive interest periods of three months’ duration been applicable to such loan, and (c) with respect to any swingline loan, the day that such loan is required to be repaid. Until NRG delivers certain financial statements and certificates for the period ended on the first fiscal quarter after the closing date of the senior secured credit agreement, category 1 will apply for purposes of determining the Applicable Margin.

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The synthetic letters of credit will be issued by an issuing bank. The synthetic letter of credit issuing bank will invest amounts in a “synthetic L/ C account” in certain agreed upon permitted investments. On the last business day of March, June, September and December of each year (beginning with March 31, 2006): (i) the synthetic letter of credit issuing bank will distribute to each lender under the synthetic letter of credit facility its pro rata share of any interest accrued on funds held in the synthetic L/ C Account and (ii) NRG will pay to the synthetic letter of credit issuing bank for pro rata remittance to each lender under the synthetic letter of credit facility a fee based on such lender’s total commitment (without regard to actual amount of letters of credit outstanding) times the interest rate applicable to the loans under the term facility (assuming one-month LIBOR) as specified in above (net of the amounts received by such lender pursuant to clause (i) above). In addition, NRG will pay the synthetic letter of credit issuing bank a fronting fee in an amount to be agreed and customary issuance and administrative fees.


	*Default Interest and Fees*

If NRG defaults on the payment of the principal of or interest on any loan or any other amount becoming due and payable hereunder or under any other loan document related to the senior secured credit facility, then NRG shall on demand from time to time pay interest, to the extent permitted by law, on such defaulted amount (a) in the case of overdue principal, at the rate otherwise applicable to such loan plus 2.00% per annum and (b) in all other cases, at a rate per annum equal to the rate that would be applicable to an Alternate Base Rate term loan plus 2.00%.


	*Commitment and Letter of Credit Fees*

Commitment fees equal to 0.5% per annum times the daily average undrawn portion of the revolving facility will accrue from the closing date and shall be payable quarterly in arrears.

A fee equal to (i) the Applicable Margin then in effect for loans bearing interest at the Adjusted LIBO Rate made under the revolving facility, times (ii) the average daily maximum aggregate amount available to be drawn under all letters of credit, will be payable quarterly in arrears to the lenders under the revolving facility. In addition, a fronting fee, to be agreed upon between the issuer of each letter of credit and NRG, will be payable to such issuer, as well as certain customary fees.


	*Covenants*

The senior secured credit facility will contain affirmative and negative covenants customary for a transaction of this type which, among other things, require us to meet certain financial tests, including a minimum interest coverage ratio and a maximum leverage ratio, each at the NRG level and on a consolidated basis. The senior secured credit facility will also contain covenants which, among other things, limit:


	•	indebtedness (including guarantees and other contingent obligations);

	•	liens;

	•	sale and lease-back transactions;

	•	investments, loans and advances;

	•	mergers, acquisitions, consolidations and asset sales;

	•	dividends and other restricted payments;

	•	transactions with affiliates;

	•	business activities and hedging agreements;

	•	capital expenditures;

	•	limitations on debt payments;

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	•	changes to the terms of any material indebtedness that materially increase the obligations of the obligor or confer additional material rights to the holder of such indebtedness; and

	•	other matters customarily restricted in such agreements.

Events of Default

Events of default under the senior secured credit facility include, but are not limited to:


	•	breaches of representations and warranties;

	•	payment defaults;

	•	noncompliance with covenants;

	•	bankruptcy;

	•	judgments in excess of a specified amount;

	•	any confirmation order that is reversed, amended or modified in any material respects, vacated or stayed;

	•	any event that could result in our liability under the Employee Retirement Income Security Act of 1974 in excess of a specified amount;

	•	failure of any guarantee or pledge agreement supporting the senior secured credit facility to be in full force and effect;

	•	failure of any lien created in favor of the loan parties to be a valid, perfected and first priority lien on any material collateral securing the senior secured credit facility; and

	•	a change of control, as such term is defined in the senior secured credit facility.

Bridge Loan Facility

NRG has entered into the commitment letter with the bridge lenders pursuant to which the bridge lenders have committed to provide NRG with up to $5.1 billion in bridge financing to fund all necessary amounts not provided for under the new senior secured credit facility. NRG does not intend to draw down on the bridge loan facility unless this offering, the common stock offering and/or the mandatory convertible preferred stock offering are not consummated at the time of the closing of the Acquisition.

The bridge loans will mature one year from the date they are issued. Upon the maturity date, if any bridge loan has not been repaid in full, and provided no payment or bankruptcy default has occurred under the bridge loans or the new senior secured credit facility, the bridge loan will automatically be converted into a term loan due on the 10-year anniversary of the closing date of the Acquisition. Subject to certain exceptions, the net proceeds from (i) any public offering or private placement of securities of NRG or its subsidiaries, (ii) any future bank borrowings under the new senior secured credit facility or (iii) any future asset sale will be used to repay the bridge loans at a price equal to 100% of the principal amount plus accrued and unpaid interest. The bridge loans may be prepaid at any time at the option of NRG at a price equal to 100% of the principal amount plus accrued and unpaid interest. Subject to customary exceptions, the bridge loans will be guaranteed on a senior first priority basis by each of NRG’s current and future domestic subsidiaries, excluding certain foreign, project and immaterial subsidiaries. The bridge loans will initially bear interest at a per annum rate equal to (a) at NRG’s option (i) the reserve adjusted Eurodollar rate or (ii) the base rate, as in effect from time to time, in each case, calculated on the basis of the actual number of days elapsed in a year of 360 days (365/366 day year with respect to loans bearing interest with reference to the base rate), plus (b) a spread of 500 basis points in the case NRG elects the Eurodollar option and 400 basis points in the case NRG elects the base rate option. If the bridge loans are not repaid in whole within six months following the closing date of the Acquisition, the spread will increase by 100 basis points at the end of such six-month period and will increase by an additional 50 basis points at the end of each three-month period thereafter.

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The bridge loans will contain customary events of default and covenants by NRG. Certain terms of the bridge loan facility may vary after the date of this prospectus supplement to facilitate the syndication of the facility. The commitment letter is subject to customary conditions to consummation, including the absence of any event or circumstance that would have a material adverse effect on the business, assets, properties, liabilities, condition (financial or otherwise) or results of operations, taken as a whole, of Texas Genco, or Texas Genco and NRG combined, since June 30, 2005.

Xcel Note

On December 5, 2003, we entered into a $10.0 million promissory note with Xcel Energy. The note accrues interest at a rate of 3% per year, payable quarterly in arrears. All principal is due at maturity on June 5, 2006.

4% Convertible Perpetual Preferred Stock

On December 27, 2004, NRG completed the sale of 420,000 shares of Convertible Perpetual Preferred Stock with a dividend coupon rate of 4%. The 4% Preferred Stock has a liquidation preference of $1,000 per share. Holders of 4% Preferred Stock are entitled to receive, when declared by NRG’s board of directors, cash dividends at the rate of 4% per annum, payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year, commencing on March 15, 2005. The 4% Preferred Stock is convertible, at the option of the holder, at any time into shares of NRG common stock. On or after December 20, 2009, NRG may redeem, subject to certain limitations, some or all of the 4% Preferred Stock with cash at a redemption price equal to 100% of the liquidation preference, plus accumulated but unpaid dividends, including liquidated damages, if any, to the redemption date.

If NRG is subject to a fundamental change, as defined in the Certificate of Designation of the 4% Preferred Stock, each holder of shares of 4% Preferred Stock has the right, subject to certain limitations, to require NRG to purchase any or all of its shares of 4% Preferred Stock at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends, including liquidated damages, if any, to the date of purchase. Final determination of a fundamental change must be approved by NRG’s board of directors or the board of directors must decide to take a neutral position with respect to such fundamental change.

Each holder of 4% Preferred Stock has one vote for each share of 4% Preferred Stock held by the holder on all matters voted upon by the holders of NRG’s common stock, as well as voting rights specifically provided for in NRG’s amended and restated certificate of incorporation or as otherwise from time to time required by law. In addition, whenever (1) dividends on the 4% Preferred Stock or any other class or series of stock ranking on a parity with the 4% Preferred Stock with respect to the payment of dividends are in arrears for dividend periods, whether or not consecutive, containing in the aggregate a number of days equivalent to six calendar quarters, or (2) NRG fails to pay the redemption price on the date shares of 4% Preferred Stock are called for redemption or the purchase price on the purchase date for shares of 4% Preferred Stock following a fundamental change, then, in each case, the holders of 4% Preferred Stock (voting separately as a class with all other series of preferred stock upon which like voting rights have been conferred and are exercisable) are entitled to vote for the election of two of the authorized number of NRG’s directors at the next annual meeting of stockholders and at each subsequent meeting until all dividends accumulated or the redemption price on the 4% Preferred Stock have been fully paid or set apart for payment. The term of office of all directors elected by holders of the 4% Preferred Stock will terminate immediately upon the termination of the rights of the holders of the 4% Preferred Stock to vote for directors. Upon election of any additional directors, the number of directors that comprise NRG’s board of directors will be increased by the number of such additional directors.

The 4% Preferred Stock is senior to all classes of common stock, on a parity with the 3.625% Preferred Stock and upon issuance, the Mandatory Convertible Preferred Stock and junior to all of NRG’s existing and future debt obligations and all of NRG’s subsidiaries’ existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries. The proceeds of $406.4 million, net of issuance costs of

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approximately $13.6 million, were used to redeem $375.0 million of Second Priority Notes on February 4, 2005.

3.625% Convertible Perpetual Preferred Stock

On August 11, 2005, NRG issued 250,000 shares of its 3.625% Convertible Perpetual Preferred Stock, or 3.625% Preferred Stock, to Credit Suisse First Boston Capital LLC, or CSFB, in a private placement. The 3.625% Preferred Stock has a liquidation preference of $1,000 per share. Holders of the 3.625% Preferred Stock are entitled to receive, out of funds legally available, cash dividends at the rate of 3.625% per annum, payable in cash quarterly in arrears commencing on December 15, 2005. Each share of 3.625% Preferred Stock is convertible during the 90-day period beginning August 11, 2015 at the option of NRG or the holder. Holders tendering the 3.625% Preferred Stock for conversion shall be entitled to receive cash and common stock. NRG may elect to make cash payment in lieu of delivering shares of common stock in connection with such conversion, and NRG may elect to receive cash in lieu of shares of common stock, if any, from the holder in connection with such conversion.

If NRG is subject to a fundamental change, as defined in the Certificate of Designation of the 3.625% Preferred Stock, each holder of shares of 3.625% Preferred Stock has the right, subject to certain limitations, to require NRG to purchase any or all of its shares of 3.625% Preferred Stock at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends, including liquidated damages, if any, to the date of purchase.

The 3.625% Preferred Stock is senior to all classes of common stock, on a parity with the 4% Preferred Stock and upon issuance, the Mandatory Convertible Preferred Stock and junior to all of NRG’s existing and future debt obligations and all of NRG’s subsidiaries’ existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries. Title to the 3.625% Preferred Stock, may not be transferred to an entity that is not an affiliate of CSFB without the consent of NRG, such consent not to be unreasonably withheld. The proceeds were used to redeem $228.8 million of Second Priority Notes on September 12, 2005.

Mandatory Convertible Preferred Stock

Concurrently with this offering, NRG is offering $500 million of its % Mandatory Convertible Preferred Stock, or Mandatory Convertible Preferred Stock, subject to the underwriters’ overallotment option. The Mandatory Convertible Preferred Stock is expected to have a liquidation preference of $250 per share. Dividends will accrue and cumulate on the Mandatory Convertible Preferred Stock from the date of issuance and, to the extent that we are legally permitted to pay dividends and our board of directors, or an authorized committee of our board of directors, declares a dividend payable, we will pay dividends in cash on March 15, June 15, September 15 and December 15 of each year prior to March 15, 2009 or the following business day if the 15th is not a business day. Each share of Mandatory Convertible Preferred Stock is expected to automatically convert on March 15, 2009 into shares of common stock determined based on the price of our common stock at such time, and holders are expected to be entitled to receive an amount of cash equal to all accrued, cumulated and unpaid dividends. It is expected that, upon the occurrence of certain market conditions, NRG will be able to cause the conversion of all, but not less than all, shares of Mandatory Convertible Preferred Stock into shares of NRG common stock plus an amount of cash equal to all accrued, cumulated and unpaid dividends and the present value of all remaining future dividend payments on the Mandatory Convertible Preferred Stock through March 15, 2009. In addition, holders of the Mandatory Convertible Preferred Stock are expected to have the right to convert, at any time, the Mandatory Convertible Preferred Stock into shares of NRG common stock at the minimum conversion rate of shares of NRG common stock per share of Mandatory Convertible Preferred Stock plus an amount of cash equal to all accrued, cumulated and unpaid dividends. Holders are also expected to have the right to convert the Mandatory Convertible Preferred Stock upon certain merger events.

Whenever dividends on the Mandatory Convertible Preferred Stock or any other class or series of stock ranking on a parity with the Mandatory Convertible Preferred Stock with respect to the payment of dividends are in arrears for dividend periods, whether or not consecutive, containing in the aggregate a number of days

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equivalent to six calendar quarters, then the holders of Mandatory Convertible Preferred Stock (voting separately as a class with all other series of preferred stock upon which like voting rights have been conferred and are exercisable) are entitled to vote for the election of two of the authorized number of NRG’s directors at the next annual meeting of stockholders and at each subsequent meeting until all dividends accumulated on the Mandatory Convertible Preferred Stock have been fully paid or set apart for payment. The term of office of all directors elected by holders of the Mandatory Convertible Preferred Stock will terminate immediately upon the termination of the rights of the holders of the Mandatory Convertible Preferred Stock to vote for directors. Upon election of any additional directors, the number of directors that comprise NRG’s board of directors will be increased by the number of such additional directors.

The Mandatory Convertible Preferred Stock will be senior to all classes of common stock, on parity with the 4% Preferred Stock and the 3.625% Preferred Stock and junior to all of NRG’s existing and future debt obligations and all of NRG’s subsidiaries’ existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries.

Credit Support and Collateral Arrangement

In connection with our power generation business, we manage the commodity price risk associated with our supply activities and our electric generation facilities. This includes forward power sales, fuel and energy purchases and emission credits. In order to manage these risks, we enter into financial instruments to hedge the variability in future cash flows form forecasted sales of electricity and purchases of fuel and energy. We utilize a variety of instruments including forward contracts, futures contracts, swaps and options. Certain of these contracts allow counterparties to require the combined company to provide credit support. This credit support consists of letters of credit, cash, guarantees and junior liens on the ERCOT assets. As of September, 30, 2005, the combined company balances of the credit support provided in support of these contracts were $846 million for letters of credit, $631.4 million for cash margin, $152.4 million for parental guarantees and $2,181 million for junior liens on the assets in the ERCOT market.

The following table shows the breakdown of the combined company after giving effect to the Acquisition and Financing Transactions, balances of the credit support provided in support of the hedging contracts described above:


	September 30, 2005		December 31, 2005
	($ in millions)		($ in millions)

Letters of Credit⁽¹⁾	$	846	$	831
Cash Margin⁽¹⁾		631.4		432.5
Parental Guarantees⁽²⁾		142.1		167.1
Junior Liens on ERCOT Assets		2,181		2,221


⁽¹⁾	At December 31, 2005 and September 30, 2005, West Coast Power’s collateral posted totaled $48.4 million and $24.6 million, respectively and is not included in the table above. Of these amounts, letters of credit totaled $0 and $10.7 million, respectively and cash totaled $48.4 million and $13.9 million, respectively.

⁽²⁾	Parental guarantees were provided by either NRG Energy, Inc. or Texas Genco LLC on behalf of their subsidiaries.

NRG expects that, at the closing of the Acquisition and the Financing Transactions, the collateral arrangements described above, including 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.”

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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following discussion is a general summary of certain material United States federal income tax consequences of the purchase, ownership and disposition of the notes. This discussion applies only to a non-U.S. holder (as defined below) of a note that acquires the note pursuant to this offering at the initial offering price. This discussion is based upon laws, regulations, rulings and decisions currently in effect, all of which are subject to change, possibly with retroactive effect. This discussion is limited to investors that hold the notes as capital assets (generally for investment purposes) for United States federal income tax purposes. Furthermore, this discussion does not address all aspects of United States federal income taxation that may be applicable to investors in light of their particular circumstances, or to investors subject to special treatment under United States federal income tax law, such as financial institutions, insurance companies, tax-exempt organizations, partnerships, dealers in securities or currencies, persons deemed to sell the notes under the constructive sale provisions of the Internal Revenue Code of 1986, as amended, and persons that hold the notes as part of a straddle, hedge, conversion transaction or other integrated investment. Furthermore, except to the extent set forth below, this discussion does not address any United States federal gift tax laws or any state, local or foreign tax laws. Prospective investors are urged to consult their tax advisors regarding the United States federal, state, local and foreign income and other tax consequences of the purchase, ownership and disposition of the notes.

To ensure compliance with Treasury Department Circular 230, prospective investors in the notes are hereby notified that (A) any discussion of United States Federal tax issues in this prospectus supplement is not intended or written to be used, and cannot be used, by holders of the notes for the purpose of avoiding penalties that may be imposed on such holders under the Internal Revenue Code, (B) any discussion of United States Federal tax issues in this prospectus supplement written to support the promotion or marketing of the transactions or matters addressed herein, and (C) prospective investors in, and holders of, the notes should seek advice based on their particular circumstances from an independent tax advisor. This notice is given solely for purposes of ensuring compliance with Treasury Department Circular 230. This notice is not intended to imply, and does not imply, that any particular person, in fact, supported the promotion or marketing of any transaction or matter, and it does not itself constitute evidence that any particular person did so.

For purposes of this discussion, the term “non-U.S. holder” means a beneficial owner of a note that is not, for United States federal income tax purposes, (i) an individual who is a citizen or resident of the United States, (ii) a corporation or other entity taxable as a corporation that is created or organized under the laws of the United States or any political subdivision thereof, (iii) an estate the income of which is subject to United States federal income taxation regardless of its source, or (iv) a trust (A) if a court within the United States is able to exercise primary supervision over its administration and one or more United States persons have the authority to control all of its substantial decisions or (B) that has made a valid election to be treated as a United States person for United States federal income tax purposes.

If a partnership (including any entity or arrangement treated as a partnership for United States federal income tax purposes) owns notes, the tax treatment of a partner in the partnership will depend upon the status of the partner and the activities of the partnership. Partners in a partnership that owns the notes should consult their tax advisors as to the particular United States federal income tax consequences applicable to them.

Non-U.S. Holders


	*Interest*

A non-U.S. holder will generally not be subject to United States federal income or withholding tax on payments of interest on the notes provided that (i) such interest is not effectively connected with the conduct of a trade or business within the United States by the non-U.S. holder and (ii) the non-U.S. holder (A) does not actually or constructively own 10% or more of the total combined voting power of all classes of our voting stock, (B) is not a controlled foreign corporation related to us directly or constructively through stock ownership, and (C) satisfies certain certification requirements under penalty of perjury (generally through the provision of a properly executed Internal Revenue Service Form W-8BEN).

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If interest on the notes is not effectively connected with the conduct of a trade or business in the United States by a non-U.S. holder, but such non-U.S. holder cannot satisfy the other requirements outlined in the preceding sentence, interest on the notes will generally be subject to United States withholding tax at a 30% rate unless a treaty applies to reduce or eliminate such withholding tax and the non-U.S. holder properly certifies as to its entitlement to the treaty benefits under penalty of perjury (generally through the provision of a properly executed Internal Revenue Service Form W-8BEN). If interest on the notes is effectively connected with the conduct of a trade or business within the United States by the non-U.S. holder, and, if an income tax treaty applies, is attributable to a permanent establishment or fixed base within the United States, then the non-U.S. holder will generally be subject to United States federal income tax on such interest in the same manner as if such holder were a United States person and, in the case of a non-U.S. holder that is a foreign corporation, may also be subject to the branch profits tax at a rate of 30% (or a lower applicable treaty rate), provided that such non-U.S. holder provides a properly executed Internal Revenue Service Form W-8ECI.


	*Sale, Exchange or Other Disposition of Notes*

A non-U.S. holder will generally not be subject to United States federal withholding tax with respect to gain recognized on the sale, exchange or other disposition of notes. A non-U.S. holder will also generally not be subject to United States federal income tax with respect to such gain unless (i) the gain is effectively connected with the conduct of a trade or business within the United States by the non-U.S. holder and, if certain tax treaties apply, is attributable to a permanent establishment or fixed base within the United States, or (ii) in the case of a non-U.S. holder that is a nonresident alien individual, such holder is present in the United States for 183 or more days in the taxable year and certain other conditions are satisfied. In the case described above in (i), gain or loss recognized on the disposition of such notes will generally be subject to United States federal income taxation in the same manner as if such gain or loss were recognized by a United States person, and, in the case of a non-U.S. holder that is a foreign corporation, may also be subject to the branch profits tax at a rate of 30% (or a lower applicable treaty rate). In the case described above in (ii), the non-U.S. holder will be subject to 30% tax on any capital gain recognized on the disposition of notes, which may be offset by certain United States source capital losses.


	*Federal Estate Tax*

A note that is held (or treated as held) by an individual who, at the time of death, is not a citizen or resident of the United States (as defined for United States federal estate tax purposes) will not be subject to United States federal estate tax provided that at the time of death, (i) such individual is not a shareholder owning actually or constructively 10% or more of the total combined voting power of all classes of stock entitled to vote and (ii) payments of interest with respect to such notes would not have been effectively connected with the conduct by such individual of a trade or business in the United States.


	*Information Reporting and Backup Withholding*

A non-U.S. holder will generally be required to comply with certain certification procedures in order to establish that such holder is not a United States person in order to avoid backup withholding tax (currently at a rate of 28%) with respect to payments of principal and interest on or the proceeds of a disposition of the notes. Such certification procedures will generally be satisfied through the provision of a properly executed Internal Revenue Service Form W-8BEN (or other appropriate form). In addition, we must report annually to the Internal Revenue Service and to each non-U.S. holder the amount of any interest paid to such non-U.S. holder, regardless of whether any tax was actually withheld. Copies of the information returns reporting such interest payments and the amount of any tax withheld may also be made available to the tax authorities in the country in which a non-U.S. holder resides under the provisions of an applicable income tax treaty. Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be allowed as a refund or credit against a non-U.S. holder’s United States federal income tax liability provided the required information is provided to the Internal Revenue Service.

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UNDERWRITING

We intend to offer each series of the notes through the underwriters. Morgan Stanley & Co. Incorporated and Citigroup Global Markets Inc. are acting as representatives of the underwriters named below. Subject to the terms and conditions contained in an underwriting agreement between us and the underwriters, we have agreed to sell to the underwriters, and the underwriters severally have agreed to purchase from us, the principal amount of each series of the notes listed opposite their names below.

Principal Amount of

Floating Rate Senior Notes

Principal Amount of %

Underwriter

due 2014

Senior Notes due 2014

Senior Notes due 2016

Morgan Stanley & Co. Incorporated

Citigroup Global Markets Inc.

Lehman Brothers Inc.

Banc of America Securities LLC

Deutsche Bank Securities Inc.

Goldman, Sachs & Co.

Merrill Lynch, Pierce, Fenner & Smith
Incorporated

Total

The underwriters have agreed to purchase all of the notes sold pursuant to the underwriting agreement if any of these notes are purchased. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the non defaulting underwriters may be increased or the underwriting agreement may be terminated.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

The underwriters are offering each series of the notes, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of each series of the notes, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officers’ certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

Commissions and Discounts

The underwriters have advised us that they propose initially to offer each series of the notes to the public at the public offering price specified on the cover page of this prospectus supplement, and to dealers at that price less a concession not in excess of % of the principal amount of the 2014 floating rate notes, % of the principal amount of the 2014 fixed rate notes and % of the 2016 notes. The underwriters may allow, and the dealers may reallow, a discount not in excess of % of the principal amount of the 2014 floating rate notes, % of the principal amount of the 2014 fixed rate notes and % of the 2016 notes to other dealers. After the initial public offering, the public offering price, concession and discount may be changed.

The expenses of the offering, not including the underwriting discount, are estimated to be $ and are payable by us.

New Issue of Notes

The notes of each series are a new issue of securities with no established trading market. We do not intend to apply for listing of any series of the notes on any national securities exchange or for quotation of any

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series of the notes on any automated dealer quotation system. We have been advised by the underwriters that they presently intend to make a market in the notes of each series after completion of the offering. However, they are under no obligation to do so and may discontinue any market-making activities at any time without notice. We cannot assure that an active public market for any series of the notes will develop or that any trading market that does develop for any series of the notes will be liquid. If an active public trading market for any series of the notes does not develop, the market price and liquidity of each series of the notes may be adversely affected.

Price Stabilization and Short Positions

In connection with the offering, the underwriters are permitted to engage in transactions that stabilize the market price of the notes. Such transactions consist of bids or purchases to peg, fix or maintain the price of the notes. If the underwriters create a short position in connection with the offering, i.e., if they sell more notes than are specified on the cover page of this prospectus supplement, the underwriters may reduce that short position by purchasing notes in the open market. Purchases of a security to stabilize the price or to reduce a short position could cause the price of the security to be higher than it might be in the absence of such purchases.

Neither we nor any of the underwriters makes any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the notes. In addition, neither we nor any of the underwriters makes any representation that the underwriters will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Other Relationships

Morgan Stanley & Co. Incorporated, Citigroup Global Markets Inc., Lehman Brothers Inc., Banc of America Securities LLC, Deutsche Bank Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Goldman Sachs & Co. and certain of their affiliates are lenders under, and receive customary fees and expenses in connection with, certain of our credit facilities, including the new senior secured credit facility and the bridge loan facility. See “Description of Certain Other Indebtedness and Preferred Stock.” We have also entered into the J. Aron PPA and other agreements with J. Aron, an affiliate of Goldman, Sachs & Co., as well as hedging agreements with Deutsche Bank Securities Inc. and/or its affiliates and certain other lenders under our new senior secured credit facility. See “Business—Regional Business Descriptions—Texas (ERCOT)—J. Aron Power Purchase Agreement.”

Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us. They have received customary fees and commissions for these transactions.

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LEGAL MATTERS

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

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$3,600,000,000

NRG Energy, Inc.

$ FLOATING RATE SENIOR NOTES DUE 2014

$ % SENIOR NOTES DUE 2014

$ % SENIOR NOTES DUE 2016

PROSPECTUS SUPPLEMENT


MORGAN STANLEY	CITIGROUP

LEHMAN BROTHERS


	BANC OF AMERICA SECURITIES LLC


	DEUTSCHE BANK SECURITIES


	GOLDMAN, SACHS & CO.


	MERRILL LYNCH & CO.