10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Fiscal Year ended December 31, 2006.
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Transition period from to .

Commission file No. 001-15891

NRG Energy, Inc.

(Exact name of Registrant as specified in its charter)


Delaware		41-1724239
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
211 Carnegie Center Princeton, New Jersey (Address of principal executive offices)		08540 (Zip Code)

(609) 524-4500

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Exchange on Which Registered

Common Stock, par value $0.01		New York Stock Exchange
5.75% Mandatory Convertible Preferred Stock		New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

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

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

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

As of the last business day of the most recently completed second fiscal quarter, the aggregate market value of the common stock of the registrant held by non-affiliates was approximately $6,599,652,171 based on the closing sale price of $48.18 as reported on the New York Stock Exchange.

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

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


Class	Outstanding at February 23, 2007

Common Stock, par value $0.01 per share		122,335,466

Documents Incorporated by Reference:

Portions of the Proxy Statement for the 2007 Annual Meeting of Stockholders to be held on April 25, 2007

TABLE OF CONTENTS

INDEX


Glossary of Terms			2
PART I			7
Item 1	—	Business	7
Item 1A	—	Risk Factors	41
Item 1B	—	Unresolved Staff Comments	54
Item 2	—	Properties	54
Item 3	—	Legal Proceedings	57
Item 4	—	Submission of Matters to a Vote of Security Holders	61
PART II			61
Item 5	—	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	61
Item 6	—	Selected Financial Data	64
Item 7	—	Management’s Discussion and Analysis of Financial Condition and Results of Operations	67
Item 7A	—	Quantitative and Qualitative Disclosures about Market Risk	115
Item 8	—	Financial Statements and Supplementary Data	119
Item 9	—	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	119
Item 9A	—	Controls and Procedures	119
Item 9B	—	Other Information	120
PART III			120
Item 10	—	Directors and Executive Officers of the Registrant	120
Item 11	—	Executive Compensation	120
Item 12	—	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120
Item 13	—	Certain Relationships and Related Transactions	120
Item 14	—	Principal Accountant Fees and Services	120
PART IV			121
Item 15	—	Exhibits and Financial Statement Schedules	121
EXHIBIT INDEX			218
EX-10.38: NEO 2006 AIP PAYOUT AND 2007 BASE SALARY TABLE
EX-10.39: NRG ENERGY, INC. EXECUTIVE AND KEY MANAGEMENT CHANGE-IN-CONTROL AND GENERAL SEVERANCE PLAN
EX-12.1: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
EX-12.2: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDEND REQUIREMENTS
EX-21: SUBSIDIARIES OF NRG ENERGY INC
EX-23.1: CONSENT OF KPMG LLP
EX-31.1: CERTIFICATION
EX-31.2: CERTIFICATION
EX-31.3: CERTIFICATION
EX-32: CERTIFICATION

Glossary of Terms

Glossary of Terms — (continued)

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


ABWR		Advanced Boiling Water Reactor
Acquisition		February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Company’s Texas region
Acquisition Agreement		Acquisition Agreement dated September 30, 2005 underlying the February 2, 2006 acquisition of the Company’s Texas region
AMA		Administrative Management Agreement between NRG Development Company, Inc. and West Coast Power, LLC
APB		Accounting Principles Board
APB 18		APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock”
Average gross heat rate		The product of dividing (a) fuel consumed in BTU’s by (b) KWh generated
BACT		Best Available Control Technology
BART		Best Available Retrofit Technology
Baseload capacity		Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
BTA		Best Technology Available
BTU		British Thermal Unit
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
CAMR		Clean Air Mercury Rule
Capacity factor		The ratio of the actual net electricity generated to the energy that could have been generated at continuous full-power operation during the year
Capital Allocation Program		Share repurchase program entered into August 2006
CDWR		California Department of Water Resources
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act
CL&P		Connecticut Light & Power
CO₂		Carbon dioxide
CPUC		California Public Utilities Commission
Derate		A derate exists whenever a generating unit is not capable of operating at its tested dependable maximum net capability
DNREC		Delaware Department of Natural Resources and Environmental Control
EAF		The total available hours a unit is available in a year minus the sum of all partial outage events in a year converted to equivalent hours, expressed as a percent of all hours in the year
EFOR		Equivalent Forced Outage Rates — considers the equivalent impact that forced de-ratings have in addition to full forced outages
EITF		Emerging Issues Task Force
EITF 02-3		EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”
EPAct of 2005		Energy Policy Act of 2005
EPC		Engineering, Procurement and Construction

ERCOT
Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas

ERO
Energy Reliability Organization

EWG
Exempt Wholesale Generator

Expected annual baseload generation
The net baseload capacity limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages)

FASB
Financial Accounting Standards Board, the designated organization for establishing standards for financial accounting and reporting

FERC
Federal Energy Regulatory Commission

FGD
Flue Gas Desulphurization

FIN
FASB Interpretation

FIN 45
FIN No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”

FIP
Federal Implementation Plan

Fresh Start
Reporting requirements as defined by SOP 90-7

GHG
Greenhouse Gases

Hedge Reset
Net settlement of long-term power contracts and gas swaps by negotiating prices to current market completed in November 2006

Hg
Mercury

ICT
Independent Coordinator of Transmission

IGCC
Integrated Gasification Combined Cycle

IRS
Internal Revenue Service

ISO
Independent System Operator, also referred to as Regional Transmission Organizations, or RTO

ISO-NE
ISO New England, Inc.

ITISA
Itiquira Energetica S.A.

kW
Kilowatts

KWh
Kilowatt-hours

LADEQ
Louisiana Department of Environmental Quality

LFRM
Locational Factor Reserve Market

LIBOR
London Inter-Bank Offered Rate

LNB/OFA
Low NOx Burner with Over Fire Air

LSE
Load-Serving Entity

MACT
Maximum Achievable Control Technology

MADEP
Massachusetts Department of Environmental Protection

MDL
Multi-District Litigation

Merit Order
A term used for the ranking of power stations in terms of increasing order of fuel costs

MIBRAG
Mitteldeutsche Braunkohlengesellschaft mbH

Moody’s
Moody’s Investors Services, Inc., a credit rating agency

MMBtu
Million British Thermal Units

MRTU
Market Redesign and Technology Upgrade

MW
Megawatts

MWh
Saleable megawatt hours net of internal/parasitic load megawatt-hours

NAAQS
National Ambient Air Quality Standards

Net baseload capacity
Nominal summer net megawatt capacity of power generation adjusted for ownership and parasitic load, and excluding capacity from mothballed units as of December 31, 2006

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

Net Generating Capacity
Nominal summer capacity, net of auxiliary power

New York Rest of State
New York State excluding New York City

NiMo
Niagara Mohawk Power Corporation

NOx
Nitrogen oxide

NOL
Net Operating Loss

NOV
Notice of Violation

NRC
United States Nuclear Regulatory Commission

NSR
New Source Review

NYPA
New York Power Authority

NYISO
New York Independent System Operator

NYSDEC
New York Department of Environmental Conservation

OCI
Other Comprehensive Income

OTC
Ozone Transport Commission

Phase II 316(b) Rule
A section of the Clean Water Act regulating cooling water intake structures

PJM
PJM Interconnection, LLC

PJM Market
The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia

PM _(2.5)
Fine particulate matter

PMI
NRG Power Marketing, Inc., a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manage, all commodity trading and hedging for NRG

Powder River Basin, or PRB, Coal
Coal produced in the northeastern Wyoming and southeastern Montana, which has low sulfur content

PPA
Power Purchase Agreement

PSD
Prevention of Significant Deterioration

PUCT
Public Utility Commission of Texas

PUHCA
Public Utility Holding Company Act of 2005

PURPA
Public Utility Regulatory Policy Act of 2005

RCRA
Resource Conservation and Recovery Act

RECLAIM
Regional Clean Air Incentives Market

Repowering NRG
Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency

RFP
Request for proposal

RGGI
Regional Greenhouse Gas Initiative

RMR
Reliability Must-Run

ROIC
Return on invested capital

RTC
RECLAIM Trading Credit

RTO
Regional Transmission Organization, also referred to as an ISO

S&P
Standard & Poor’s, a credit rating agency

SARA
Superfund Amendments and Reauthorization Act of 1986

Sarbanes-Oxley
Sarbanes — Oxley Act of 2002

SCAQMD
South Coast Air Quality Management District

Schkopau
Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which NRG has a 41.9% interest

SCR
Selective Catalytic Reduction

SDG&E
San Diego Gas & Electric

SEC
United States Securities and Exchange Commission

Sellers
Former holders of Texas Genco LLC shares

SERC
Southeastern Electric Reliability Council/Entergy

SFAS
Statement of Financial Accounting Standards issued by the FASB

SFAS 71
SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”

SFAS 87
SFAS No. 87, “Employers’ Accounting for Pensions”

SFAS 106
SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”

SFAS 109
SFAS No. 109, “Accounting for Income Taxes”

SFAS 123
SFAS No. 123, “Accounting for Stock-Based Compensation”

SFAS 123R
SFAS No. 123 (revised 2004), “Share-Based Payment”

SFAS 133
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”

SFAS 137
SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133”

SFAS 138
SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of FASB Statement No. 133”

SFAS 142
SFAS No. 142, “Goodwill and Other Intangible Assets”

SFAS 143
SFAS No. 143, “Accounting for Asset Retirement Obligations”

SFAS 144
SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”

SFAS 149
SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”

SFAS 158
SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)”

SFAS 159
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115”

SNCR
Selective non-catalytic reduction

SIP
State Implementation Plan

SO₂
Sulfur dioxide

SOP
Statement of Position issued by the American Institute of Certified Public Accountants

SOP 90-7
Statement of Position 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”

SPP
Southwest Power Pool

STP
South Texas Project — Nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest

STPNOC
South Texas Project Nuclear Operating Company

TCEQ
Texas Commission on Environmental Quality

Texas Genco
Texas Genco LLC, now referred to as the Company’s Texas region

Uprate
A sustainable increase in the electrical rating of a generating facility

US
United States of America

USEPA
United States Environmental Protection Agency

U.S. GAAP
Accounting principles generally accepted in the United States

VAR
Value at Risk

Virtual Units
Products sold with scheduling characteristics for energy and ancillary services that are based on an underlying unit physical characteristic

VOC
Volatile Organic Carbon

WCP
WCP (Generation) Holdings, Inc.

PART I

Item 1 — Business

General

NRG Energy, Inc., NRG, or the Company, is a wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is primarily engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the United States and internationally. As of December 31, 2006, NRG had a total global portfolio of 223 active operating generation units at 51 power generation plants, with an aggregate generation capacity of approximately 24,175 MW. Within the United States, the Company has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,940 MW of generation capacity in 207 active generating units at 45 plants. These power generation facilities are primarily located in Texas (approximately 10,760 MW), and the Northeast (approximately 7,240 MW), South Central (approximately 2,850 MW), and the West (approximately 1,965 MW) regions of the United States, with approximately 125 MW from the Company’s thermal assets. NRG’s principal domestic power plants consist of a diversified mix of natural gas-, coal-, oil-fired and nuclear facilities, representing approximately 45%, 34%, 16% and 5% of the Company’s total domestic generation capacity, respectively. In addition, 15% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option, and consist primarily of baseload, intermediate and peaking power generation facilities, which are referred to as the merit order, and also include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company’s revenues and provides a stable source of cash flow. In addition, NRG’s diverse generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability. In addition, NRG is pursuing opportunities to repower existing facilities and develop new generation capacity in markets in which NRG currently owns assets in an initiative referred to as Repowering NRG. In connection with NRG’s acquisition of Padoma Wind Power LLC, the Company has and will continue to actively evaluate and potentially develop or construct domestic terrestrial wind projects as part of the Repowering NRG program.

Business Strategy

NRG’s strategy is to optimize the value of the Company’s generation assets while using its asset base as a platform for growth and enhanced financial performance which can be sustained and expanded upon in the years to come. NRG plans to maintain and enhance the Company’s 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 NRG’s existing customer base and other entities that offer load or otherwise consume wholesale electricity products and services in bulk. NRG’s strategy includes the following elements:

Pursue additional growth opportunities at existing sites — NRG is favorably positioned to pursue growth opportunities through expansion of its existing generating capacity and development of new generating capacity at its existing facilities. NRG intends to invest in its existing assets through plant improvements, repowerings, brownfield development and site expansions to meet anticipated requirements for additional capacity in NRG’s core markets. In furtherance of this goal, NRG has initiated a company-wide program, known as Repowering NRG, to develop, construct and operate new and enhanced power generation facilities at its existing sites, with an emphasis on new baseload capacity that is supported by long-term power sales agreements and financed with limited or non-recourse project financing. NRG expects that these efforts will provide one or more of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; an improved ability to dispatch economically across the merit order; increased technological and fuel diversity; and reduced environmental impacts, including facilities that either have near zero greenhouse gas emissions or can be equipped to capture and sequester greenhouse gas emissions.

Increase value from existing assets — NRG has a highly diversified portfolio of power generation assets in terms of region, fuel-type and dispatch levels. NRG will continue to focus on extracting value from its portfolio by improving plant performance, reducing costs and harnessing the Company’s advantages of scale in the procurement of fuels and other commodities, parts and services, and in doing so improve the Company’s return on invested capital, or ROIC — a strategy that NRG has branded FORNRG, or Focus on ROIC@NRG.

Maintain financial strength and flexibility — NRG remains focused on cash flow and maintaining appropriate levels of liquidity, debt and equity in order to ensure continued access to capital for investment, to enhance risk-adjusted returns and to provide flexibility in executing NRG’s business strategy. NRG will continue to focus on maintaining operational and financial controls designed to ensure that the Company’s financial position remains strong. At the same time, NRG expects to continue its practice of returning excess cash flows to its debt and equity investors on a regular basis.

Reduce the volatility of the Company’s cash flows through asset-based commodity hedging activities — NRG 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 the Company’s physical and contractual assets. The Company’s marketing and hedging philosophy is centered on generating stable returns from its portfolio of baseload power generation assets while preserving an ability to capitalize on strong spot market conditions and to capture the extrinsic value of the Company’s intermediate and peaking facilities and portions of its baseload fleet. NRG believes that it can successfully execute this strategy by leveraging its expertise in marketing power and ancillary services, its knowledge of markets, its balanced financial structure and its diverse portfolio of power generation assets.

Pursue strategic acquisitions and divestures — NRG will continue to pursue selective acquisitions, joint ventures and divestitures to enhance its asset mix and competitive position in the Company’s core regions. NRG intends to concentrate on opportunities that present attractive risk-adjusted returns. NRG will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures.

Competition and Competitive Strengths

Competition — Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. NRG competes on the basis of the location of its plants and owning multiple plants in its regions, which increases the stability and reliability of its energy supply. Wholesale power generation is basically a local business that is currently highly fragmented relative to other commodity industries and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies NRG competes against depending on the market.

Scale and diversity of assets — NRG has one of the largest and most diversified power generation portfolios in the United States, with approximately 22,940 MW of generation capacity in 207 active generating units at 45 plants as of December 31, 2006. The Company’s power generation assets are diversified by fuel-type, dispatch level and region, which help mitigate the risks associated with fuel price volatility and market demand cycles. NRG’s U.S. baseload facilities, which consist of approximately 8,745 MW of generation capacity measured as of December 31, 2006, provide the Company with a significant source of stable cash flow, while its intermediate and peaking facilities, with approximately 14,195 MW of generation capacity as of December 31, 2006, provide NRG with opportunities to capture the significant upside potential that can arise from time to time during periods of high demand. In addition, approximately 15% of the Company’s domestic generation facilities have dual or multiple fuel capability, which allows most of these plants to dispatch with the lowest cost fuel option.

The following chart demonstrates the diversification of NRG’s domestic power generation assets as of December 31, 2006:

Reliability of future cash flows — NRG has sold forward or otherwise hedged a significant portion of its expected baseload generation capacity through 2012. The Company has the capacity and intent to enter into additional hedges in later years when market conditions are favorable. In addition, as of December 31, 2006, the Company has purchased forward under fixed price contracts (with contractually-specified price escalators) to provide fuel for approximately 73% of its expected baseload coal generation output from 2007 to 2012. These forward positions provide a stable and reliable source of future cash flow for NRG’s investors, while preserving a portion of its generation portfolio for opportunistic sales to take advantage of market dynamics.

Favorable market dynamics for baseload power plants — In 2006, approximately 83% of the Company’s domestic generation was fueled by coal or nuclear fuel. In many of the competitive markets where NRG operates, the price of power is typically set by the marginal costs of natural gas-fired and oil-fired power plants that currently have substantially higher variable costs than solid fuel baseload power plants. As a result of NRG’s lower marginal cost for baseload coal and nuclear generation assets, the Company expects these ERCOT assets to generate power nearly 100% of the time they are available.

Locational advantages — Many of NRG’s 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. NRG has generation assets located within New York City, southwestern Connecticut, Houston and the Los Angeles and San Diego load basins; all areas with constraints on the transmission of electricity. This gives the Company the opportunity 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. These facilities are often ideally situated for repowering or the addition of new capacity, as well, because their location and existing infrastructure give them significant advantages over newly developed sites in their regions.

Performance Metrics

The following table contains a summary of NRG’s operating revenues by segment for the year ended December 31, 2006. The table also reflects the realignment of the Company’s new segment structure as discussed in Item 15 — Note 17, Segment Reporting, to the Consolidated Financial Statements.


					Risk													Total
	Energy		Capacity		Management			Contract		Thermal		Hedge			Other			Operating
Region	Revenues		Revenues		Activities			Amortization		Revenues		Reset			Revenues^(c)			Revenues
	(In millions)

Texas^(a)	$	1,726	$	849	$	(30	)	$	609	$	—	$	(129	)	$	63		$	3,088
Northeast		966		321		144			—		—		—			112			1,543
South Central		334		199		13			19		—		—			5			570
West^(b)		75		68		(3	)		—		—		—			6			146
International		80		79		—			—		—		—			14			173
Thermal		12		—		—			—		124		—			16			152
Corporate/Eliminations		—		—		—			—		—		—			(49	)		(49	)

Total	$	3,193	$	1,516	$	124		$	628	$	124	$	(129	)	$	167		$	5,623


(a)	For the period February 2, 2006 — December 31, 2006.

(b)	Includes fully consolidated results of WCP for the period April 1, 2006 — December 31, 2006.

(c)	Includes operations and maintenance fees, sale of natural gas, sale of emission allowances, and revenues from ancillary services.

In understanding NRG’s business, the Company believes that certain performance metrics are particularly important. These are industry statistics defined by the North American Electric Reliability Council and are more fully described below:

Annual Equivalent Availability Factor, or EAF: The percentage of time in one year that a generating unit is able to produce electricity, adjusted to take into account times when the unit is unavailable and able to produce its full rated output.

Gross heat rate: NRG calculates the gross heat rate for the Company’s fossil-fired power plants by dividing the average amount of fuel in BTUs that it takes to generate one kWh of electricity by the generator output.

Net Capacity Factor: The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.

The tables below present the North American power generation performance metrics for the Company’s power plants discussed above for the years ended December 31, 2006 and 2005:


	Year Ended December 31, 2006
					Annual
			Net		Equivalent			Average Net
	Net Owned		Generation		Availability			Heat Rate		Net Capacity
Region	Capacity (MW)		(MWh)		Factor			Btu/KWh		Factor
	(In thousands of MWh)

Texas^(a)		10,760		44,910		91.0	%		10,300		41.0	%
Northeast^(b)		7,240		13,309		85.8			10,900		18.8
South Central		2,850		11,036		94.3			10,400		47.2
West^(c)		1,965		1,901		89.1	%		11,400		15.1	%


	Year Ended December 31, 2005
					Annual
			Net		Equivalent			Average Net
	Net Owned		Generation		Availability			Heat Rate		Net Capacity
Region	Capacity (MW)		(MWh)		Factor			Btu/KWh		Factor
	(In thousands of MWh)

Northeast^(b)		7,099		16,246		87.2	%		11,146		22.9	%
South Central		2,395		10,009		90.9			10,518		50.6
West^(d)		1,044		1,794		86.5	%		11,109		18.0	%


(a)	For the period February 2, 2006 through December 31, 2006.

(b)	Factor data and heat rate does not include the Keystone and Conemaugh facilities.

(c)	Includes fully consolidated results of WCP for the period April 1, 2006 — December 31, 2006.

(d)	Includes 50% of the generation owned through NRG’s WCP partnership.

Generation Asset Overview

NRG has a significant power generation presence in major competitive power markets of the United States as set forth in the map below:

As of December 31, 2006, the Company’s power generation assets consisted of approximately 10,470 MW of gas-fired; 7,815 MW coal-fired; 3,555 MW of oil-fired and 1,100 MW of nuclear generating capacity in the United States. In addition, NRG also owns approximately 1,230 MW of thermal capacity as well as 1,235 MW of power generation capacity overseas. The Company’s North American power generation portfolio by dispatch level is comprised of approximately 39% baseload, 37% intermediate and 24% of peaking units. NRG uses hedging strategies which may include power and natural gas forward sales contracts to manage the commodity price risk associated with the Company’s generation assets, and are primarily around the Company’s baseload generation assets. In addition, these hedging strategies also provide for stable cash flow and earnings predictability.

The following table summarizes NRG’s North American baseload capacity and the corresponding revenues resulting from baseload hedge agreements extending beyond December 31, 2006 through 2012:


																			Annual
																			Average for
	2007			2008			2009			2010			2011			2012			2007-2012
	(In millions unless otherwise stated)

Net Baseload Capacity (MW)		8,800			8,730			8,730			8,621			8,621			8,621			8,687
Forecasted Baseload Capacity (MW)		7,493			7,394			7,358			7,305			7,208			7,269			7,338
Total Baseload Sales (MW)^(a)		7,263			6,105			5,370			4,334			4,679			1,767			4,920
Percentage Baseload Capacity Sold Forward^(b)		97	%		83	%		73	%		59	%		65	%		24	%		67	%
Total Forward Hedged Revenues^(c)(d)	$	3,582		$	2,803		$	2,524		$	1,931		$	1,934		$	617		$	2,232
Weighted Average Hedged Price ($ per MWh)^(c)	$	56		$	52		$	54		$	51		$	47		$	40		$	50
Weighted Average Hedged Price ($ per MWh) excluding South Central region^(d)	$	61		$	57		$	59		$	56		$	51		$	49		$	56


(a)		Includes amounts under fixed price power sales contracts and amounts financially hedged under natural gas contracts. The forward natural gas quantities are reflected in equivalent MWh and are derived by first dividing the quantity of MMBtu of natural gas hedged by the forward market implied heat rate as of December 31, 2006 to arrive at the equivalent MWh hedged which is then divided by 8,760 hours (total hours in a year) to arrive at MW hedged.

(b)		Percentage hedged is based on total MW sold as power and gas converted using the method as described in (a) above divided by the forecasted baseload capacity.

(c)		Represents all North American baseload sales including power contract prices in the Texas and South Central regions which are comprised of a fixed demand charge exclusive of a fixed energy charge, with the transaction price related to these contracts being the sum of both charges.

(d)		The South Central region’s weighted average hedged prices ranges from $33/MWh — $35/MWh due to legacy cooperative load contracts entered into at prices significantly below current market levels.

(e)		Includes contracted revenues subject to hedge accounting, market-to-market, and normal purchases and normal sales accounting treatment.

The following is a discussion of NRG’s generation assets by segment for the year ended December 31, 2006. This discussion reflects the realignment of the Company’s new segment structure as discussed in Item 15 — Note 17, Segment Reporting, to the Consolidated Financial Statements in this Form 10-K.

Texas Region — As of December 31, 2006, NRG’s generation assets in the Texas region consisted of approximately 5,280 MW of baseload generation assets and approximately 5,480 MW of intermediate and peaking natural gas-fired assets. NRG realizes a substantial portion of its revenue and cash flow from the sale of power from the Company’s three baseload power plants located in the ERCOT market that use solid fuel: W. A. Parish which uses coal, Limestone which uses lignite and coal, and an undivided 44% interest in two nuclear generating units at STP which uses nuclear fuel. Power plants are generally dispatched in order of lowest operating cost and as of December 31, 2006, approximately 72% of the net generation capacity in the ERCOT market was natural gas-fired. In the current natural gas price environment, NRG’s three baseload facilities have significantly lower operating costs than gas plants. NRG expects these three facilities to operate nearly 100% of the time, subject to planned and forced outages.

Northeast Region — As of December 31, 2006, NRG generation assets in the Northeast region of the United States consisted of approximately 7,240 MW generation capacity from the Company’s power plants within the control areas of the New York Independent System Operator, or NYISO, the Independent System Operator — New England, or ISO-NE, and the PJM Interconnection LLC, or PJM. Certain of these assets are located in transmission constrained areas, including approximately 1,415 MW of in-city New York City generation capacity and approximately 535 MW of southwest Connecticut generation capacity. As of December 31, 2006, NRG’s generation assets in the Northeast region consisted of approximately 1,960 MW of baseload generation assets and approximately 5,280 MW of intermediate and peaking assets.

South Central Region — As of December 31, 2006, NRG generation assets in the South Central region of the United States consisted of approximately 2,850 MW of generation capacity, making NRG the third largest generator in the Southeastern Electric Reliability Council/Entergy, or SERC-Entergy, region. The Company’s generation assets in the South Central region consists of its primary asset, Big Cajun II, a coal-fired plant located near Baton Rouge, Louisiana which has approximately 1,490 MW of baseload generation assets and 1,360 MW of intermediate and peaking assets. An annual average of 1,164 MW of baseload generation capacity has been contracted through eleven cooperatives within the region through 2025.

West Region — On March 31, 2006, NRG acquired Dynegy, Inc.’s 50% ownership interest in WCP Holdings to become sole owner of power plants with generation capacity of approximately 1,825 MW in the West region of the United States. These assets, combined with approximately 140 MW of existing wholly owned capacity in the Western Electricity Coordinating Council, brings NRG’s total generation to approximately 1,965 MW in the West region as of December 31, 2006. On January 3, 2007, NRG completed the sale of the Red Bluff and Chowchilla II power plants with a combined generation capacity of approximately 95 MW to an entity controlled by Wayzata Investment Partners LLC. Excluding these two plants, total generation for the West region was 1,870 MW.

International Region — As of December 31, 2006, NRG had net ownership in approximately 1,235 MW of power generating capacity outside the United States in Australia, Brazil, and Germany. In addition to traditional power generation facilities, NRG also owned equity interests in certain coal mines in Germany.

Thermal — NRG owns thermal and chilled water businesses that generate approximately 1,230 MW thermal equivalents. In addition, NRG’s thermal segment owns certain power plants with approximately 125 MW of power generating capacity located in Delaware and in Pennsylvania.

Dispositions of Non-Strategic Assets

During 2006, NRG continued its efforts to divest the Company’s interests in non-core assets. As of December 31, 2006, NRG had sold a number of consolidated businesses and equity investments in an effort to reduce the Company’s debt, improve liquidity and rationalize NRG’s investments.

Dispositions completed during 2006 are summarized in the following table:


			Closing			Gain/(Loss)			Debt
Asset	Type	Segment^(b)	Date	Proceeds		on Disposition			Reduction
				(In millions)

Rocky Road	Equity investment	Corporate	03/31/06	$	45	$	—		$	—
Audrain^(a)	Discontinued operation	Corporate	03/29/06		115		15			240
Cadillac	Equity investment	Corporate	04/13/06		11		11			—
James River	Equity investment	Corporate	05/15/06		8		(6	)		—
Latin American Funds	Equity investment	International	06/30/06		23		3			—
Flinders	Discontinued operation	International	08/30/06		242		60			183
Resource Recovery	Discontinued operation	Corporate	11/08/06		22		5			—

Total				$	466	$	88		$	423


(a)		Of the $115 million in cash proceeds, approximately $20 million was paid to NRG with the balance paid to the lenders of NRG Financial Company I LLC.

(b)		Reflects realignment of the Company’s business segments during the fourth quarter 2006.

In addition, on January 3, 2007, NRG completed the sale of Red Bluff and Chowchilla II power plants to an entity controlled by Wayzata Investment Partners LLC.

Repowering NRG Program

NRG has announced a comprehensive portfolio redevelopment program, referred to as Repowering NRG, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity at NRG’s existing domestic sites to meet the growing demand in the Company’s core markets. Through the Repowering NRG program, the Company anticipates retiring certain existing units and adding up to approximately 10,350 MW of new generation, with an emphasis on new baseload capacity that is supported by long-term power purchase agreements, or PPAs, and financed with limited or non-recourse project financing. NRG expects that these repowering investments will provide one or more of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; an improved ability to dispatch economically across the merit order; increased technological and fuel diversity; and reduced environmental impacts. The Company expects that the Repowering NRG program will also result in indirect benefits, including the continuation of operations and retention of key personnel at its existing facilities.

A critical aspect of the Repowering NRG program is the extent to which the Company seeks to reduce the carbon intensity of the Company’s generation fleet by developing generating facilities with zero CO₂ and low CO₂ emissions, as well as facilities that can be equipped for CO₂ separation and sequestration. As a result, the Repowering NRG program is important not only to NRG but also to the power industry in general. The American power industry is the primary emitter of CO₂ in the largest CO₂ emitting market on earth. As the power industry takes steps to develop the next wave of power generation infrastructure, technology and capital allocation decisions will be made which could impact GHG from power generation by either making the situation significantly worse or significantly better in terms of CO₂ intensity. Although there is no current technological solution to retro-fit existing fossil-fueled technology to capture GHG from power plant flues, there are commercially available large scale technologies for new plants that can generate power with much lower GHG emissions than traditional coal-fired generation. Given that new generation units have useful lives of up to 50 years, NRG will give full consideration to CO₂ and other emissions that contribute to GHG when making its long-term investment decisions.

As part of the Repowering NRG program, NRG is pursuing a five-pronged GHG emissions strategy as follows:

1. Nuclear development — a known, reliable source of electricity with zero emissions.

2. IGCC development — coal-fueled baseload generation designed to reduce the intensity of CO₂ emissions.

3. Wind development — renewable energy for the future with zero emissions.

4. Public outreach — NRG will work with government, industry and public interest groups to formulate and implement an economically and environmentally responsible GHG policy.

5. Bridge the technology gap — The Company has launched a number of initiatives to improve technology through R&D particularly post-combustion carbon capture, developing underground sequestration, and finding offsets that will mitigate CO₂ production.

NRG estimates that the Repowering NRG program, if fully implemented as currently proposed, could have a total capital cost of approximately $16 billion. While NRG believes it is extremely unlikely that the program will be fully implemented as currently proposed, the Company nonetheless expects the overall capital expenditures in connection with the program will be substantial. NRG expects to mitigate the capital cost of the program through equity partnerships and public-private partnerships, as well as through development fees for certain projects. To mitigate the investment risks, NRG anticipates entering into long-term PPAs and engineering, procurement and construction, or EPC, contracts. The Company currently expects its share of cash contributions for the projects included in the Repowering NRG program to range between $500 million and $2.0 billion over the next decade. However, the proposed increase in generation capacity and capital costs resulting from Repowering NRG could change as proposed projects are included or removed from the program due to a number of factors, including successfully obtaining required permits and long term PPAs, availability of financing on favorable terms, and

achieving targeted project returns. The projects that have been identified as part of the Repowering NRG program are subject to change as NRG refines the program to take into account the success rate for completion of projects, changes in the targeted minimum return thresholds, and evolving market dynamics.

The following table summarizes the current projects included in the Repowering NRG program by fuel-type:


Fuel-type	MW

Gas		4,050
Nuclear		2,700
Coal Gasification, or IGCC		1,500
Solid Fuel		1,800
Wind		300

Total		10,350

Commercial Operations Overview

NRG seeks to maximize profitability and manage cash flow volatility through the marketing, trading and sale of energy, capacity and ancillary services into spot, intermediate and long-term markets and through the active management and trading of emissions allowances, fuel supplies and transportation-related services. The Company’s principal objectives are the realization of the full market value of its asset base, including the capture of its extrinsic value, the management and mitigation of commodity market risk and the reduction of cash flow volatility over time.

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

Fuel Supply and Transportation

NRG’s fuel requirements consist primarily of nuclear fuel and various forms of fossil fuel including oil, natural gas and coal, including lignite. The prices of oil, natural gas and coal are subject to macro- and micro-economic forces that can change dramatically in both the short- and long-term. The Company obtains its oil, natural gas and coal from multiple suppliers and transportation sources. Although availability is generally not an issue, localized shortages, transportation availability and supplier financial stability issues can and do occur. Issues related to the sources and availability of raw materials is fairly uniform across the Company’s business segments.

Coal — The Company is largely hedged for its domestic coal consumption over the next few years. Coal hedging is dynamic based on forecasted generation and market volatility. As of December 31, 2006, NRG has purchased forward under contracts to provide fuel for approximately 73% on average of the Company’s requirement from 2007 through 2012; 111% in 2007 (includes inventory build in excess of the Company’s forecasted coal burn requirements), 89% in 2008, 81% in 2009, 56% in 2010, 51% in 2011 and 50% in years 2012 and beyond. NRG arranges for the purchase, transportation and delivery of coal for the Company’s baseload coal plants via a variety of coal purchase agreements, rail transportation agreements and rail car lease arrangements. The Company purchased approximately 35 million tons of coal in 2006, which would rank NRG as one of the largest coal purchasers in the United States.

As of December 31, 2006, NRG had approximately 7,600 privately leased or owned rail cars in the Company’s transportation fleet. In addition, the Company intends to enter into contracts for delivery of additional 1,100 rail cars within the next year of which approximately 1,000 will replace a portion of the Company’s existing rail car fleet. NRG has entered into rail transportation agreements with varying tenures that provide for substantially all of the Company’s rail transportation requirements through the end of the decade.

Natural Gas — NRG operates a fleet of natural gas plants in the Texas, Northeast, South Central and West regions which are comprised of primarily peaking assets that run in times of high power demand. Due to the

uncertainty of their dispatch, the fuel needs are managed on a spot basis as it is not prudent to forward purchase fixed price gas on units that may not run. The Company contracts for gas storage services as well as gas transportation services to ensure delivery of gas when needed.

Nuclear Fuel — STP’s owners satisfy STP’s fuel supply requirements by (1) acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride, (2) contracting for enrichment of uranium hexafluoride and (3) contracting for fabrication of nuclear fuel assemblies. NRG is party to a number of long-term forward purchase contracts with many of the world’s largest suppliers covering STP requirements for uranium and conversion services for the next five years, and with substantial portions of STP’s requirements procured through the end of the next decade. NRG is party to long term contracts to procure STP’s requirements for enrichment services and fuel fabrication for the life of the operating license.

Seasonality and Price Volatility

Annual and quarterly operating results can be significantly affected by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. NRG derives a majority of its annual revenues in the months of May through September, when demand for electricity is the highest in its core domestic markets. Further, power price volatility is generally higher in the summer months, traditionally NRG’s most important season. The Company’s second most important season is the winter months of December through March when volatility and price spikes in underlying fuel prices have tended to drive seasonal electricity prices. Issues related to seasonality and price volatility are fairly uniform across the Company’s business segments.

Plant Operations Overview

NRG provides support services to the Company’s 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 the Company. Performance goals are set for equivalent forced outage rates, or EFOR, availability, procurement costs, operating costs and safety.

Support services include safety, security, and systems. These services also include operations strategic planning and the development and dissemination of consistent policies and practices relating to plant operations.

To support the Repowering NRG program, the Company has organized its project execution process into one centralized group consisting of engineering, procurement and construction. This group has regional engineering functions combined with corporate project engineering, project management, procurement and construction functions to provide a consistent and standardized approach to the way repowering work is executed. This has enabled NRG to leverage both the procurement of major equipment as well as outside engineering resources through standardized work processes and work packaging. This process has led to identifying commonality in major equipment that can be procured from Original Equipment Manufacturers, or OEMs, as well as design processes. As a result, NRG expects to achieve cost savings by minimizing the number of outside engineering and construction resources, which provide detailed design and construction services required to complete projects, in addition to and by ensuring a consistent engineering and construction approach across all projects.

Performance Improvement, 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 under way at NRG’s major baseload facilities, including forced outage reductions, achieving full load, station service reductions, and heat rate improvements. Qualifying projects are also underway at the Princeton headquarters, which have reduced paperwork burdens as well as tax and insurance costs.

During the second quarter 2006, NRG expanded the program to include the Texas Genco assets and extended the term of the program to 2009, with anticipated annual savings in excess of $200 million to be achieved through

continued benefits from operational performance, cost synergies and purchasing-related initiatives, plus $50 million in cash savings. For 2006, the program has demonstrated benefits of over $140 million from operational performance, cost synergies and purchasing-related initiatives, plus $61 million in cash savings, putting the Company on track to meet its 2009 target.

Environmental Capital Expenditures

Based on current rules, technology and plans, NRG has estimated that approximately $1.28 billion of environmental capital expenditures will be incurred during the period 2007 through 2012, primarily related to installation of particulate, SO₂, NO_x, and mercury controls to comply with the Clean Air Interstate Rule and Clean Air Mercury rules or alternative State regimes, to the extent more stringent than the USEPA rules, as well as installation of BTA under the Phase II 316(b) Rule. Changes to regulations or market conditions could result in changes to installed equipment timing or associated costs.

The following table summarizes the estimated environmental capital expenditures for the referenced period, by region and by year:


	Texas		Northeast		South Central		Other		Total
	(In millions)

2007	$	9	$	118	$	40	$	10	$	177
2008		16		183		92		10		301
2009		19		183		167		5		374
2010		26		144		86		4		260
2011		19		30		64		1		114
2012		13		3		34		—		50

Total	$	102	$	661	$	483	$	30	$	1,276

NRG is working to reduce a portion of the above environmental capital expenditures. First, NRG has the ability to monetize a portion of the Company’s excess allowances over the 2007-2012 timeframe and still hold sufficient allowances to operate the fleet with proposed controls through at least 2020. Second, NRG’s current contracts with the Company’s rural electrical customers in the South Central region allow for recovery of a significant portion of the costs, along with a capital return incurred by complying with new laws, including interest over the asset life of the required expenditures. Actual recoveries will depend, among other things, on the duration of the contracts and the treatment of these expenditures.

Employees

As of December 31, 2006, NRG had 3,217 employees, approximately 1,622 of whom were covered by U.S. bargaining agreements. During 2006, the Company did not experience any significant labor stoppages or labor disputes at any of its facilities.

Regional Business Descriptions

NRG is organized into business units as described below, with each of the Company’s core regions operating as a separate business segment. As of December 31, 2006, NRG realigned the Company’s segment structure. For a further discussion on the realignment of the Company’s operating segments and for financial information on NRG’s operations by segment, see Item 15 — Note 17, Segment Reporting, to the Consolidated Financial Statements.

TEXAS

NRG’s largest business unit is located in Texas and is comprised of investments in generation facilities located in the physical control areas of the ERCOT market. These assets were acquired on February 2, 2006 as part of the acquisition of Texas Genco LLC.

Operating Strategy

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

NRG’s strategy is to sell forward a majority of its solid-fuel baseload capacity in the ERCOT market under long-term contracts or to enter into hedges by using natural gas as a proxy for power prices. Accordingly, the Company’s primary focus will be to keep these solid-fuel baseload units running efficiently. With respect to gas-fired assets, NRG 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, the Company will offer a range of products including where the customer has the right to dispatch capacity as the customer needs. For the gas-fired capacity that NRG will continue to sell commercially into the market, the Company will focus on making this capacity available to the market whenever it is economic to run.

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


	Net Generation
	2006		2005		2004
	(In thousands of MWh)

Coal		31,371		31,299		31,222
Gas		7,983		6,806		7,701
Nuclear^(a)		9,385		6,412		6,580

Total		48,739		44,517		45,503


(a)		MWh information reflects the undivided interest in total MWh generated by STP. On May 19, 2005, Texas Genco LLC increased its undivided interest in STP from 30.8% to 44.0%

Generation Facilities

As of December 31, 2006, NRG’s generation facilities in Texas consisted of approximately 10,760 MW of generation capacity. The following table describes NRG’s electric power generation plants and generation capacity as of December 31, 2006:


				Net
				Generation
				Capacity
Plant	Location	% Owned		(MW)^(c)	Primary Fuel-type

Solid Fuel Baseload Units:
W. A. Parish^(a)	Thompsons, TX		100.0	2,480	Coal
Limestone	Jewett, TX		100.0	1,700	Lignite/Coal
South Texas Project^(b)	Bay City, TX		44.0	1,100	Nuclear

Total Solid Fuel Baseload				5,280
Operating Natural Gas-Fired Units:
Cedar Bayou	Baytown, TX		100.0	1,500	Natural Gas
T. H. Wharton	Houston, TX		100.0	1,025	Natural Gas
W. A. Parish (Natural gas)^(a)	Thompsons, TX		100.0	1,190	Natural Gas
S. R. Bertron	Deer Park, TX		100.0	840	Natural Gas
Greens Bayou	Houston, TX		100.0	760	Natural Gas
San Jacinto	LaPorte, TX		100.0	165	Natural Gas

Total Operating Natural Gas-Fired				5,480

Total Operating Capacity				10,760


(a)		W. A. Parish has nine units, four of which are baseload coal-fired units and five of which are natural gas-fired units.

(b)		Generation capacity figure consists of the Company’s 44.0% undivided interest in the two units of STP.

(c)		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 2,970 MW of mothballed capacity available for redevelopment.

The following is a description of NRG’s most significant revenue generating plants in the Texas region:

W.A. Parish — NRG’s W.A. Parish plant is one of the largest fossil-fired plants in the United States based on total MWs of generation capacity. This plant’s power generation units include four coal-fired steam generation units with an aggregate generation capacity of 2,480 MW as of December 31, 2006. Two of these units are 650 MW steam units that were placed in commercial service in December 1977 and December 1978, respectively. The other two units are 570 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 NRG’s coal transportation options at competitive prices. Each of the four coal-fired units have low-NO_x burners and SCR, installed to reduce NO_x emissions and baghouses to reduce particulates. In addition, W.A. Parish Unit 8 has a scrubber installed to reduce SO₂ emissions. Plant uprate projects completed in 2006 uprated the net generation capacity of W.A. Parish by 17 MW.

Limestone — NRG’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 1,700 MW as of December 31, 2006. The first unit is an 835 MW steam unit that was placed in commercial service in December 1985. The second unit is an 865 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. NRG 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. In the second quarter of 2006, NRG replaced the high pressure and intermediate pressure turbines, rewound the generator and replaced the main generator step-up transformer of Limestone Unit 2. These upgrades increased the generation capacity by 86 MW.

South Texas Project Electric Generating Station, or STP — 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. STP’s two generation units commenced operations in August 1988 and June 1989, respectively. For the year ended December 31, 2006, STP had a zero percent forced outage rate and a 97% net capacity factor.

STP is currently owned as a tenancy in common between NRG and two other co-owners. NRG owns a 44%, approximately 1,100 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, NRG is severally liable, but not jointly liable, for the expenses and liabilities of STP. The four original co-owners of STP organized South Texas Project Nuclear Operating Company, or STPNOC, to operate and maintain STP. STPNOC is managed by a board of directors composed of one director appointed by each of the three co-owners, along with the chief executive officer of STPNOC. STPNOC is the NRC-licensed operator of STP. No single owner controls STPNOC and all decisions must be approved by two or more owners who collectively control more than 60% of the interests.

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.

Repowering NRG — Texas

As part of the Company’s Repowering NRG program, NRG has identified a number of proposed projects in Texas that could add important generation capacity to the State. These include, at present, one or more Houston gas-fired generation projects and wind projects, a large baseload coal project, and two new nuclear units. These projects are designed to meet the growing electrical needs of the State of Texas in a pragmatic and environmentally responsible way. Using a balanced portfolio of fuels and technologies, these projects would provide Texas with both new baseload generation, as well as intermediate and peaking generation units that will follow load and provide ancillary services.

The following table summarizes the proposed projects currently included in the Repowering NRG program in Texas:


Facility	Fuel-type	Technology

Cedar Bayou	Gas	Simple/Combined Cycle
Limestone — unit 3	Coal	Pulverized Coal
STP — Units 3&4	Nuclear	ABWR
Wind Power	Wind	Wind turbines

Cedar Bayou — In November 2006, NRG filed for a permit with the Texas Commission for Environmental Quality, or TCEQ, to repower single and combined cycle gas units consisting of up to 900 MW at NRG’s Cedar Bayou facility. The Company expects to receive permits and interconnection studies during the second half of 2007.

Limestone — NRG is proposing to repower an 800 MW pulverized baseload coal unit at the Company’s Limestone facility in central Texas, referred to as Limestone-3. Limestone-3 would be fueled primarily by PRB coal.

STP — NRG is proposing the addition of two nuclear reactors (Units 3 and 4) at the STP nuclear project. Commercial operations are proposed for late 2014 for Unit 3 and late 2015 for Unit 4. NRG has begun licensing

efforts and the Company anticipates filing a Combined Operating License Application with the NRC during the second half of 2007. NRG is proposing to use General Electric’s Advanced Boiling Water Reactor, or ABWR, technology, which is rated at approximately 1,350 MW per reactor.

Wind — The Company has 100-300 MW of wind projects under active development in Texas.

Market Framework

The ERCOT market is one of the nation’s largest and fastest growing power markets. It represents approximately 85% of the demand for power in Texas and covers the whole state, with the exception of the far west (El Paso), a large part of the Texas Panhandle and two small areas in the eastern part of the state. From 1994 through 2006, 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 2006, hourly demand ranged from a low of 20,276 MW to a high of 63,056 MW. ERCOT has limited interconnections compared to other markets in the United States — currently limited to 856 MW of generation capacity, and wholesale transactions within the ERCOT market are not subject to regulation by the Federal Energy Regulatory Commission, or 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 in the first half of this decade. As of December 31, 2006, aggregate net generation capacity of approximately 76,964 MW existed in the ERCOT market, of which 72.1% was natural gas-fired. Approximately 20,616 MW, or 26.7%, was lower marginal cost generation capacity such as coal, lignite and nuclear plants. NRG’s coal and nuclear fuel baseload plants represent approximately 5,280 MW, or 26%, of the total solid fuel baseload net generation capacity in the ERCOT market. ERCOT has established a target equilibrium reserve margin level of approximately 12.5%; the reserve margin at December 31, 2006, was 16.4%, forecast to drop to 11.4% for 2008 per ERCOT’s latest Capacity Demand and Reserve Report. With the exception of wind generation units, there has been very little generation that has come online since 2004, and the Company expects reserve margins to decrease through 2010 primarily due to load growth. Many new projects have been announced that if materialized would begin to increase the reserve margin after 2010.

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. An October 1, 2005 “Report on Existing and Potential Electric System Constraints and Needs” found that natural gas-fired power plants set the market price of power more than 90% of the time in the ERCOT market. As a result of NRG’s lower marginal cost for baseload coal and nuclear generation assets, the Company expects these ERCOT assets to generate power nearly 100% of the time they are available.

The ERCOT market is currently divided into four regions or congestion zones, namely: North, Houston, South and West, which reflect transmission constraints that are commercially significant and which have limits as to the amount of power that can flow across zones. NRG’s W. A. Parish plant and all its natural gas-fired plants are located in the Houston zone. NRG’s Limestone plant is located in the North zone with STP 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’s 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. ERCOT also serves as an 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 ERCOT 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 also, Regional Regulatory Developments — Texas 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 late 2008. NRG expects that implementation of any new market design will require modifications to its existing procedures and systems. Although NRG does not expect the Company’s competitive position in the ERCOT market to be materially adversely affected by the proposed market restructuring, the Company does not know for certain how the planned market restructuring will affect its revenues, and some of NRG’s plants in ERCOT may experience adverse pricing effects due to their location on the transmission grid.

NORTHEAST

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

Operating Strategy

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


	Net Generation
	2006		2005		2004
	(In thousands of MWh)

Coal		11,042		11,363		11,694
Oil		1,217		3,148		1,429
Gas		1,050		1,735		1,136

Total		13,309		16,246		14,259

NRG is focused on capturing the locational value of its plants that are located in or near load centers and inside chronic transmission constraints, in order to improve the economic rationale for repowering of those sites. NRG does this primarily through the advocacy of capacity market reforms. The Company has seen some success in these efforts with the start of the Locational Forward Reserve Markets, or LFRM, in the New England Power Pool, or NEPOOL, which, were effective October 1, 2006, and, in addition, with the start of transition capacity payments which were effective December 1, 2006, together acting as a prelude to the full implementation of the Forward Capacity Market, or FCM, which begins June 1, 2010. Further, on December 22, 2006, FERC approved a settlement regarding PJM’s reliability pricing model, or RPM, effective June 1, 2007.

RMR Agreements — Several of the Northeast region’s 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 NRG agrees to maintain its facilities to be available to run when needed, and are paid to provide these capability services based on the Company’s costs. During 2006, Middletown, Montville and Devon were covered by an RMR agreement.

Effective January 1, 2007, the region’s Devon plant is no longer covered by an RMR agreement but operates now on a merchant basis. On January 12, 2007, FERC approved the ISO-NE request to eliminate Peaking Unit Safe Harbor, or PUSH, bidding effective June 19, 2007. This decision adversely impacts the value of generation from the Norwalk Harbor plant. NRG anticipates that it will file for an RMR agreement for this plant to be effective upon the elimination of PUSH bidding. To that end, NRG has received a determination letter from ISO-NE that this plant is needed for reliability service.

Generation Facilities

As of December 31, 2006, NRG’s generation facilities in the Northeast region consisted of approximately 7,240 MW of generation capacity, including assets located in transmission constrained areas, such as in-city New York City — 1,415 MW and southwest Connecticut — 535 MW.

The Northeast region power generation assets are summarized in the table below:


				Net
				Generation
Plant	Location	% Owned		Capacity^(a)	Primary Fuel-type

Oswego	Oswego, NY		100.0	1,635	Oil
Arthur Kill	Staten Island, NY		100.0	865	Natural Gas
Middletown	Middletown, CT		100.0	770	Oil
Indian River	Millsboro, DE		100.0	780	Coal
Astoria Gas Turbines	Queens, NY		100.0	550	Natural Gas
Huntley	Tonawanda, NY		100.0	550	Coal
Dunkirk	Dunkirk, NY		100.0	585	Coal
Montville	Uncasville, CT		100.0	500	Oil
Norwalk Harbor	So. Norwalk, CT		100.0	340	Oil
Devon	Milford, CT		100.0	140	Natural Gas
Vienna	Vienna, MD		100.0	170	Oil
Somerset Power	Somerset, MA		100.0	125	Coal
Connecticut Remote Turbines	Four locations in CT		100.0	105	Oil
Conemaugh	New Florence, PA		3.7	65	Coal
Keystone	Shelocta, PA		3.7	60	Coal

Total Northeast Region				7,240


(a)		Excludes 365 MW of inactive capacity.

The following is a description of NRG’s 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 865 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 350 MW and was installed in 1959. Unit 30 produces an aggregate generation capacity of 500 MW and was installed in 1969. Both Unit 20 and Unit 30 were converted from coal-fired to natural gas-fired facilities in the early 1990s. Unit GT-1 produces an aggregate generation capacity of 15 MW and is activated when ConEd issues a maximum generation alarm on hot days and during thunderstorms.

Astoria Gas Turbine — Located in Astoria, Queens, New York, the NRG Astoria Gas Turbine facility occupies approximately 15 acres within the greater Astoria Generating complex which includes several competing generating facilities. NRG’s Astoria Gas Turbine facility has an aggregate generation capacity of approximately 550 MW from 19 operational combustion turbine generators classified into three types of turbines. The first group consists of 12 gas-fired Pratt & Whitney GG-4 Twin Packs in Buildings 2, 3 and 4, which have a net generating capacity of 145 MW per building. The second group consists of Westinghouse Industrial Combustion

Turbines #191A in Buildings 5, 7 and 8 that fire on liquid distillate with a net generating capacity of approximately 12 MW per building. The third group consists of Westinghouse Industrial Gas Turbines #251GG located in Buildings 10, 11, 12 and 13 and fired on liquid distillate with a net generation capacity of 20 MW per building. The Astoria units also supply Black Start Service to the NYISO. The site also contains tankage for distillate fuel with a capacity of 86,000 barrels.

Dunkirk — The Dunkirk plant is a coal-fired plant located on Lake Erie in Dunkirk, New York. This plant produces an aggregate generation capacity of 585 MW from four baseload units. Units 1 and 2 produce up to 95 MW each and were put in service in 1950, and Units 3 and 4 produce approximately 195 MW each and were put in service in 1959 and 1960, respectively. In the spring of 2006, the plant completed 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 New York Department of Environmental Conservation, or NYSDEC, settlement referred to in the following paragraph.

Huntley — The 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 550 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 officially retired in May 2006. On November 30, 2006, NRG gave notice to the New York Department of Public Service of the Company’s intent to retire Units 65 and 66 effective June 3, 2007 pursuant to a settlement agreement reached with NYSDEC in January 2005. Per that agreement, NRG will reduce NO_x and SO₂ emissions from the Company’s Huntley and Dunkirk plants through 2013 in the aggregate by over 8,090 lbs and 8,690 lbs, 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.

Indian River — The Indian River Power plant is a coal-fired plant located in southern Delaware on a 1,170 acre site. The plant consists of four coal-fired steam electric units, Units 1 through 4 and one 15 MW combustion turbine, bringing total plant capacity to approximately 780 MW. Units 1 and 2 are each 80 MW of capacity and were placed in service in 1957 and 1959, respectively. Unit 3 is 165 MW of capacity and was placed in service in 1970, while Unit 4 is 440 MW of capacity and was placed in service in 1980. Units 3 and 4 are equipped with SNCR systems, for the reduction of NO_x emissions. All four units are equipped with electrostatic precipitators to remove fly ash from the flue gases as well as low NO_x burners with over fired air to control NO_x emissions. Units 1, 2 and 3 combust eastern bituminous coal, while Unit 4 is fueled with low sulfur compliance coal.

Repowering NRG — Northeast Region

The Repowering NRG program in the Northeast is focused on developing the region’s existing facilities, including using IGCC technology and coal in New York and Delaware, in addition to using combined cycle gas turbines and gas peakers (some with dual fuel capability on oil) in the region.

The following table summarizes the proposed projects currently included in the Repowering NRG program in the Northeast region:


Facility	Fuel-type	Technology

Huntley	Coal	IGCC
Indian River	Coal	IGCC
Montville	Gas/Oil	Combined Cycle Gas Turbine
Middletown	Gas/Oil	Gas Peakers
Devon	Gas/Oil	Gas Peakers

Huntley — In December 2006, NRG won a conditional award in a competitive bid process with the New York Power Authority, or NYPA, to build a 600 MW IGCC plant at the Company’s Huntley facility. The bid included selling capacity and energy to NYPA under a long term PPA. As part of the conditional award, NYPA entered into a strategic alliance with NRG to pursue support from federal, state and local programs in order to close the perceived pricing gap between NRG’s proposal and NYPA’s requirements, while preserving the material benefits of NRG’s

proposal relating to innovative clean coal power generation, including CO₂ capture and geologic sequestration plans.

Indian River — NRG also submitted a bid in December 2006 for the development of a similar IGCC plant at the Company’s Indian River facility in response to a Request for Proposals, or RFP, issued by Delmarva Power and Light. NRG’s bid proposed a 400 MW long term PPA for energy and capacity from the IGCC facility. The bid is currently under review and a formal award decision is scheduled to occur in the second quarter of 2007. If the bid is accepted, NRG expects to negotiate the terms of the PPA and obtain regulatory approval by the middle of 2007.

Connecticut — In December 2006, NRG submitted bids to repower a number of its existing facilities in Connecticut, in response to the State of Connecticut’s RFP process. The bids included separate proposals offering a total of approximately 1,000 MW of new capacity. The largest proposal includes a 630 MW combined cycle unit at the Company’s Montville site. The project covered by this proposal, if accepted, could be converted to an IGCC plant at a later date in response to any state energy and environmental policy objectives requiring baseload capacity that utilizes a plentiful domestic fuel source, such as coal. In addition, this conversion has the potential to bring material environmental benefits to the State of Connecticut, including the ability to capture and potentially sequester CO₂. NRG has also submitted bids for a new gas-fired peaking capacity at the Company’s Middletown and Devon sites.

Market Framework

Although each of the three Northeast ISOs and their respective energy markets are functionally, administratively and operationally independent, they all follow, to a certain extent, similar market designs. Each ISO dispatches power plants to meet system energy and reliability needs, and settles physical power deliveries at Locational Marginal Prices, or LMPs, which reflect the value of energy at a specific location at the specific time it is delivered. This value is determined by an ISO-administered auction process, which evaluates and selects the least costly supplier offers or bids to create a reliable and least-cost dispatch. The ISO-sponsored LMP energy markets consist of two separate and characteristically distinct settlement time frames. The first is a security-constrained, financially firm, day-ahead unit commitment market. The second is a security-constrained, financially settled, real-time dispatch and balancing market. Prices paid in these LMP energy markets, however, are affected by, among other things, market mitigation measures, which can result in lower prices associated with certain generating units that are mitigated because they are deemed to have locational market power, and by $1,000/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 Northeast ISOs have realized, however, that they are not capable of supporting needed investment in new generation without well designed capacity and ancillary service markets. NYISO’s capacity market was the first to receive approval of its proposed demand curve and locational capacity reforms (which are intended to better reflect locational values of capacity resources). ISO-NE and PJM are in the process of implementing their respective versions of reformed capacity markets, namely, a forward capacity market, or FCM, in ISO-NE, and a reliability pricing model, or RPM, proposal in PJM. ISO-NE has instituted a transitional payment for capacity starting December 1, 2006, which starts at a price of $3.05/kW-month and gradually rises to $4.10/kW-month through June 1, 2010, when the FCM market takes effect. In addition, ISO-NE instituted its LFRM market effective October 1, 2006 which provides a capacity payment for qualifying quick start units. NRG bid and was awarded 292 MW of LFRM capacity in the first auction which cleared at the capped rate of $14/kW-month. As indicated above, FERC approved a settlement of the PJM RPM market which will be effective June 1, 2007. For a further discussion, see Item 15 — Note 22 Regulatory Matters, to the Consolidated Financial Statements.

SOUTH CENTRAL

As of December 31, 2006, NRG owned approximately 2,850 MW of generating capacity in the South Central region of the United States. The region lacks a regional transmission organization or ISO and, therefore, remains a bilateral market, making it less efficient than a region with an ISO-administered energy market using large scale economic dispatch, such as the Northeast region. NRG operates the LaGen Control Area which encompasses the generating facilities and the Company’s cooperative load. As a result, the LaGen control area is capable of

providing control area services, in addition to wholesale power, that allows NRG to provide full requirement services to load-serving entities, thus making the LaGen Control Area a competitive alternative to the integrated utilities operating in the region.

Operating Strategy

NRG’s South Central region seeks to capitalize on two factors: (1) its position as a significant coal-fired generator in a market that is highly dependent on natural gas for power generation, and (2) its long-term contractual and historical service relationship with eleven rural cooperatives around Louisiana. NRG’s South Central region works with its cooperative customers to improve contract administration, to expand their and the Company’s customer bases on terms advantageous to all parties and, in some cases, to modify the terms of the Company’s contracts with respect to its current or new customers.

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


	Net Generation
	2006		2005		2004
	(In thousands of MWh)

Coal		10,968		9,924		10,353
Gas		68		85		8

Total		11,036		10,009		10,361

Generation 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 is referred to as Big Cajun II, and also includes the Sterlington, Rockford, Bayou Cove and Big Cajun peaking facilities.

NRG’s power generation assets in the South Central region as of December 31, 2006 are summarized in the table below:


				Net
				Generation
				Capacity
Plant	Location	% Owned		(MW)	Primary Fuel-type

Big Cajun II^(a)	New Roads, LA		86.0	1,490	Coal
Bayou Cove	Jennings, LA		100.0	300	Natural Gas
Big Cajun I — (Peakers) Units 3 & 4	Jarreau, LA		100.0	210	Natural Gas
Big Cajun I — Units 1 & 2	Jarreau, LA		100.0	220	Natural Gas/Oil
Rockford I	Rockford, IL		100.0	300	Natural Gas
Rockford II	Rockford, IL		100.0	145	Natural Gas
Sterlington	Sterlington, LA		100.0	185	Natural Gas

Total South Central				2,850


(a)		NRG owns 100% of Units 1 & 2; 58% of Unit 3

Big Cajun II — NRG’s Big Cajun II plant is a coal-fired, sub-critical baseload plant located along the banks of the Mississippi River, near Baton Rouge, Louisiana. This plant includes three coal-fired generation units (Units 1, 2 and 3) with an aggregate generation capacity of 1,730 MW as of December 31, 2006, and generation capacity per unit of 580 MW, 575 MW and 575 MW, respectively. The plant uses coal supplied from the Powder River Basin and was commissioned between 1981 and 1983. NRG owns 100% of Units 1 and 2 and a 58% undivided interest in Unit 3 for an aggregate owned capacity of 1,490 MW 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.

Repowering NRG — South Central Region

The region’s Repowering NRG strategy is focused on expanding generation capacity at the Company’s Big Cajun facilities, using coal and petcoke as fuel for the plants under best available control technology.

The following table summarizes the proposed projects currently included in the Repowering NRG program in the South Central region:


Facility	Fuel-type	Technology

Big Cajun-II — Unit 4	Coal	Pulverized Coal (BACT)
Big Cajun-I	Pet coke/Coal	Fluidized Bed Boiler

Big Cajun II — Unit 4 — The Company continues the development of a new 775 MW super critical coal-fired generating unit at its Big Cajun II facility. On April 28, 2006, NRG filed an application with the Louisiana Department of Environmental Quality, or LADEQ, to modify the existing permit to allow the Big Cajun II Unit 4 to utilize bituminous, in addition to sub-bituminous, coal. NRG has also entered into project development agreements with potential equity partners for certain ownership interests in Unit 4. However, NRG cannot predict the outcome of its application for the issuance of the modified permit at this time.

Big Cajun I — On May 26, 2006, NRG filed with LADEQ a request for an air permit for the addition of a 230 MW facility at the Company’s Big Cajun I facility. This proposed facility will have the ability to utilize petroleum coke, coal, or biomass as its fuel source.

Market Framework

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

As of December 31, 2006, NRG had long-term all-requirements contracts with eleven Louisiana distribution cooperatives with initial terms ranging from five to twenty-five years. The region had seven contracts that expire in 2025, with the remaining four contracts expiring between 2009 and 2014. In addition, NRG also has certain long-term contracts with the Municipal Energy Authority of Mississippi, South Mississippi Electric Power Association, and Southwestern Electric Power Company, which collectively comprise an additional 13% of region’s contract load requirement.

During 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 the Company’s contracts. As the loads of the region’s customers grow, the Company can expect this imbalance to worsen, unless NRG is successful in renegotiating the terms of these long-term contracts. NRG has been successful in negotiating contract modifications with several of the region’s long-term cooperative customers, which has prevented the addition of large industrial or municipal loads at the contract rates. Also, to minimize this risk during the peak summer and winter seasons, the Company has been successful in entering into tolling agreements, which effectively reduce the need for spot market purchases.

WEST

NRG’s portfolio in the West region currently consists of the El Segundo Generating Station, the Encina Generating Station and 13 combustion turbines with total generation capacity of approximately 1,965 MW. On March 31, 2006, NRG purchased Dynegy Inc’s 50% ownership interest in WCP and became the sole owner of the WCP assets. In addition, NRG owns a 50% interest in the Saguaro power plant located in Nevada. On January 3, 2007, NRG sold the Red Bluff and the Chowchilla II power plants to Wayzata Investment Partners LLC.

Operating Strategy

NRG’s West region strategy is focused on maximizing the cash flow and value associated with its generating plants while protecting and potentially realizing the commercial value of the underlying real estate. There are three principal components to this strategy: (1) responding to expected market demand, initially in load serving entity RFOs and eventually into a capacity market, and (2) using existing emission credits to permit new more efficient generating units at existing sites or siting plants at less valuable property and optimizing the value of the region’s coastal property for other purposes.

The Company’s Encina Station has sold all energy and capacity, 965 MW, in the aggregate, to SDG&E through 2009, on a tolling basis, and recovers its operating costs plus a capacity payment. The El Segundo Station has sold all energy and capacity, 670 MW, in the aggregate, to a load-serving entity through April 30, 2008, on a tolling basis, and recovers its operating costs plus a capacity payment. The San Diego Combustion Turbines, 190 MW, in the aggregate, are subject to an RMR agreement with the CAISO through calendar year 2007, on a tolling basis, and recover their costs plus a return of investment.

The Saguaro power plant is located in Henderson, Nevada, and is contracted to Nevada Power and two steam hosts. The Saguaro plant is contracted to Nevada Power through 2022, one steam host, referred to as Pioneer, whose contract expires in 2007, with a negotiated renewal, and a steam off taker, Ocean Spray, whose contract runs through 2015. Saguaro Power Company, LP, the project company, procures fuel in the open market. NRG manages its share of any fuel price risk through NRG’s commodity price risk strategy.

Generation Facilities

NRG’s power generation assets in the West region as of December 31, 2006 are summarized in the table below:


				Net
				Generation
				Capacity
Plant	Location	% Owned		(MW)	Primary Fuel-type

Encina	Carlsbad, CA		100.0	965	Natural Gas
El Segundo	El Segundo, CA		100.0	670	Natural Gas
Cabrillo II	San Diego, CA		100.0	190	Natural Gas
Red Bluff^(a)	Northern CA		100.0	45	Natural Gas
Chowchilla^(a)	Northern CA		100.0	50	Natural Gas
Saguaro	Henderson, NV		50.0	45	Natural Gas

Total West Region				1,965


(a)		Sold on January 3, 2007

The following are descriptions of the Company’s most significant revenue generating plants in the West region:

Encina — The Encina Station 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 provide intermediate load services and primarily use natural gas but also maintain dual fuel capability. Dual fuel capability allows the units to use oil for emergency reliability backup only under a gas supply force majeure conditions. Also located at the Encina Station is a combustion turbine that provides peaking services

of 15 MW. Units 1, 2 and 3 each have a generation capacity of approximately 107 MW and were installed in 1954, 1956 and 1958, respectively. Units 4 and 5 have a generation capacity of approximately 300 MW and 330 MW respectively, and were installed in 1973 and 1978. The combustion turbine was installed in 1966. Units 1, 2 and 3 are projected to be retired after 2010. Low NO_x burner modifications and SCR equipment has been installed on Units 1, 2, 3, 4 and 5.

El Segundo — The El Segundo plant is located in El Segundo, California and produces an 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. SCR equipment has been installed on Units 3 and 4.

Repowering NRG — West Region

The region’s Repowering NRG strategy is focused on the construction of new capacity to meet increasing local requirements using natural gas at the Company’s existing facilities, as well as the development of potential wind projects through the Company’s wholly-owned subsidiary, Padoma Wind Power, LLC.

The following table summarizes the proposed projects currently included in the Repowering NRG program in the West region.


Facility	Fuel-type	Technology

Long Beach	Gas	Simple Cycle Gas Turbine
Long Beach Repower	Gas	Combined Cycle Gas Turbine
Encina Peakers	Gas	Simple Cycle Gas Turbine
El Segundo 1&2	Gas	Combined Cycle Gas Turbine
Wind Power — California	Wind	Wind turbines
El Segundo 3&4	Gas	Combined Cycle Gas Turbine

Long Beach — In November 2006, NRG was awarded a 260 MW PPA by Southern California Edison to repower Units 1-4 at the Company’s Long Beach Generating Station in Long Beach, California. The PPA term commences August 1, 2007 and continues for ten years.

El Segundo 1& 2 Repower Project — NRG has permits from the California Energy Commission and Air District to construct a new gas-fired combined cycle plant at the Company’s El Segundo facility to replace the retired units at the site. NRG anticipates seeking amendments to these permits to substitute equipment that will not require the use of once-through sea water cooling. The reconfigured project is included in a load-serving entity’s RFO process which is scheduled to announce PPA contract awards for new capacity in early 2008.

In addition, the Company has submitted bids to one of the load-serving entities for two more projects in the West region. The Company expects to know the outcome of these bids sometime during the second half of 2007.

Market Framework

NRG’s assets in the West 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, are under tolling agreements for 2007. CAISO has designated all of the units comprising El Segundo, Encina and Cabrillo II to be capacity that meets the local capacity procurement requirements of the local load-serving entities. At times, all of the plants have been designated as RMR, which entitles designated plants to certain fixed-cost payments from the CAISO for the right to dispatch those units during periods of locational constraints. Currently, the El Segundo unit does not have an RMR agreement with CAISO, but has been designated as a local capacity resource in the Western Los Angeles area and has a tolling agreement for its full capacity with a local major utility for the period May 1, 2006 through April 30, 2008. All units at Encina and Cabrillo II have been designated as local capacity resources for the San Diego load pocket and were designated as RMR units for 2007. Per the RMR agreement, CAISO has an option to renew those units for RMR service into 2008. Encina has a tolling agreement for its full capacity with SDG&E for the period January 1, 2007 through December 31, 2009.

INTERNATIONAL

As of December 31, 2006, NRG, through certain foreign subsidiaries, had investments in power generation projects located in Australia, Germany and Brazil with approximately 1,235 MW of total generating capacity. In addition, NRG owns interests in coal mines located in Germany. The Company’s strategy is to maximize its return on investment and therefore concentrates on contract management; monitoring of its facility operators to ensure safe, profitable and sustainable operations; management of cash flow and finances; and growth of its businesses through investments in projects related to current businesses.

NRG’s international power generation assets as of December 31, 2006 are summarized in the table below:


				Net
				Generation
Plant	Location	% Owned		Capacity	Primary Fuel-type

Gladstone	Australia		37.5	605	Coal
Schkopau	Germany		41.9	400	Lignite
MIBRAG	Germany		50.0	75	Lignite
ITISA	Brazil		99.2	155	Hydro

Total International				1,235

Australia — On June 8, 2006, NRG announced the sale of the Company’s 37.5% equity interest in the Gladstone power station, or Gladstone, and its associated 100% owned NRG Gladstone Operating Services to Transfield Services, an Australia-based provider of operations, maintenance, ownership and asset management services for a purchase price of approximately $189 million (AU$239 million) subject to customary purchase price adjustments, plus assumption of NRG’s share of Gladstone’s unconsolidated debt and cash of approximately $61 million (AU$77 million) and approximately $28 million (AU$35 million), respectively. After-tax cash proceeds are expected to be in excess of $185 million (AU$234 million). The sale is pending until NRG satisfies certain conditions, particularly the securing of certain consents and waivers from the other owners of the project, or agrees to complete the sale on alternative terms. NRG is seeking to close the transaction in 2007.

Germany — NRG’s interests in Germany include a 50% equity interest in MIBRAG, which mines approximately 20 million metric tons of lignite per year and owns 150 MW of electric generation capacity, and a 41.9% equity interest in Schkopau, a 900 MW generating plant fueled with lignite from MIBRAG. NRG does not have direct operational control of either of these facilities.

Approximately 89% of MIBRAG’s revenues are generated from lignite sales. MIBRAG’s generation capacity comprises three plants, 40% of whose output is used to power MIBRAG’s mining operations and the balance sold under contract to EnviaM, the local distribution utility. NRG, through its wholly-owned subsidiary Saale Energie Gesellschaft, or SEG, owns 400 MW of the Schkopau plant’s electric capacity which is sold under a long term contract to Vattenfall Europe Generation.

Brazil — NRG owns a 155 MW hydro-electric power plant located in the state of Mato Grosso, Brazil. NRG currently has a 99.2% interest in the plant.

THERMAL

Through its wholly-owned subsidiary, NRG Thermal LLC, or NRG Thermal, the Company owns thermal and chilled water businesses that have a steam and chilled water capacity of approximately 1,230 megawatt thermal equivalents, or MWt. As of December 31, 2006, NRG Thermal provided steam heating to approximately 550 customers and chilled water to 95 customers in five different cities in the United States. The Company’s thermal businesses in Pittsburgh, Harrisburg and San Francisco are regulated by their respective state Public Utility Commission. The other thermal businesses are subject to the terms of the contract with the off-takers. In addition, NRG Thermal owns and operates three thermal projects that serve industrial and government customers with high-pressure steam and hot water. NRG Thermal also owns a 90 MW combustion turbine peaking generation facility and a 12 MW coal-fired cogeneration facility in Dover, Delaware as well as a 16 MW gas-fired project in

Harrisburg, Pennsylvania. Approximately 40% of NRG Thermal’s revenues are derived from its district heating and chilled water business in Minneapolis, Minnesota.

Regulatory Matters

As operators of power plants and participants in wholesale energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include CFTC, FERC, NRC, PUCT and other public utility commissions in certain states where NRG’s generating assets are located. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which it participates.

The operations of, and wholesale electric sales from, NRG’s Texas region are not subject to regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. As discussed below, these operations are subject to regulation by PUCT, as well as to regulation by the NRC with respect to the Company’s ownership interest in STP.

Commodities Futures Trading Commission, or CFTC

CFTC, among other things, has regulatory oversight authority over the trading of electricity and gas commodities, including financial products and derivatives, under the Commodity Exchange Act, or CEA. Specifically, under existing statutory authority, CFTC has the authority to commence enforcement actions and seek injunctive relief against any person, whenever that person appears to be engaged in the communication of false or misleading or knowingly inaccurate reports concerning market information or conditions that affected or tended to affect the price of natural gas, a commodity in interstate commerce, or actions intended to or attempting to manipulate commodity markets. CFTC also has the authority to seek civil monetary penalties, as well as the ability to make referrals to the Department of Justice for criminal prosecution, in connection with any conduct that violates the CEA. Proposals are pending in Congress to expand CFTC oversight of the over-the-counter markets and bilateral financial transactions.

Federal Energy Regulatory Commission

FERC, among other things, regulates the transmission and the wholesale sale of electricity in interstate commerce under the authority of the Federal Power Act, or FPA. In addition, under existing regulations, FERC determines whether an entity owning a generation facility is an Exempt Wholesale Generator, or EWG, as defined in the Public Utility Holding Company Act of 2005, or PUHCA of 2005. 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 a EWG.

Federal Power Act — The FPA gives FERC exclusive rate-making jurisdiction over the wholesale sale of electricity and transmission of electricity in interstate commerce. Under the FPA, FERC, with certain exceptions, regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as public utilities. The FPA also gives FERC jurisdiction to review certain transactions and numerous other activities of public utilities. NRG’s QFs are currently exempt from the FERC’s rate regulation under Sections 205 and 206 of the FPA to the extent that sales are made pursuant to a state regulatory authority’s implementation of PURPA.

Public utilities under the FPA are required to obtain FERC’s acceptance, pursuant to Section 205 of the FPA, of their rate schedules for the wholesale sale of electricity. All of NRG’s non-QF generating and power marketing companies in the United States make sales of electricity pursuant to market-based rates authorized by FERC. 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, 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 its generating or power marketing companies were deemed to have violated any 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 well as criminal and civil penalties. As a condition to the orders granting NRG market-based rate authority, every three years NRG is required to file a market update to demonstrate that it continues to meet FERC’s standards with respect to generating 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. 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 could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules.

Section 203 of the FPA requires FERC’s prior approval for the transfer of control of assets subject to FERC’s jurisdiction. 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 and the assumption of liabilities to entities with market-based rate authority. In the event that one of NRG’s generating and power marketing companies were to lose its market-based rate authority, such company’s future securities issuances or assumption of liabilities could require prior approval from FERC.

In compliance with Section 215 of the Energy Policy Act of 2005, or EPAct of 2005, FERC has approved the North American Electric Reliability Corporation, or NERC, as the national Energy Reliability Organization, or ERO. As the ERO, NERC will be responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. NRG is responsible for complying with the standards in the regions in which it operates. The ERO will have the ability to assess financial penalties for non-compliance beginning in June 2007.

Public Utility Holding Company Act of 2005 — PUHCA of 2005 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, and Foreign Utility Companies, or FUCOs. NRG is a public utility holding company, but because all of the Company’s generating facilities have QF status or are owned through EWGs or FUCOs, it is exempt from the accounting, record retention, and reporting requirements of PUHCA.

Public Utility Regulatory Policies Act — PURPA was passed in 1978 in large part to promote increased energy efficiency and development of independent power producers. PURPA created QFs to further both goals, and 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. Among other things, EPAct of 2005 provides for the elimination of the obligation imposed on certain utilities to purchase power from QFs at an avoided cost rate under certain conditions. However, the purchase obligation is only eliminated 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. Existing contracts entered into under PURPA are not expected to be impacted; however, certain of NRG’s QFs currently interconnect into markets that may meet the qualifications for elimination of the PURPA purchase requirement. If the obligation 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 NRG’s PURPA sales arrangements under existing contracts and thus may diminish the value of the Company’s QFs. In addition, under FERC regulations for 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, or NRC

The NRC is authorized under the Atomic Energy Act of 1954, as amended, or the AEA, among other things, to grant licenses for, and regulate the operation of, commercial nuclear power reactors. As a holder of an ownership interest in STP, NRG is an NRC licensee and is subject to NRC regulation. The NRC license gives the Company the right to only possess an interest in STP but not to operate it. Operating authority under the NRC operating license for STP is held by STPNOC. NRC regulation involves licensing, inspection, enforcement, testing, evaluation, and modification of all aspects of plant design and operation including the right to order a plant shutdown, technical and financial qualifications, and decommissioning funding assurance in light of NRC safety and environmental

requirements. In addition, NRC’s written approval is required prior to a licensee transferring an interest in its license, either directly or indirectly. As a possession-only licensee, i.e., non-operating co-owner, the NRC’s regulation of NRG is primarily focused on the Company’s ability to meet its financial and decommissioning funding assurance obligations. In connection with the NRC license, the Company and its subsidiaries have a support agreement to provide up to $120 million to support operations at STP.

Decommissioning Trusts — Upon expiration of the 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 the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning obligations unless it is a rate-regulated utility, or a state or municipal entity that sets its own rates, or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that the trust, plus allowable earnings, will equal the estimated decommissioning obligations by the time the decommissioning is expected to begin.

As a result of the acquisition of Texas Genco LLC, NRG through its 44% ownership interest has become the beneficiary of decommissioning trusts that have been established to provide funding for decontamination and decommissioning of STP. CenterPoint Energy Houston Electric, LLC, or CenterPoint, and American Electric Power, or AEP, collect, through rates or other authorized charges to their electric utility customers, amounts designated for funding NRG’s portion of the decommissioning of the facility.

In the event that the funds from the trusts are ultimately determined to be inadequate to decommission the STP facilities, the original owners of the Company’s STP interests, CenterPoint and AEP, each will be required to collect, through their PUCT-authorized non-bypassable rates or other charges to customers, additional amounts required to fund NRG’s obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective rate payers of CenterPoint or AEP, or their successors.

Public Utility Commission of Texas, or PUCT

NRG’s Texas generation 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. PMI is registered as a power marketer with the PUCT and thus is also subject to the jurisdiction of the PUCT with respect to its sales in ERCOT.

Regional Regulatory Developments

In New England, New York, the Mid-Atlantic region, the Midwest and California, FERC has approved regional transmission organizations, also commonly referred to as independent system operators, or ISOs. Most of these ISOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by FERC and associated ISO market rules. These tariffs/market rules dictate how the capacity and energy markets operate, how market participants may make bilateral sales with one another, and how entities with market-based rates are compensated within those markets. The ISOs in these regions also control access to and the operation of the transmission grid within their regions. In Texas, pursuant to a 1999 restructuring statute, the PUCT has granted similar responsibilities to ERCOT.

NRG is affected by rule/tariff changes that occur in the ISO regions. The ISOs 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 to address market power or volatility in these markets. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of NRG’s generation facilities that sell capacity and energy into the wholesale power markets. In addition, new approaches to the sale of electric power have been proposed, and it is not yet clear how they will operate in times of market stress or whether they will provide adequate compensation to generators over the long term.

Texas Region

ERCOT has adopted “Texas Nodal Protocols” that will revise the wholesale market design to incorporate locational marginal pricing (in place of the current ERCOT zonal market). Major elements of the Texas Nodal Protocols include the continued capability for bilateral contracting of energy and ancillary schedules, a financially binding day-ahead market, resource-specific energy and ancillary service bid curves, the direct assignment of all congestion rents, nodal energy prices for resources, aggregation of nodal to zonal energy prices for loads, congestion revenue rights (including pre-assignment for public power entities), and pricing safeguards. The PUCT approved the Texas Nodal Protocols on April 5, 2006, and full implementation of the new market design is expected in December 2008. In other rulemakings, the PUCT has expanded its enforcement policy, increased market oversight, and established market and generator-specific data disclosure requirements designed to increase market transparency. Certain entity specific data disclosure provisions have been stayed by order of a Texas appellate court.

Northeast Region

New England — NRG’s Middletown and Montville facilities continue to be operated pursuant to RMR agreements that were accepted by the Commission on February 1, 2006 (effective January 1, 2006). Unless terminated earlier, the Middletown and Montville RMR agreements are expected to terminate upon the commencement of the Forward Capacity Market, as discussed below. The Devon RMR Agreement terminated on December 31, 2006.

On March 7, 2006, a broad group of New England market participants filed a settlement that provides for interim capacity transition payments for all generators in New England for the period starting December 1, 2006 through May 31, 2010, and the establishment of FCM, commencing June 1, 2010. The FCM established by the settlement will operate an annual descending clock forward capacity auction, normally three years in advance, and will serve as the principal mechanism by which ISO-NE will obtain its installed capacity requirement. For the Company’s Connecticut units subject to RMR agreements, any transition payment will be credited against the monthly availability payment for those units, resulting in no additional revenues for those units. NRG’s other New England generation units are eligible for the transition payments. On June 16, 2006, FERC issued an order accepting the settlement, which was reaffirmed on rehearing by order dated October 31, 2006. On December 28, 2006, the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts filed an appeal of the FERC orders accepting the settlement with U.S. Court of Appeals for the D.C. Circuit. Interim capacity transition payments provided for under the FCM settlement commenced December 1, 2006, as scheduled.

On May 12, 2006, FERC issued an order accepting ISO-NE’s Ancillary Service Market Phase II package that includes a LFRM. This order was reaffirmed on rehearing on October 25, 2006. NRG’s quick-start units are well-suited to provide this service. For the eight-month winter period beginning October 1, 2006, the LFRM market for Connecticut cleared at the cap of $14/kW-month. NRG sold 292 MW in the LFRM auction and expects its participation in this market to positively contribute to revenues from the region.

On January 12, 2007, FERC accepted proposed amendments to ISO-NE’s market rules that eliminate the PUSH bidding mechanism effective June 19, 2007. The elimination of PUSH bidding will impact the Company’s Norwalk Harbor facility, and the Company anticipates seeking an RMR agreement for Norwalk Harbor Units 1 and 2.

New York — On December 22, 2006, the NYISO filed proposed tariff revisions that impose additional market power mitigation on the current owners of its divested generation units in New York City, including NRG’s Arthur Kill and Astoria facilities. The proposed mitigation effectively lowers the bid cap currently set forth in the NYISO tariff from $105/kW-year to $82/kW-year. This proposal could adversely impact capacity revenues from these units and NRG is contesting this filing before FERC.

On January 5, 2007, the Executive Committee of the New York State Reliability Council voted to change the Installed Reserve Margin, or IRM, from 18% to 16.5%. This change, which must be approved by FERC, will become effective for the May 2007 through April 2008 capacity year and will reduce the amount of capacity that must be purchased by load-serving entities.

PJM — On December 22, 2006, FERC issued an order approving the settlement agreement filed September 29, 2006, in the Reliability Pricing Model, or RPM, proceeding. The settlement agreement proposes to implement RPM, the key components of which include the determination of capacity prices through use of a downward-sloping demand curve, locational pricing, and a forward capacity market. PJM anticipates conducting its first auction for the 2007-08 delivery years in April 2007 and implementing the RPM capacity market on June 1, 2007. The RPM settlement effectively accepts PJM’s August 31, 2006 filing with a number of revisions, as set forth in the settlement and December 22, 2006 order. NRG considers these market reforms to be a positive development for its assets in the region.

South Central Region

Entergy has begun to implement its Independent Coordinator of Transmission, or ICT, proposal that will provide (i) independent oversight over the operations of the Entergy transmission system, including the processing of interconnection and transmission requests; (ii) a new process and standard for assigning cost responsibility for transmission upgrades; and (iii) a new weekly procurement process that will allow both Entergy and NRG, as a purchaser of power, to more efficiently utilize the transmission system. The Southwest Power Pool has been selected as the ICT and began performing its responsibilities in November 2006.

Entergy’s ICT proposal will impact both the region’s existing operations by improving transmission access and competitive opportunities and the region’s development opportunities by administering the interconnection process. Certain issues regarding (i) the development of the base transmission plan; (ii) control over Entergy’s transmission models; and (iii) Entergy’s proposal to implement participant funding, are still being contested.

West Region

On December 1, 2006, NRG filed with FERC an extension of the existing RMR agreements for NRG’s Cabrillo Power I, LLC’s Encina facility, and Cabrillo Power II, LLC’s San Diego Jets facility for 2007, and to continue the existing rate effective January 1, 2007. On January 24, 2007, FERC accepted the Cabrillo I filing. On January 30, 2007, FERC accepted the Cabrillo II filing, subject to refund, in response to protests filed by the CPUC and CAISO, and established settlement procedures. NRG has negotiated a three-year bilateral arrangement with SDG&E for Encina that insulates Encina from any revenue impact associated with the RMR agreement.

On September 21, 2006, FERC conditionally accepted the CAISO’s Market Redesign and Technology Upgrade, or MRTU, proposal which is currently scheduled to go in effect in January 31, 2008. Significant components of the MRTU include (i) locational marginal pricing of energy; (ii) a more effective congestion management system; (iii) a day-ahead market; and (iv) an increase to the existing bid caps. NRG considers these market reforms to be a positive development for its assets in the region. Several parties have requested rehearing, which remains pending.

On July 20, 2006, the CPUC issued its order towards establishing a standard Resource Adequacy Capacity Product that followed its decision to impose local capacity requirements, which took effect January 1, 2007. On the same date, the CPUC issued its order on long-term resource procurement that requires SCE to procure at least 1,500 MW.

In November 2006, NRG was awarded a 260 MW PPA by Southern California Edison to repower Units 1-4 at the Company’s Long Beach Generating Station in Long Beach, California. On February 22, 2007, an intervener sought rehearing of the CPUC approval of the agreement and is contesting the PPA at FERC.

See also Item 15 — Note 22, Regulatory Matters, to the Consolidated Financial Statements for a further discussion.

Environmental Matters

NRG is subject to a wide range of environmental regulations across a broad number of jurisdictions in the development, ownership, construction and operation of domestic and international projects. These laws and regulations generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental laws have become increasingly stringent in recent years, especially

around 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. 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 Company’s facilities. NRG expects that future liability under, or compliance with, environmental requirements could have a material effect on the Company’s operations or competitive position.

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. Texas and Louisiana will adopt the CAMR federal implementation plan, or FIP, when it is finalized by USEPA. Certain states in which NRG operates coal plants in NRG’s Northeast region such as Delaware, Massachusetts and New York have proposed or adopted state implementation plans in lieu of the CAMR FIP. Provisions for mercury monitoring and mitigation technologies are included in the budget and environmental capital expenditures for NRG’s coal plants.

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 some of the Company’s power plants in New York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois, Pennsylvania, Maryland and Texas. On August 24, 2005, the USEPA published a proposed FIP to ensure that generators affected by CAIR reduce emissions on schedule. In parallel: (i) on December 20, 2005, the USEPA signed proposed revisions to address attainment for fine particulates, or NAAQS for PM2.5, which will require affected states to implement further rules to address SO₂ and NO_x emissions; and (ii) on November 9, 2005, the USEPA proposed the second phase of the 8-hour ozone NAAQS rule relating to NO_x emissions. A number of environmental groups, states and industry organizations challenged aspects of the CAIR. The challenges were consolidated into South Coast Air Quality Management District v. EPA. In a ruling on December 22, 2006, the D.C. Circuit overturned portions of USEPA’s Phase I implementation rule for the new 8-hour ozone standard. Specifically, the court ruled that USEPA could revoke the 1-hour standard as long as there was no backsliding from more stringent control measures. This ruling could result in the imposition of fees under Section 185 of the Clean Air Act, or the CAA, on volatile organic carbon, or VOC, and NO_x emissions in severe non-attainment areas. The fees could be as high as $7,700/ton for emissions above 80% of baseline emissions levels. Depending on the determination of baseline emission levels, this could materially impact NRG’s operations in California, New York City and Texas.

The Clean Air Visibility Rule was published by the USEPA on July 6, 2005. 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. Most of the Company’s 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 beyond those required by CAIR.

Increased public concern and mounting political pressure may result in federal requirements to reduce or mitigate the effects of GHG. NRG’s generating portfolio includes coal-, oil- and gas-fired plants, which emit CO₂, a GHG, and will likely be subject to proposed regulation which could affect NRG’s costs of operation. NRG is taking steps now to mitigate any potential adverse impacts, including investments in non-fossil generation and investments in generation technologies that will more easily allow the company to manage and control CO₂ emissions.

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 New Source Review, or NSR, Prevention of Significant Deterioration, or PSD, requirements. EPA has issued

an NOV against NRG’s Big Cajun II plant alleging that NRG’s predecessors had undertaken projects that triggered requirements under the PSD program, including the installation of emission controls. NRG has evaluated the claims and believes they have no merit. Nonetheless, NRG has had discussions with EPA about resolving the claims. See the South Central regional below for a further discussion.

Water — In July 2004, USEPA published rules governing cooling water intake structures at existing power facilities commonly referred to as the Phase II 316(b) rules. The rules specify standards for cooling water intake structures at existing power plants using the largest amounts of cooling water. These rules will require implementation of the 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. On January 25, 2007, the 2nd Circuit Court of Appeals made its decision in the Riverkeeper vs. US EPA appeal over the Phase II 316(b) regulation. Riverkeeper prevailed on nearly all issues and the decision essentially remands all of the important aspects of the rule back to EPA for reconsideration and restricted EPA’s ability to allow generators to substitute mitigation for aquatic species losses through habitat restoration or other measures. The Phase II 316(b) regulation affects a number of NRG’s plants, specifically those with once-through cooling systems. While NRG has conducted a number of the requisite studies, until all the needed studies throughout the Company’s fleet have been completed, consultations on the results have occurred with USEPA or its delegated state or regional agencies, and EPA concludes its reconsideration of the 316(b) rules, it is not possible to estimate with certainty the capital costs that will be required for compliance with the Phase II 316(b) rules.

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 NRG 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 state of 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. NRG intends to continue to ship low-level waste material from STP offsite 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 Initiatives

Northeast Region

NRG’s facilities in the eastern US are subject to a cap-and-trade program governing NO_x emissions during the ozone season, typically from May 1 through September 30. These rules essentially require that one NO_x allowance be held for each ton of NO_x emitted. Each of NRG’s facilities that are subject to these rules has been allocated NO_x emission allowances. NRG currently estimates that the portfolio total is currently sufficient to generally cover operations at these facilities through 2009, reflecting the fact that NO_x allowances are allocated on a three-year, look-back basis. However, if at any point emission 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 Ozone Transport Commission, or OTC, was established by Congress and governs ozone and the NO_x budget program in certain eastern states, including Massachusetts, Connecticut, New York and Delaware. The OTC proposes to implement a regional plan containing emission reduction targets for power plants that exceed those under CAIR. The OTC targets and timelines have slipped although additional SO₂ and NO_x reductions are still in

discussion. Current attention is focused on NO_x emissions from units run primarily on High Energy Demand Days, or HEDD, of which NRG owns facilities in Connecticut, Delaware and New York. NRG continues to be actively engaged in the OTC stakeholder process including providing technical expertise to improve policy decision making. While it is not possible to predict the outcome of this regional effort, to the extent that the OTC is successful in implementing emission requirements that are more stringent than existing regimes, NRG could be materially impacted.

On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding, or MOU, to create a Regional Greenhouse Gas initiative to establish a cap-and-trade greenhouse gas program for electric generators, referred to as RGGI. Maryland and Massachusetts have since announced their intent to join. In August 2006, the states participating in RGGI released a model rule which addresses program elements including timelines, monitoring, the use of offsets, and allowance trading. The program begins in 2009. Individual states in which NRG operates including Connecticut, Delaware, Massachusetts and New York must promulgate state rules, which can be based on the model rule, and in addition, address allowance allocations/auctions, treatment of unallocated allowances and leakage. New York issued a pre-proposal version in December 2006 which, among other things, proposes to increase MOU suggested set aside of allowances from 25% to 100% and that these allowances be auctioned. New York is accepting comments on the pre-proposal and expects to have a final rule later in 2007. Connecticut, Delaware and Massachusetts plan to develop rules in 2007. NRG has proposed clean coal IGCC projects that are carbon capture ready to meet future generation demands in both New York and Delaware and also, potentially, Connecticut. NRG continues to actively participate in state and regional RGGI proceedings.

New England — 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. 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 as of January 1, 2008 and must achieve a reduction in its mercury inlet-to-outlet concentration of 85%. NRG plans 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. A permit for repowering the facility was submitted to the MADEP in December 2006.

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 emissions restrictions. A carbon emissions cap applies from January 1, 2006, while a rate requirement will apply in 2008. It is expected that Somerset will meet the cap from 2006 through 2007 and purchase offsets after that period. Massachusetts announced in January 2006 that they will join the other Northeast states in RGGI.

New York — Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC entered into a Consent Order with the New York State Department of Environmental Conservation, or NYSDEC, effective March 31, 2004, regarding certain alleged opacity exceedances. The Order stipulates penalties for future violations of opacity requirements and a compliance schedule. In 2006, NRG accrued amounts payable to NYSDEC of $0.2 million to cover the stipulated penalty payments.

Delaware — In November 2006, the Delaware Department of Natural Resources and Environmental Control, or DNREC, promulgated Regulation No. 1146, or Reg 1146, Electric Generating Unit Multi-Pollutant Regulation and Section 111(d) of the State Plan for the Control of Mercury Emissions from Coal-Fired Electric Steam Generating Units. These regulations govern the control of SO₂, NO_x and mercury emissions from electric generating units. NRG’s current plan to install controls at the Company’s Indian River facility, while on an accelerated basis, is unable to meet certain deadlines for SO₂ and NO_x controls in Phase 1, taking into account the time required, as a practical matter, to design, install and commission the necessary equipment. NRG and the owners of all other subject facilities in the state filed a challenge to Reg 1146 with the Environmental Appeals Board on December 6, 2006. In addition, NRG also filed a protective appeal with the Delaware Superior Court on December 29, 2006. NRG is unable to predict the outcome of the proceedings at this time, but failure to obtain relief may result in a material impact to the Company’s Indian River facility.

On January 5, 2005, DNREC initiated a rule making to incorporate USEPA’s NSR reforms within Delaware’s Regulation 25. Delaware was required to revise the state’s current rules and demonstrate such revisions are equivalent to, or more stringent than, the USEPA’s revised rules by January 2006, which Delaware did not meet. The state is considering a facility emissions limit that would cap all NSR applicable pollutants. The results of the rule making, expected in 2007, will impact Indian River and Dover facilities.

West Region

NRG’s El Segundo Generating Station is regulated by the South Coast Air Quality Management District, or SCAQMD. Before the station’s 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 September 27, 2006, Governor Arnold Schwarzenegger signed Assembly Bill 32 — California Global Warming Solutions Act of 2006 and Senate Bill 1368 — Electricity: Emissions of Greenhouse Gases. Assembly Bill 32, or AB 32, requires the California Air Resources Board, or CARB, to develop a greenhouse gas reduction program to reduce emissions to 1990 levels by 2020, a reduction of approximately 25%. The reductions will be phased in beginning 2012 pursuant to regulations to be adopted by 2011. The financial impact to NRG will depend on final regulations. In addition, the governor also signed Senate Bill 1368, or SB 1368, which prohibits utilities from entering into contracts of five years or more for any baseload generation exceeding a 60% capacity factor unless the contracting facility complies with a greenhouse gas performance standard no higher than the rate of GHG emissions for a combined cycle natural gas baseload power plant. NRG’s plants and development projects in California are unaffected by SB 1368 because they either meet the combined cycle standard or they do not exceed the 60% capacity factor and/or five year contract term thresholds.

Nuclear Insurance

STPNOC purchases insurance coverage on behalf of NRG and the other owners of STP. STP maintains property, decontamination liability and nuclear hazard liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. Currently, STP has a $2.75 billion limit in property and decontamination liability insurance coverage, which is above the legally required minimum of $1.06 billion. The $2.75 billion includes $1 billion excess blanket coverage that is shared with two other nuclear power plants, namely Diablo Canyon and DC Cook. The deductible for property damage is $2.5 million. STP also carries a primary accidental outage policy, which allows for six weeks of indemnity at $3.5 million per week after a 17 week deductible is met. The $3.5 million weekly indemnity would be allocated between the three owners of STP according to their ownership percentages. NRG has purchased additional accidental outage coverage for its 44% ownership stake in STP. This policy provides coverage after the six week indemnity period has been paid under the primary policy, and will provide NRG $1.98 million weekly indemnity per unit for 52 weeks and $1.58 million per week for the next 71 weeks. If both units at STP are affected by an outage arising out of the same accident, weekly indemnity per unit is limited to 80% of the single unit recovery. There is no coverage for partial outages, and the outage must be the result of a property damage caused by a sudden and fortuitous event.

The Price-Anderson Act, as amended through 2025 by the Energy Policy Act of 2005, requires owners of nuclear power plants in the U.S. to purchase the maximum amount of insurance available (currently $300 million) in the insurance market for liability claims that arise in the event of a nuclear accident. In addition, the Act provides a secondary layer of protection of up to $10.5 billion. Under this provision, each licensed reactor company is obliged to contribute up to approximately $101 million per unit per accident in retrospective premiums for any single incident at any nuclear power plant. Annual installments per reactor cannot exceed $15 million. STP is a two reactor facility but NRG’s liability would be capped at 44% due to the Company’s ownership interest in STP. The Price-Anderson Act only covers nuclear liability associated with an accident in the course of operation of the nuclear

reactor, transportation of nuclear fuel to the reactor site, 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. Any substantial retrospective premiums imposed under the Price-Anderson Act or losses not covered by insurance could have a materially adverse effect on NRG’s financial condition, the results of operations and statement of cash flows.

Domestic Site Remediation Matters

Under certain federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products at the facility. NRG may also be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, 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 the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills or other occurrences during its operations.

In January 2006, NRG Indian River Operations, Inc. received a letter of informal notification from DNREC stating that it may be a potentially responsible party with respect to a historic captive landfill. NRG is working with the DNREC, through the Voluntary Clean-up Program to investigate the site. The Company is unable to predict the exact impact at this time.

Further details regarding our Domestic Site Remediation obligations can be found at Item 15 — Note 22, Regulatory Matters, to the Consolidated Financial Statements.

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 enacted on February 16, 2005, and country-based restrictions pertaining to global climate change concerns.

NRG retains appropriate advisors in foreign countries and seeks to design its 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 the Company’s international operations.

MIBRAG/Schkopau, Germany — CO₂ emissions trading began in Germany in 2005, pursuant to European Union obligations under the Kyoto Protocol. Trading rules and emissions allocations for the second emissions trading period (2008 through 2012) have not yet been established by the regulators, therefore the impact of the new rules on NRG’s German business cannot be predicted at this time. Changes to the German Emission Control Directive have specified lower NO_x emission limits for plants firing conventional fuels and co-firing waste products. The new regulations required the Mumsdorf and Deuben Power stations to install additional controls to reduce NO_x emissions in 2006. These plant modifications have been successfully completed. The regulations of the revised European Union’s Groundwater Directive and Mine Wastewater Management Directive are now in effect and MIBRAG sees no negative effects on its mining operations or economics.

Available Information

NRG’s annual reports on Form 10-K, quarterly reports on Form10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge through the Company’s website, www.nrgenergy.com, as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission.

Item 1A — Risk Factors Related to NRG Energy, Inc.

Many of NRG’s power generation facilities operate, wholly or partially, without long-term power sale agreements.

Many of NRG’s facilities operate as “merchant” facilities without long-term power sales agreements for some or all of their generating capacity and output, and therefore are exposed to market fluctuations. Without the benefit of long-term power sales agreements for these assets, NRG cannot be sure that 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 the Company’s property, plant and equipment or to the closing of certain of its facilities, resulting in economic losses and liabilities, which could have a material adverse effect on the Company’s results of operations, financial condition or cash flows.

NRG’s financial performance may be impacted by changing natural gas prices, significant and unpredictable price fluctuations in the wholesale power markets and other market factors that are beyond the Company’s control.

A significant percentage of the company’s domestic revenues are derived from baseload power plants that are fueled by coal. In many of the competitive markets where NRG operates, the price of power typically is set by marginal cost natural gas-fired power plants that currently have substantially higher variable costs than NRG’s coal-fired baseload power plants. The current pricing and cost environment allows the Company’s baseload coal generation assets to earn attractive operating margins compared to plants fueled by natural gas. A decrease in natural gas prices could result in a corresponding decrease in the market price of power but would generally not affect the cost of the coal that the plants use. This could significantly reduce the operating margins of the Company’s baseload generation assets and materially and adversely impact its financial performance.

In addition, because changes in power prices in the markets where NRG operates are generally correlated with changes in natural gas prices, NRG’s hedging portfolio includes natural gas derivative instruments to hedge power prices for its baseload generation. If this correlation between power prices and natural gas prices is not maintained and a change in gas prices is not proportionately offset by a change in power prices, the Company’s natural gas hedges may not fully cover this differential. This could have a materially adverse impact on the Company’s cash flow and financial position.

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- and short-term power prices may also fluctuate substantially due to other factors outside of the Company’s control, including:


	•	increases and decreases in generation capacity in the Company’s markets, including the addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity;

	•	changes in power transmission or fuel transportation capacity constraints or inefficiencies;

	•	electric supply disruptions, including plant outages and transmission disruptions;

	•	heat rate risk;

&nb


ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ERO		Energy Reliability Organization
EWG		Exempt Wholesale Generator
Expected annual baseload generation		The net baseload capacity limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages)
FASB		Financial Accounting Standards Board, the designated organization for establishing standards for financial accounting and reporting
FERC		Federal Energy Regulatory Commission
FGD		Flue Gas Desulphurization
FIN		FASB Interpretation
FIN 45		FIN No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
FIP		Federal Implementation Plan
Fresh Start		Reporting requirements as defined by SOP 90-7
GHG		Greenhouse Gases
Hedge Reset		Net settlement of long-term power contracts and gas swaps by negotiating prices to current market completed in November 2006
Hg		Mercury
ICT		Independent Coordinator of Transmission
IGCC		Integrated Gasification Combined Cycle
IRS		Internal Revenue Service
ISO		Independent System Operator, also referred to as Regional Transmission Organizations, or RTO
ISO-NE		ISO New England, Inc.
ITISA		Itiquira Energetica S.A.
kW		Kilowatts
KWh		Kilowatt-hours
LADEQ		Louisiana Department of Environmental Quality
LFRM		Locational Factor Reserve Market
LIBOR		London Inter-Bank Offered Rate
LNB/OFA		Low NOx Burner with Over Fire Air
LSE		Load-Serving Entity
MACT		Maximum Achievable Control Technology
MADEP		Massachusetts Department of Environmental Protection
MDL		Multi-District Litigation
Merit Order		A term used for the ranking of power stations in terms of increasing order of fuel costs
MIBRAG		Mitteldeutsche Braunkohlengesellschaft mbH
Moody’s		Moody’s Investors Services, Inc., a credit rating agency
MMBtu		Million British Thermal Units
MRTU		Market Redesign and Technology Upgrade
MW		Megawatts


MWh		Saleable megawatt hours net of internal/parasitic load megawatt-hours
NAAQS		National Ambient Air Quality Standards
Net baseload capacity		Nominal summer net megawatt capacity of power generation adjusted for ownership and parasitic load, and excluding capacity from mothballed units as of December 31, 2006
Net Capacity Factor		Net actual generation divided by net maximum capacity for the period hours
Net Generating Capacity		Nominal summer capacity, net of auxiliary power
New York Rest of State		New York State excluding New York City
NiMo		Niagara Mohawk Power Corporation
NOx		Nitrogen oxide
NOL		Net Operating Loss
NOV		Notice of Violation
NRC		United States Nuclear Regulatory Commission
NSR		New Source Review
NYPA		New York Power Authority
NYISO		New York Independent System Operator
NYSDEC		New York Department of Environmental Conservation
OCI		Other Comprehensive Income
OTC		Ozone Transport Commission
Phase II 316(b) Rule		A section of the Clean Water Act regulating cooling water intake structures
PJM		PJM Interconnection, LLC
PJM Market		The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia
PM _(2.5)		Fine particulate matter
PMI		NRG Power Marketing, Inc., a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manage, all commodity trading and hedging for NRG
Powder River Basin, or PRB, Coal		Coal produced in the northeastern Wyoming and southeastern Montana, which has low sulfur content
PPA		Power Purchase Agreement
PSD		Prevention of Significant Deterioration
PUCT		Public Utility Commission of Texas
PUHCA		Public Utility Holding Company Act of 2005
PURPA		Public Utility Regulatory Policy Act of 2005
RCRA		Resource Conservation and Recovery Act
RECLAIM		Regional Clean Air Incentives Market
Repowering NRG		Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency
RFP		Request for proposal
RGGI		Regional Greenhouse Gas Initiative


RMR		Reliability Must-Run
ROIC		Return on invested capital
RTC		RECLAIM Trading Credit
RTO		Regional Transmission Organization, also referred to as an ISO
S&P		Standard & Poor’s, a credit rating agency
SARA		Superfund Amendments and Reauthorization Act of 1986
Sarbanes-Oxley		Sarbanes — Oxley Act of 2002
SCAQMD		South Coast Air Quality Management District
Schkopau		Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which NRG has a 41.9% interest
SCR		Selective Catalytic Reduction
SDG&E		San Diego Gas & Electric
SEC		United States Securities and Exchange Commission
Sellers		Former holders of Texas Genco LLC shares
SERC		Southeastern Electric Reliability Council/Entergy
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS 71		SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”
SFAS 87		SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS 106		SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 109		SFAS No. 109, “Accounting for Income Taxes”
SFAS 123		SFAS No. 123, “Accounting for Stock-Based Compensation”
SFAS 123R		SFAS No. 123 (revised 2004), “Share-Based Payment”
SFAS 133		SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 137		SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133”
SFAS 138		SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of FASB Statement No. 133”
SFAS 142		SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 143		SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 144		SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS 149		SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
SFAS 158		SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)”
SFAS 159		SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115”
SNCR		Selective non-catalytic reduction
SIP		State Implementation Plan
SO₂		Sulfur dioxide


SOP		Statement of Position issued by the American Institute of Certified Public Accountants
SOP 90-7		Statement of Position 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”
SPP		Southwest Power Pool
STP		South Texas Project — Nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC		South Texas Project Nuclear Operating Company
TCEQ		Texas Commission on Environmental Quality
Texas Genco		Texas Genco LLC, now referred to as the Company’s Texas region
Uprate		A sustainable increase in the electrical rating of a generating facility
US		United States of America
USEPA		United States Environmental Protection Agency
U.S. GAAP		Accounting principles generally accepted in the United States
VAR		Value at Risk
Virtual Units		Products sold with scheduling characteristics for energy and ancillary services that are based on an underlying unit physical characteristic
VOC		Volatile Organic Carbon
WCP		WCP (Generation) Holdings, Inc.