Edgar Filing: RELIANT ENERGY INC

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TABLE OF CONTENTS
PART IV

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
or
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 number 1-16455

Reliant Energy, Inc.
(Exact Name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		76-0655566 (I.R.S. Employer Identification No.)
1000 Main Street Houston, Texas 77002 (Address and Zip Code of Principal Executive Offices)		(713) 497-3000 (Registrant's Telephone Number, Including Area Code)

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

Title of each class		Name of each exchange on which registered
Common Stock, par value $.001 per share, and associated rights to purchase Series A Preferred Stock		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

Indicate by check mark whether the registrant (1) has filed all reports required 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 ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. ý

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. Large accelerated filer ý 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 Act). Yes o No ý

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $3,320,080,867 (computed by reference to the closing sale price of the registrant's common stock on the New York Stock Exchange on June 30, 2005, the last business day of the registrant's most recently completed second fiscal quarter).

As of March 1, 2006, the registrant had 305,417,242 shares of common stock outstanding and no shares of common stock were held by the registrant as treasury stock.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's definitive proxy statement for its 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2005, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

Forward-Looking Information		iii
Glossary of Technical Terms		iv
PART I
Item 1.	Business	1
	General	1
	Retail Energy	1
	Wholesale Energy	3
	Regulation	6
	Seasonality and Competition	7
	Environmental Matters	7
	Employees	10
	Executive Officers	10
	Available Information	12
	Certifications	12
Item 1A.	Risk Factors	12
	Risks Related to the Retail and Wholesale Energy Industries	12
	Special Risks Relating to Our Texas Retail Operations	14
	Risks Related to Our Company	16
	Other Risks	18
Item 1B.	Unresolved Staff Comments	18
Item 2.	Properties	18
Item 3.	Legal Proceedings	18
Item 4.	Submission of Matters to a Vote of Security Holders	18
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
Item 6.	Selected Financial Data	19
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21
	Business Overview	21
	Consolidated Results of Operations	23
	Liquidity and Capital Resources	35
	Off-Balance Sheet Arrangements	38
	Historical Cash Flows	39
	New Accounting Pronouncements, Significant Accounting Policies and Critical Accounting Estimates	41
Item 7A.	Quantitative and Qualitative Disclosures about Non-Trading and Trading Activities and Related Market Risks	44
	Market Risks and Risk Management	44
	Non-trading Market Risks	44
	Trading Market Risks	46
Item 8.	Financial Statements and Supplementary Data	48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	48
Item 9A.	Controls and Procedures	48
Item 9B.	Other Information	48

PART III
Item 10.	Directors and Executive Officers of the Registrant	48
Item 11.	Executive Compensation	49
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	49
Item 13.	Certain Relationships and Related Transactions	49
Item 14.	Principal Accountant Fees and Services	49
PART IV
Item 15.	Exhibits and Financial Statement Schedules	50

Forward-Looking Information

Projections, estimates or assumptions about revenues, costs, income, cash flow and other future events are called "forward-looking statements." In some cases, you can identify forward-looking statements by words like "anticipate," "estimate," "believe," "intend," "may," "expect" or similar words. Forward-looking statements are not guarantees of future performance. Actual results may differ from forward-looking statements. Each forward-looking statement speaks only as of its date and we are under no obligation to update these statements. For information about factors that could cause our actual results to differ from forward-looking statements, see "Risk Factors" in Item 1A of this report.

iii

GLOSSARY OF TECHNICAL TERMS

Cal ISO		California Independent System Operator.
capacity factor		The ratio of actual net electricity generated to energy that could have been generated at continuous full-power operation during the year.
CenterPoint		CenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries, prior to August 31, 2002.
CO₂		Carbon dioxide.
Commercial capacity factor		The percentage of the number of hours that our plants run divided by the number of hours that would be dispatched based on the market demand.
contribution margin		Revenues less (a) purchased power, fuel and cost of gas sold, (b) operation and maintenance, (c) selling and marketing and (d) bad debt expense.
EBITDA		Earnings (loss) before interest expense, interest income, income taxes, depreciation and amortization expense.
EITF		Emerging Issues Task Force.
EITF No. 02-03		EITF Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities."
EITF No. 03-11		EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and Not 'Held for Trading Purposes' as Defined in EITF No. 02-03."
EPA		United States Environmental Protection Agency.
ERCOT		Electric Reliability Council of Texas.
ERCOT ISO		ERCOT Independent System Operator.
ERCOT Region		The electric market operated by ERCOT.
FASB		Financial Accounting Standards Board.
FERC		Federal Energy Regulatory Commission.
gross margin		Revenues less purchased power, fuel and cost of gas sold.
GWh		Gigawatt hour.
ISO		Independent system operator.
KWh		Kilowatt hour.
LIBOR		London Inter Bank Offering Rate.
MISO		Midwest Independent Transmission System Operator.
MMbtu		One million British thermal units.
MW		Megawatt.
MWh		Megawatt hour.
net generating capacity		The average of a facility's summer and winter generating capacities, net of auxiliary power.
NO_x		Nitrogen oxide.
NYMEX		New York Mercantile Exchange.
Orion Power		Orion Power Holdings, Inc. and its subsidiaries.
PEDFA		Pennsylvania Economic Development Financing Authority.
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.
PUCT		Public Utility Commission of Texas.
REMA		Reliant Energy Mid-Atlantic Power Holdings, LLC and its subsidiaries.
RTO		Regional transmission organization.
SEC		United States Securities and Exchange Commission.
SO₂		Sulfur dioxide.
Texas GENCO		Texas Genco Holdings, Inc. and its subsidiaries.

PART I

Item 1. Business.

General

We provide electricity and energy services to retail and wholesale customers through two business segments.

•: Retail energy—provides electricity and energy services to approximately 1.9 million retail electricity customers in Texas, including residential and small business customers and large commercial, industrial and governmental/institutional customers. We also serve commercial, industrial and governmental/ institutional customers in the PJM Market.
•: Wholesale energy—provides electricity and energy services in the competitive wholesale energy markets in the United States. In this connection, we own and operate or contract for power generation capacity. As of December 31, 2005, we had approximately 15,956 MW of owned or leased generation capacity in operation.

For information about our corporate history, business segments and disposition activities, see notes 1, 17, 19 and 20 to our consolidated financial statements and "Selected Financial Data" in Item 6 of this Form 10-K.

Retail Energy

Our retail energy segment provides electricity and energy services to customers primarily in Texas. We also have retail energy operations in the PJM Market, and we regularly evaluate entering other markets.

As a retail electricity provider, we are responsible for arranging for the transmission and delivery of electricity to our customers, billing customers and collecting payment for electricity sold, and maintaining 24-hour call centers to provide customer service. We purchase the electricity we sell to customers from generation companies, utilities, power marketers and other retail energy companies. As of December 31, 2005, we had contracts to purchase generation capacity for our Texas retail customers averaging 9,166 MW per month in 2006, 5,965 MW per month in 2007 and 1,395 MW per month in 2008. These amounts exclude commitments as of December 31, 2005, related to a contract terminated in early January 2006. Based on current market conditions, existing retail sales commitments and current load forecasts, we estimate that these contracts will supply approximately 97% of our retail energy segment's current capacity requirements for 2006 for our Texas retail customers.

Residential and Small Business Customers

Our retail business for residential and small business customers is primarily concentrated in Texas. Based on metered locations, as of December 31, 2005, we had approximately 1.7 million residential and 203,000 small business customers, making us the second largest residential electricity provider in Texas. Approximately 75% of our customers are in the Houston area. We also have customers in other Texas cities, including Dallas, Ft. Worth and Corpus Christi.

Commercial, Industrial and Governmental/Institutional Customers

In Texas and the PJM Market, we market electricity and energy services to large commercial, industrial and governmental/institutional customers. These customers include refineries, chemical plants, manufacturing facilities, hospitals, universities, governmental agencies, restaurants and other facilities. Based on metered locations, as of December 31, 2005, we had approximately 36,000 commercial, industrial and governmental/institutional customers.

Operations Data

The following tables present information about our retail electricity sales and customers in various markets:

					2005	2004	2003
					(GWh)
Electricity Sales to End-Use Retail Customers:
Texas:
	Residential:
		Price-to-beat			17,981	19,315	20,738
		Non price-to-beat			6,470	4,516	2,070

			Total residential		24,451	23,831	22,808
	Small business:⁽¹⁾
		Price-to-beat			5,183	7,166	10,845
		Non price-to-beat			2,882	1,924	1,053

			Total small business		8,065	9,090	11,898
	Large commercial, industrial and governmental/institutional⁽²⁾⁽³⁾				28,604	31,278	28,788

			Total Texas		61,120	64,199	63,494

Outside of Texas:
	Commercial, industrial and governmental/institutional				6,155	3,635	785

			Total Outside of Texas		6,155	3,635	785

				Total	67,275	67,834	64,279

(1): "Small business" customers are our retail commercial customers that have a peak demand of less than one MW.
(2): "Large commercial, industrial and governmental/institutional" customers are our retail commercial customers that have a peak demand of more than one MW.
(3): These volumes include customers of the General Land Office for whom we provide services.

				December 31,
				2005	2004
				(in thousands, metered locations)
Retail Customers:
Texas:
	Residential:
		Price-to-beat		1,191	1,313
		Non price-to-beat		483	334

			Total residential	1,674	1,647
	Small business:
		Price-to-beat		137	163
		Non price-to-beat		66	30

			Total small business	203	193
	Large commercial, industrial and governmental/institutional⁽¹⁾			34	40

			Total Texas	1,911	1,880

Outside of Texas:
	Commercial, industrial and governmental/institutional			2	1

		Total Outside of Texas		2	1

			Total	1,913	1,881

(1): These volumes include customers of the General Land Office for whom we provide services.

				2005	2004	2003
				(in thousands, metered locations)
Weighted Average Retail Customer Count:
Texas:
	Residential:
		Price-to-beat		1,250	1,360	1,408
		Non price-to-beat		396	271	117

			Total residential	1,646	1,631	1,525
	Small business:
		Price-to-beat		147	174	194
		Non price-to-beat		43	26	17

			Total small business	190	200	211
	Large commercial, industrial and governmental/institutional⁽¹⁾			36	40	33

			Total Texas	1,872	1,871	1,769

Outside of Texas:
	Commercial, industrial and governmental/institutional⁽²⁾			2	1	—

		Total Outside of Texas		2	1	—

			Total	1,874	1,872	1,769

(1): These amounts include volumes of customers of the General Land Office for whom we provide services.
(2): For 2003, our weighted average retail customer count was 165.

Wholesale Energy

As of December 31, 2005, we owned, had an interest in or leased 36 operating electric power generation facilities with an aggregate net generating capacity of 15,956 MW in five regions of the United States. The net generating capacity of these facilities consists of approximately 38% base-load, 35% intermediate and 27% peaking capacity.

We sell electricity and energy services from our generation portfolio to investor-owned utilities, municipalities, cooperatives and other companies that serve end users or purchase power at wholesale for resale. We also sell these products in hour-ahead, day-ahead, forward, bilateral and ISO markets. Because our facilities are not subject to traditional cost-based regulation, we can generally sell electricity at market-determined prices. The following table identifies the principal markets where we own, lease and have under contract wholesale generation assets:

Region		Principal Markets
PJM		Illinois, New Jersey and Pennsylvania
MISO		Illinois, western Pennsylvania and Ohio
Southeast		Florida, Mississippi and Texas (non-ERCOT)
West		California and Nevada
ERCOT		ERCOT

We also lease transportation and storage capacity in the Eastern and Western United States to provide natural gas to our generation assets.

In the fourth quarter of 2005, we commenced an evaluation of our wholesale energy segment's hedging strategy and use of capital. In February 2006, we decided to substantially reduce new hedges of our generation. For additional information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Business Overview" in Item 7 of this Form 10-K.

Operations Data

The following table presents information about our wholesale power generation, purchase and sales volumes:

		2005	2004	2003
		(GWh)
Power Generation:⁽¹⁾
	Wholesale net power generation volumes	33,709	32,562	35,135
	Wholesale power purchase volumes	1,838	1,840	60,983

	Wholesale power sales volumes⁽²⁾	35,547	34,402	96,118

(1): These amounts include physically delivered volumes, hedge activity related to our power generation portfolio and volumes associated with our legacy trading activities. These amounts exclude (a) volumes associated with our discontinued operations (see note 20 to our consolidated financial statements), (b) generation from facilities where the generation is sold by a third party pursuant to a tolling agreement, (c) generation from facilities that are accounted for as an equity method investment and (d) physical transactions that are settled prior to delivery.
(2): For 2005, 2004 and 2003, these amounts include sales to our retail energy segment of 11,780 GWh, 8,909 GWh and 2,003 GWh, respectively.

The following table presents information about our wholesale natural gas sales volumes:

		2005		2004		2003
		(MMbtu)
Net natural gas sales volumes		146		80		—

The following table describes our electric power generation facilities and net generating capacity by region as of December 31, 2005 (excluding generation facilities included in discontinued operations and facilities subsequently sold or retired from service):

Region		Number of Generation Facilities	Net Generating Capacity (MW)	Fuel Type	Dispatch Type
PJM
	Operating⁽¹⁾	20	7,264	Coal/Gas/Oil/Dual	Base-load/Intermediate/Peaking
	Mothballed	1	68	Dual	Peaking

	Combined	21	7,332
MISO
	Operating	4	1,671	Coal/Gas/Oil	Base-load/Intermediate/Peaking
Southeast
	Operating⁽²⁾⁽³⁾	5	2,215	Gas/Dual	Base-load/Intermediate/Peaking
	Mothballed	1	800	Gas	Intermediate

	Combined	6	3,015
West
	Operating	6	3,976	Gas/Dual	Base-load/Intermediate/Peaking
ERCOT
	Operating	1	830	Gas	Base-load
Total
	Operating	36	15,956
	Mothballed	2	868

	Combined	38	16,824

(1): We lease a 100%, 16.67% and 16.45% interest in three Pennsylvania facilities having 614 MW, 1,711 MW and 1,712 MW of net generating capacity, respectively, through facility lease agreements expiring in 2026, 2034 and 2034, respectively. The table includes our share of the capacity of these facilities.
(2): We own a 50% interest in one of these facilities having a net generating capacity of 108 MW. An unaffiliated party owns the other 50%. The table includes our proportionate share of the capacity of this facility.
(3): We are party to tolling agreements entitling us to 100% of the capacity of two Florida facilities having 630 MW and 474 MW of net generating capacity, respectively. These tolling agreements expire in 2012 and 2007, respectively, and are treated as operating leases for accounting purposes.

The following table provides information regarding generation output:

			2005	%		Capacity Factor		2004	%		Capacity Factor
Dispatch Type (GWh):⁽¹⁾
	Base-load		33,301	87	%	63	%	30,985	84	%	58	%
	Intermediate		3,610	9		6	%	4,922	13		3	%
	Peaking		1,495	4		4	%	1,140	3		9	%

		Total	38,406	100	%	26	%	37,047	100	%	25	%

Fuel Type (GWh):⁽¹⁾
	Coal		24,144	63	%	60	%	21,229	57	%	53	%
	Natural gas		12,195	32		17	%	13,473	37		19	%
	Oil		24	—		1	%	59	—		2	%
	Dual		1,919	5		6	%	2,027	6		7	%
	Hydro		42	—		11	%	109	—		28	%
	Renewables		82	—		36	%	150	—		66	%

		Total	38,406	100	%	26	%	37,047	100	%	25	%

(1): Excludes operations classified as discontinued operations. See note 20 to our consolidated financial statements.

Regulation

Texas

We are certified by the PUCT to provide retail electric service in Texas. Outside Houston, we sell electricity at unregulated prices. In Houston, we can also sell electricity without pricing restrictions. However, until January 1, 2007, we must continue to make electricity available to residential and small business customers at the PUCT-approved "price-to-beat." As of December 31, 2005, the average "price-to-beat" was 16.3 cents per KWh for residential customers using 1,000 KWh per month and 13.6 cents per KWh for small business customers using 15,000 KWh per month.

From November 3 through December 31, 2005, we did not charge the full amount of the approved "price-to-beat" rate to our "price-to-beat" customers. Instead, we charged a price based on an imputed natural gas price of $9.74/MMbtu. In addition, from January 1 through March 15, 2006, we committed to the PUCT to charge existing residential "price-to-beat" customers a price based on an imputed natural gas price of $10.78/MMbtu rather than the current "price-to-beat" rate, which is based on a gas price of $11.387/MMbtu. From March 16 through June 30, 2006, we committed to the PUCT to not charge these residential customers a price higher than the "price-to-beat" rate based on an imputed gas price of $11.387/MMbtu.

Under current PUCT rules, we can request an adjustment to the fuel factor component of the "price-to-beat" twice a year based on significant changes in natural gas prices and purchased energy. The following table shows historical adjustments to our "price-to-beat" fuel factor:

Date Requested	Date Granted	Natural Gas Price in Fuel Factor Before Request (per MMbtu)		Natural Gas Price in Fuel Factor After Request (per MMbtu)
January 2003	March 2003	$	4.017	$	4.956
June 2003	July 2003	$	4.956	$	6.100
November 2004	December 2004	$	6.100	$	7.499
October 2005	November 2005	$	7.499	$	11.387	⁽¹⁾

(1): See discussion above regarding discounts.

In addition to the PUCT, our activities in Texas are subject to standards and regulations adopted by ERCOT. See "Risk Factors" in Item 1A of this Form 10-K.

Other States

We operate electric generation facilities in regions administered by the following ISOs/RTOs: PJM, Cal ISO and MISO, which operate under FERC-established tariffs and regulations. In each of these regions, the market rules include price limits or caps applicable to all generators. In addition, at the request of the local system operator, we may be required to operate our plants at fixed prices or subject to temporary price caps to maintain the reliability of the local grid system. The ISOs also impose numerous other requirements relative to the manner in which we must operate our plants.

Federal Energy Regulatory Commission

A number of our subsidiaries are public utilities under the Federal Power Act. As public utilities, these entities must sell power at either cost-based rates or market-based rates, if market-based rates authority has been granted by FERC. Each of our FERC-jurisdictional subsidiaries has been granted market-based rate authority, although some services sold by some of these entities are sold at cost-based rates. These subsidiaries are subject to FERC rules and oversight regulations.

Seasonality and Competition

The retail and wholesale energy industries are intensely competitive. Our competitors include merchant energy companies, utilities, retail electric service providers and other companies, including in recent years companies owned by investment banking firms, hedge funds and private equity funds. Our principal competitors in the retail electricity markets outside of Houston are typically incumbent utility companies or their affiliates, which have the advantage of long-standing relationships with customers. In general, competition in the retail and wholesale energy markets is on the basis of price, service and product offerings, as well as market perceptions of creditworthiness. For a discussion of how seasonality impacts our business and for additional information on the effect of competition, see "Risk Factors" in Item 1A of this Form 10-K and note 16 to our consolidated financial statements.

Environmental Matters

We are subject to numerous federal, state and local requirements relating to the protection of the environment and the safety and health of personnel and the public. These requirements relate to a broad range of our activities, including the discharge of compounds into the air, water and soil; the proper handling of solid, hazardous and toxic materials; and waste, noise and safety and health standards applicable to the workplace.

For the continued economic operation of our plants, we will construct, modify and retrofit equipment and clean up or decommission our disposal or fuel storage areas and other locations. Based on existing regulations, we estimate that we will spend approximately $50 million to $70 million in 2006, $85 million to $120 million in 2007 and $270 million to $515 million in 2008 through 2011. The above amounts include $8 million for environmental capitalized maintenance projects in 2006 and $20 million for future ash landfill expansions from 2007 through 2011. In addition, $7 million will be spent for remediation of four New Jersey plants through 2011.

Our estimates for compliance with new and emerging environmental regulations are based on our current assessment of items such as the cost of labor and materials and the current state of evolving technologies. Changes to the preceding factors, revisions of regulations, litigation and legislation, as well as other factors, could cause the actual costs to vary outside the range of these estimates.

Air Quality Matters

The Clean Air Act requires the EPA to define standards for air quality that are protective of public health and welfare. The 1990 amendments to the Clean Air Act directed the EPA to implement programs to control ambient ozone, acidic deposition (acid rain) and ozone depleting chemicals, improve visibility in the United States' pristine areas and national parks (regional haze) and reduce emissions of hazardous air pollutants. As a result of these mandates, the EPA implemented a number of emission control programs that affect industrial sources, including power plants, by limiting emissions of NO_x and SO₂, both of which are compounds that result from the combustion of fossil fuels. NO_x and SO₂ are precursors to the formation of acid rain, fine particulate matter and regional haze. NO_x is also a precursor to the formation of ozone.

To comply with these regulations, we must purchase emission allowances and/or upgrade the emissions controls at some of our facilities. As part of our effort to operate our business efficiently, we concluded that since our generating assets dispatch based on market prices, we should maintain an emission allowances inventory that corresponds with forward power sales. We plan to sell some excess emission allowances inventory if the price is equal to or above our fundamental view. See "Risk Factors" in Item 1A and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" in Item 7 of this Form 10-K and notes 4 and 19 to our consolidated financial statements.

Regulation of NO_x and SO₂ Emissions

In March 2005, the EPA finalized a regulation, referred to as the Clean Air Interstate Rule, to further reduce emissions of NO_x and SO₂ in the eastern United States in two phases. The first phase, which takes effect in 2009 for NO_x and 2010 for SO₂, requires approximately a 50% reduction in NO_x and SO₂ emissions on an annual basis. The second phase, which takes effect in 2015, requires additional reductions of approximately 10% for a 60% total reduction in NO_x and 15% for a 65% reduction in SO₂. The EPA regulations include the use of cap-and-trade programs to achieve these reductions.

We have undertaken studies to evaluate possible impacts of the Clean Air Interstate Rule and similar legislative and regulatory proposals, which will primarily affect our coal-fired facilities in the eastern United States. Our preliminary estimates of the required capital expenditures, based on an economic analysis that includes plant operability, changes in the emission allowances market and potential impact of state-imposed regulations, range from approximately $295 million to $545 million through 2011 for SO₂ and NO_x. We anticipate that these expenditures would be made over time, with the majority of the expenditures being incurred in 2008 and 2009.

Regulation of Emissions of Mercury and Other Hazardous Air Pollutants

In March 2005, the EPA adopted a national cap-and-trade rule that requires mercury emission reductions in two phases, in 2010 and 2018, with reduction levels set at approximately 30% and 70%, respectively. Despite the finalization of these mercury control regulations, several issues remain that affect the ultimate requirement to control mercury. First, litigation has commenced over the final form of the rule. The outcome of this litigation is uncertain, and could result in a requirement to control mercury on a facility-by-facility basis, instead of under a cap-and-trade program. Second, states are free to adopt their own mercury regulations that are stricter than those finalized by EPA. Several states, including Pennsylvania, are considering adopting stricter regulations for mercury.

Given the uncertainty around the final outcome of state efforts to regulate mercury and litigation surrounding the federal mercury regulations, preliminary estimates indicate that our emission control expenditures for mercury compliance could range between $35 million and $80 million through 2009. We anticipate that these expenditures would be made over time, with the majority of the expenditures being incurred in 2008 and 2009. These estimates are incremental to the overall capital expenditures range for SO₂ and NO_x.

Greenhouse Gas Emissions

The Kyoto Protocol, which became effective in February 2005, requires ratifying countries to achieve substantial reductions of CO₂ and other greenhouse gases between 2008 and 2012. In December 2005, the United Nations Climate Change Conference in Montreal, Canada adopted over 40 provisions to implement this treaty. Although the United States Congress indicated that it does not intend to ratify the treaty at this time, any future limitations on power plant CO₂ emissions could have a material impact on all fossil fuel-fired facilities, including those belonging to us.

There continues to be a debate within the United States over the direction of domestic climate change policy. The United States Congress is currently considering several bills that would impose mandatory limitation of CO₂ emissions for the domestic power generation sector; and several states, primarily in the northeastern and coastal western United States, are actively developing or considering state-specific or regional regulatory initiatives to stimulate CO₂ emission reductions in the electric utility industry. The specific impact on our business will depend upon the form of emissions-related legislation or regulations ultimately adopted by the federal government or states in which our facilities are located.

Water Quality Matters

In July 2004, the EPA promulgated final regulations relating to the design and operation of cooling water intake structures at existing power plants. The regulations establish "best technology available" standards to protect aquatic organisms in the vicinity of our plant intakes. In 2004, we initiated site-specific evaluations to determine our practicable compliance options and the associated costs. The EPA developed facility-specific cost assumptions that provide an interim means to benchmark our future compliance expenditures. Using these assumptions, we anticipate capital expenditures of approximately $50 million between 2008 and 2010. Several environmental organizations and Attorneys General of six northeastern states have filed lawsuits against the EPA alleging the regulations are insufficient for protection of the state waters and fisheries. The outcome of this litigation on the regulations cannot be determined at this time, but it could significantly affect the final costs of our compliance.

Other

As a result of their age, many of our facilities contain significant amounts of asbestos insulation, other asbestos containing materials, as well as lead-based paint. Existing state and federal rules require

the proper management and disposal of these potentially toxic materials. We have developed a management plan that includes proper maintenance of existing non-friable asbestos installations, and removal and abatement of asbestos containing materials where necessary. We have accounted for the proper management, abatement and disposal of asbestos and lead-based paint at our facilities in our financial planning. See note 2(q) to our consolidated financial statements.

Under the Comprehensive Environmental Response Corporation and Liability Act of 1980 and similar state laws, owners and operators of facilities from or at which there has been a release or threatened release of hazardous substances, together with those who have transported or arranged for the disposal of those substances, are liable for the costs of responding to that release or threatened release, and the restoration of natural resources damaged by any such release. We are not aware of any liabilities under the Act that would have a material adverse effect on our results of operations, financial position or cash flows.

For additional information regarding environmental matters, see "Risk Factors" in Item 1A of this Form 10-K and note 12(b) to our consolidated financial statements.

Employees

As of December 31, 2005, we had 3,675 full-time and part-time employees. Of these employees, 1,205 are covered by collective bargaining agreements, which expire on various dates through September 2009. We are currently negotiating an agreement with the representative for an additional 49 employees. The following table sets forth the number of our employees by business segment as of December 31, 2005:

Segment
Retail energy		831
Wholesale energy		2,144
Other operations		700

	Total	3,675

Executive Officers

The following table lists our executive officers:

Name	Age⁽¹⁾	Present Position
Joel V. Staff	62	Chairman and Chief Executive Officer
Mark M. Jacobs	43	Executive Vice President and Chief Financial Officer
Brian Landrum	43	Executive Vice President, Operations
Jerry J. Langdon	54	Executive Vice President, Public and Regulatory Affairs and Corporate Compliance Officer
Michael L. Jines	47	Senior Vice President, General Counsel and Corporate Secretary
Suzanne L. Kupiec	39	Senior Vice President, Risk and Structuring
Karen D. Taylor	48	Senior Vice President, Human Resources and Chief Diversity Officer
Thomas C. Livengood	50	Senior Vice President and Controller

(1): Age is as of February 1, 2006.

Joel V. Staff has served as our Chairman and Chief Executive Officer since April 2003. He was Executive Chairman of National-Oilwell, Inc. (now National Oilwell Varco, Inc.), an international oil and gas services and equipment company, from May 2001 to May 2002 and Chairman, President and Chief Executive Officer from July 1993 to May 2001. He also serves on the Board of Directors of ENSCO International Incorporated and is a member of its Nominating, Governance and Compensation Committee.

Mark M. Jacobs has served as our Executive Vice President and Chief Financial Officer since July 2002. He served as Executive Vice President and Chief Financial Officer of CenterPoint from July 2002 until our separation from it and Managing Director in the Natural Resources Group of Goldman, Sachs & Co., a global investment banking, securities and investment management firm, from 1989 to 2002.

Brian Landrum has served as our Executive Vice President, Operations since February 2006. He was Senior Vice President, Commercial and Retail Operations, IT from February 2005 to February 2006; Senior Vice President, Customer Operations and Information Technology from January 2004 to February 2005; President, Reliant Energy Retail Services from June 2003 to January 2004; Senior Vice President, Retail Operations from August 2001 to May 2003; and Vice President, Internet and E-business from November 1999 to August 2001.

Jerry J. Langdon has served as our Executive Vice President, Public and Regulatory Affairs and Corporate Compliance Officer since January 2004. He was our Executive Vice President and Chief Administrative Officer from May 2003 to January 2004. Before joining us, Mr. Langdon served as President of EPGT Texas Pipeline, L.P., an El Paso Corporation affiliate that provided gas transportation and storage services, from June 2001 until May 2003 and the Managing Partner and Chief Operating Officer of CARLANG Partners, L.P., an investment firm directed toward the energy transportation industry, and President and Chief Executive Officer of CARLANG Inc. from December 1999 to July 2001.

Michael L. Jines has served as our Senior Vice President, General Counsel and Corporate Secretary since May 2003. He was our Deputy General Counsel and Senior Vice President and General Counsel, Wholesale Group from March 2002 to May 2003. Previously, Mr. Jines served as Deputy General Counsel of CenterPoint and Senior Vice President and General Counsel of its Wholesale Group from 1999 until our separation from it.

Suzanne L. Kupiec has served as our Senior Vice President, Risk and Structuring since January 2004. She was our Vice President and Chief Risk and Corporate Compliance Officer from June 2003 to January 2004. Before joining us, Ms. Kupiec was a partner at Ernst & Young LLP, where she led its Energy Trading and Risk Management Practice serving both audit and advisory service clients.

Karen D. Taylor has served as our Senior Vice President, Human Resources since December 2003. In November 2005, she was appointed as our Chief Diversity Officer. Ms. Taylor was Vice President, Human Resources from February 2003 to December 2003 and Vice President, Administration, Wholesale Group from October 1998 to February 2003.

Thomas C. Livengood has served as our Senior Vice President and Controller since May 2005. He was Vice President and Controller from August 2002 to May 2005. From 1996 to August 2002, Mr. Livengood served as Executive Vice President and Chief Financial Officer of Carriage Services, Inc., a consumer services company.

Available Information

Our principal offices are at 1000 Main, Houston, Texas 77002 (713-497-7000). You can find on our website (http://www.reliant.com):

•: Our corporate governance guidelines and board committee charters;
•: As soon as reasonably practicable after they are filed or furnished to the SEC, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports; and
•: Our business ethics policy.

You can request a free copy of these documents by contacting our investor relations department. In addition, these materials are available on the SEC's website at (http://www.sec.gov) or at its public reference room: 100 F Street, NE, Room 1580, Washington, D.C. 20549 (1-800-SEC-0330).

Certifications

We will timely provide the annual certification of our Chief Executive Officer to the New York Stock Exchange. We filed last year's certification in July 2005. In addition, our Chief Executive Officer and Chief Financial Officer each have signed and filed the certifications under Section 302 of the Sarbanes-Oxley Act of 2002 with this Form 10-K.

Item 1A. Risk Factors.

Risks Related to the Retail and Wholesale Energy Industries

The financial results of our wholesale and retail energy segments are subject to market risks beyond our control.

Our results of operations, financial condition and cash flows are significantly impacted by the prevailing demand and market prices for electricity, purchased power, fuel and emission allowances over which we have no control. Market prices can fluctuate dramatically in response to many factors, including weather conditions; changes in the prices of related commodities; changes in law and regulation; regulatory intervention (including the imposition of price limitations, bidding rules or similar mechanisms); market illiquidity; transmission constraints; environmental limitations; generation unit outages; fuel supply issues; and other events.

The wholesale and retail electricity markets in which we operate are relatively immature markets that are characterized by elements of both deregulated and regulated markets.

The introduction of competition into the United States electricity market is a relatively recent development. As a result, the market is characterized by elements of both a regulated electricity market and a deregulated electricity market. Consequently, our ability to set rates at market prices may be constrained by regulatory restrictions or possible regulatory or political intervention. In many instances, the regulatory structures governing these markets are still evolving, creating gaps in the regulatory framework and associated uncertainty. The new competitive market has attracted a number of new participants. Many of these companies are larger than us and possess stronger balance sheets. The emergence of aggressive competitors may put downward pressure on our retail margins and sales volumes over time. Other competitors are smaller, less well-capitalized entities that may default on their obligations to the market. These defaults may impose costs and burdens on the remaining market participants such as us. As an emerging market, a significant potential for industry consolidation exists as companies seek to expand and grow their operations, which may lead to stronger, more well-capitalized competitors in the industry.

Our operations are subject to extensive regulations. Changes in these regulations could adversely affect the cost, manner or feasibility of conducting our business.

We operate in a regulatory environment that is undergoing significant changes as a result of varying restructuring initiatives at both state and federal levels. We cannot predict the future direction of these initiatives or the ultimate effect that this changing regulatory environment will have on our business. Moreover, existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to our facilities or our commercial activities. Such future changes in laws and regulations may have an adverse effect on business. See "Business—Regulation" in Item 1 of this Form 10-K.

We depend on facilities and systems that we do not own or control for our fuel and fuel supply and to deliver electricity to and bill our customers. Any disruption in these facilities or systems could have an adverse effect on our business.

We depend on (a) fuel sources and fuel supply facilities owned and operated by third parties to supply our generation plants and (b) power transmission, distribution facilities and metering systems owned and operated by third parties to deliver electricity to our customers and provide energy usage data. If these facilities or systems, over which we have no control, fail, we may be unable to generate and/or deliver electricity. In addition, inaccurate or untimely information from third parties could hinder our ability to bill customers and collect amounts owed.

The operation of generation facilities involves significant risks that could interrupt operations and increase our costs.

Ownership of generation assets exposes us to risks relating to the breakdown of equipment or processes, fuel supply or transportation interruptions, shortages of equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, as well as other operational risks. In addition, many of our facilities are old and require significant maintenance expenditures. We are party to collective bargaining agreements with labor unions at several of our plants. If (a) our workers were to engage in a strike, work stoppage or other slowdown, (b) other employees were to become unionized or (c) the terms and conditions in future labor agreements were renegotiated, we could experience a significant disruption in our operations and higher ongoing labor costs. Similarly, we have an aging workforce at a number of our plants creating potential knowledge and expertise gaps as those workers retire. If we are unable to secure fuel, we will not be able to run our generation units. If a generation unit fails, we may have to purchase replacement power from third parties at higher prices. We have insurance, subject to limits and deductibles, covering some types of physical damage and business interruption related to our generation units. However, this insurance may not always be available on commercially reasonable terms. In addition, there is no assurance that (a) insurance proceeds will be sufficient to cover all losses, (b) insurance payments will be timely made or (c) the policies themselves will be free of substantial deductibles.

Our business operations expose us to the risk of loss if third parties fail to perform their contractual obligations.

We may incur losses if third parties default on their obligations to pay us money; buy or sell electricity, fuel, emission allowances and other commodities; or provide us with fuel transportation services, power transmission or distribution services. For additional information about third party default risk, including our efforts to mitigate against this risk, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Risk" in Item 7 of this Form 10-K and note 2(e) to our consolidated financial statements.

We have a substantial coal- and oil-fired generation portfolio that poses environmental issues. Our costs of compliance with environmental laws are significant and can affect our future financial results.

Our wholesale energy segment is subject to extensive and evolving environmental regulations, particularly our coal- and oil-fired generation units. We incur significant costs in complying with these regulations and, if we fail to comply, could incur significant penalties. In addition, failure to comply with environmental requirements could require us to shut down or reduce production on our generation units or create liability exposure. New environmental laws or regulations may be adopted that would further constrain our operations or increase our environmental compliance costs. We also may be responsible for the environmental liabilities associated with generation units even if a prior owner caused the liabilities. We concluded that since our generating assets dispatch based on market prices, we should maintain an emission allowances inventory that corresponds with forward power sales. We plan to sell some excess emission allowances inventory if the price is equal to or above our fundamental view. To the extent allowances are required in the future to operate our facilities, such allowances may be unavailable or only available at costs exceeding our sales price. See "Business—Environmental Matters" in Item 1 of this Form 10-K and note 12(b) to our consolidated financial statements.

Failure to obtain or maintain any required permits or approvals could prevent or limit us from operating our business.

To operate our generating units and retail electric business, we must obtain and maintain various permits, approvals and certificates from governmental agencies. In some jurisdictions, we must also meet minimum requirements for customer service and comply with local consumer protection and other laws. Our failure to obtain or maintain any necessary governmental permits or to satisfy these legal requirements, including environmental compliance provisions, could limit our ability to operate our business or create liability exposure.

Significant events beyond our control, such as hurricanes and other weather-related problems or acts of terrorism, could have a material adverse effect on our businesses.

The uncertainty associated with events beyond our control, such as significant weather events and the risk of future terrorist activity, may affect our results of operations and financial condition in unpredictable ways. These events could result in adverse changes in the insurance markets and disruptions of power and fuel markets. In addition, terrorist actions could damage or shut down our generation facilities or the fuel and fuel supply facilities or the power transmission and distribution facilities upon which our generation and retail businesses are dependent. These events could also adversely affect the United States economy, create instability in the financial markets and, as a result, have an adverse effect on our ability to access capital on terms and conditions acceptable to us.

Special Risks Relating to Our Texas Retail Operations

We depend on third parties to provide electricity to supply our Texas retail customers.

We own a very limited amount of generation capacity in Texas, which is insufficient to supply the electricity requirements of our Texas retail operations. We purchase substantially all of our Texas supply requirements from third parties. As a result, our financial performance depends on our ability to obtain adequate supplies of electric generation from third parties at prices below the prices we charge our customers.

Initiatives undertaken by the PUCT may negatively impact the wholesale cost of power.

The PUCT is expected to propose a new rule on resource adequacy and market power in the ERCOT Region. In this rule, the PUCT is considering an increase to the current price cap applicable

to generation bids into the ERCOT energy market, elimination of current market power mitigation measures and adoption of new market power guidelines. It is expected that these rules will be implemented sometime after the summer of 2006. If market power abuses are not adequately monitored and mitigated, these rules may have the impact of increasing the wholesale cost of power, which could adversely impact our gross margins in the Texas retail market.

The financial performance of our Texas retail electric operations depends on the amount of gross margin, or headroom, available in the "price-to-beat" tariff.

Our retail energy segment derives a significant portion of its revenue from sales to "price-to-beat" customers. The "price-to-beat" includes a component (fuel factor) that, subject to PUCT approval, can be adjusted to reflect changes in the market price of natural gas and purchased power costs. Under PUCT rules, we can request this adjustment twice a year. However, the PUCT or government officials may seek to (a) limit these adjustments in periods of concern over price levels or (b) change the existing rules for adjusting the "price-to-beat" rates.

The price of natural gas embedded in power supply purchases associated with our "price-to-beat" energy commitments can be different than that reflected in the fuel factor due to:

•: varying supply procurement strategies used and the timing of entering into related contracts;
•: subsequent changes in the overall price of natural gas;
•: daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
•: changes in market heat rate (i.e., the relationship between power and natural gas prices);
•: timing of prospective fuel factor adjustments; and
•: other factors.

Our earnings could be adversely affected in any period in which our power supply costs rise at a greater rate than our "price-to-beat" fuel factor.

The declines we have experienced in our Houston retail gross margins may continue or accelerate.

In recent years, we have experienced significant declines in our gross margins in the Houston retail market. This trend could continue and be exacerbated by regulatory intervention. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Business Overview—Factors Affecting Future Performance."

We may lose further market share in the Houston retail electricity market, which is a significant contributor of income to our consolidated results.

In recent years, we have experienced declines in our share of the Houston retail electricity market, which represents approximately 75% of our customer base. This trend could continue if competition increases. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Business Overview—Factors Affecting Future Performance."

Our ability to set rates at market prices in Texas may be constrained by new legislative or regulatory restrictions.

The PUCT is evaluating the retail electric service provided after January 2007 by incumbent providers, such as us, to customers who have not selected a non "price-to-beat" product since the Texas retail electricity market opened to competition. In addition, the Texas Legislature is studying the effects of competition in the Texas retail electricity market. New legislation or rules governing the retail

electric prices we are allowed to charge after January 2007 could have an adverse effect on our financial condition, results of operations and cash flows.

We depend on the ERCOT ISO to communicate operating and system information in a timely and accurate manner. Corrections to prior estimated billing and other information can have an impact on our future reported financial results.

The ERCOT ISO communicates information relating to a customer's choice of retail electric provider and other data needed for servicing of customer accounts to utilities and retail electric providers. Any failure to perform these tasks will result in delays and other problems in enrolling, switching and billing customers. The ERCOT ISO is also responsible for settling all electricity supply volumes in the ERCOT Region. Information that is not accurate or timely may result in incorrect estimates of our settled volumes and supply costs that would need to be corrected when such information is received. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—New Accounting Pronouncements, Significant Accounting Policies and Critical Accounting Estimates—Critical Accounting Estimates" in Item 7 of this Form 10-K.

We could be liable for a share of the payment defaults of other retail electric providers within the ERCOT market.

If a retail electric provider defaults on its payment obligations to ERCOT, we, together with other ERCOT market participants, are liable for a portion of the defaulted amount based on our respective share of the total load. As of December 31, 2005, we accounted for approximately 20% of the total ERCOT load.

Risks Related to Our Company

Our borrowing levels and debt service obligations may adversely affect our business.

As of December 31, 2005, we had total debt from continuing operations of $5.1 billion:

•: We must dedicate a substantial portion of our cash flows to pay debt service requirements, which reduces the amount of cash available for other business purposes;
•: The covenants in our debt agreements restrict our ability to, among other things, (a) obtain additional financing, (b) make investments or acquisitions, (c) create additional liens on our assets and (d) take other actions to react to changes in our business;
•: If we do not comply with the payment and other material covenants, including the financial ratios, under our debt agreements, our debt holders could require us to repay our debt immediately and, in the case of our revolving credit facilities and receivables facility, terminate their commitment to lend us money;
•: So long as our debt remains at current levels, and substantially all our assets are pledged to secure repayment of our debt, we are unlikely to obtain an investment grade credit rating;
•: Our debt levels and credit ratings may affect the evaluation of our creditworthiness by customers, which could put us at a competitive disadvantage to competitors with less debt;
•: We have to post collateral with substantially all of our commercial counterparties and levels of our collateral postings are impacted by changes in commodity prices. A significant change in commodity prices could significantly increase our collateral posting obligations and require us to seek additional sources of liquidity, including additional debt; and
•: We may be more vulnerable to adverse economic and industry conditions, including changes in short-term interest rates.

Although we have taken steps to achieve greater financial flexibility, there is no assurance that we will be successful in achieving this goal.

In February 2004, we announced a goal of achieving, by the end of 2006, an adjusted net debt-to-adjusted EBITDA ratio of 3.0. Although we have taken steps to repay debt and implement other measures intended to improve our financial flexibility, we do not believe that we will achieve this goal in 2006. Even if we achieve our goal, or otherwise obtain credit metrics similar to those held by entities traditionally assigned investment grade credit ratings, there is no assurance credit rating agencies will improve our credit ratings.

Because of our debt levels and the capital-intensive nature of our business, we are vulnerable to reductions in our cash flows or liquidity.

If we were unable to generate sufficient cash flows, access funds from operations or raise cash from other sources, we would not be able to meet our debt service, collateral postings and other obligations. This situation could result from adverse developments in the energy, fuel or capital markets, a disruption in our operations or those of third parties or other events adversely affecting our cash flows and financial performance. We could experience reductions in liquidity if changes in commodity prices trigger our contractual obligations to pledge additional collateral under commodity contracts. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" in Item 7 of this Form 10-K.

Our hedging and other risk management activities may not work as planned.

Our hedges may not be effective as a result of basis price differences, transmission issues, price correlation, volume variations or other factors. See "Quantitative and Qualitative Disclosures about Non-Trading and Trading Activities and Related Market Risks" in Item 7A of this Form 10-K.

Changes in the wholesale energy market or sales of generation assets could result in impairments.

If our outlook for the wholesale energy market changes negatively, or if our ongoing evaluation of our wholesale energy segment results in decisions to mothball, retire or dispose of generation assets, we could have impairment charges related to goodwill or our fixed assets. See notes 2(h) and 4 to our consolidated financial statements.

Lawsuits and regulatory proceedings could adversely affect our business.

From time to time, we are named as a party to lawsuits and regulatory proceedings. Litigation can involve complex factual and legal questions and its outcome is uncertain. Any claim that is successfully asserted against us could result in significant damage claims and other losses. Even if we were to prevail, any litigation could be costly and time-consuming and would divert the attention of our management and key personnel from our business operations, which could adversely affect our financial condition, results of operations or cash flows. See notes 12 and 13 to our consolidated financial statements.

We have entered into outsourcing arrangements with third party service providers. In addition, our retail and other commercial operations are highly dependent on computer and other operating systems, including telecommunications systems. Any interruptions in these arrangements or systems could significantly disrupt our business operations.

In recent years, we have entered into outsourcing arrangements, such as information technology production software, infrastructure and development and certain functions within customer operations, with third party service providers. If these service providers do not perform their obligations, we may incur significant costs and experience interruptions in our business operations in connection with

switching to other service providers or assuming these obligations ourselves. We are also highly dependent on our specialized computer and communications systems, the operation of which could be interrupted by fire, flood, power loss, computer viruses and similar disruptions. Although we have some backup systems and disaster recovery plans, there is no guarantee that these systems and plans will be effective.

If we acquire or develop additional generation assets, or dispose of existing generation assets, we may incur additional costs and risks.

Subject to restrictions in our debt agreements and available capital resources, we may seek to purchase or develop additional generation units or dispose of existing generation units. There is no assurance that our efforts to identify and acquire additional generation units or to dispose of existing generation assets will be successful. In the sale of generation units, we may be required to indemnify a purchaser against certain liabilities. To finance future acquisitions, we may be required to issue additional equity securities or incur additional debt.

Other Risks

For other company risks, see "Business" in Item 1 and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 of this Form 10-K.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Our principal executive offices are leased through 2018, subject to two five-year renewal options. Our principal generation facilities are described under "Business—Wholesale Energy" in Item 1 of this Form 10-K. We believe that our properties are adequate for our present needs. We have satisfactory title to our owned facilities, subject to exceptions, which, in our opinion, would not have a material adverse effect on the use or value of the facilities.

Item 3. Legal Proceedings.

For a description of our material pending legal and regulatory proceedings and settlements, see notes 12 and 13 to our consolidated financial statements.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our common stock trades on the New York Stock Exchange under the ticker symbol "RRI." On March 1, 2006, we had 41,372 stockholders of record.

The closing price of our common stock on December 31, 2005 was $10.32.

	Market Price
	High		Low
2005:
First Quarter	$	13.75	$	10.97
Second Quarter	$	13.00	$	9.70
Third Quarter	$	15.52	$	12.20
Fourth Quarter	$	15.65	$	8.65
2004:
First Quarter	$	8.43	$	6.61
Second Quarter	$	10.97	$	7.75
Third Quarter	$	11.60	$	8.81
Fourth Quarter	$	13.94	$	9.40

We have never paid dividends. Our debt agreements restrict the payment of dividends. See note 6 to our consolidated financial statements.

Sales of Unregistered Securities. During the fourth quarter of 2005, we issued 61,996 shares of unregistered common stock for warrants and 140,227 shares of unregistered common stock for $713,755 in cash pursuant to warrant exercises under an exemption pursuant to Section 4(2) of the Securities Act of 1933, as amended.

Item 6. Selected Financial Data.

	2005 ^(1)(2)(3)			2004 ^(1)(3)(4)(7)			2003 ^{(1)(3)(4)(5)(6)(7)}			2002 ^{(1)(4)(7)(8)(9)(10)}			2001 ⁽¹⁾
	(in millions)
Statements of Operations Data:
Revenues	$	9,712		$	8,098		$	10,097		$	10,230		$	5,739
Operating income (loss)		(321	)		(13	)		(476	)		249			701
Income (loss) from continuing operations		(441	)		(276	)		(916	)		29			461
Cumulative effect of accounting changes, net of tax		(1	)		7			(24	)		(234	)		3
Net income (loss)		(331	)		(29	)		(1,342	)		(560	)		563


		2005 ⁽¹⁾⁽²⁾			2004 ⁽¹⁾⁽⁷⁾			2003 ^(1)(4)(5)(7)			2002 ^{(1)(4)(7)(8)(9)(10)}		2001 ⁽¹⁾
Diluted Earnings (Loss) per Share:
	Income (loss) from continuing operations	$	(1.46	)	$	(0.93	)	$	(3.12	)	$	0.10	$	1.66


	2005 ⁽¹⁾			2004 ⁽¹⁾⁽⁷⁾			2003 ⁽¹⁾			2002 ^(1)(8)(10)			2001 ⁽¹⁾
	(in millions)
Statements of Cash Flow Data:
Cash flows from operating activities	$	(917	)	$	106		$	994		$	234		$	(9	)
Cash flows from investing activities		306			900			917			(3,204	)		(981	)
Cash flows from financing activities		594			(1,047	)		(2,889	)		3,985			1,000


	December 31,
	2005 ^(1)(11)		2004 ⁽¹⁾		2003 ^(1)(5)(6)		2002 ^{(1)(8)(9)(10)}		2001 ⁽¹⁾
	(in millions)
Balance Sheet Data:
Net margin deposits on energy trading and hedging activities	$	1,700	$	487	$	36	$	259	$	69
Total assets		13,569		12,194		13,297		17,219		11,726
Current portion of long-term debt and short-term borrowings		789		619		129		518		94
Long-term debt to third parties		4,317		3,939		4,276		4,555		295
Stockholders' equity		3,864		4,386		4,372		5,653		5,984

(1): Our results of operations include Orion Power since its acquisition in February 2002. We sold or transferred the following operations, which have been classified as discontinued operations: Desert Basin, European energy, Orion Power's hydropower plants, Liberty, Ceredo and Orion Power's New York plants. We sold the following operations, which are included in continuing operations: REMA hydropower plants in April 2005, landfill-gas fueled power plants in July 2005 and our El Dorado investment in July 2005. See notes 19 and 20 to our consolidated financial statements.
(2): During 2005, we recorded charges of $359 million relating to various settlements associated with the western energy crisis. See note 13(a) to our consolidated financial statements.
(3): Effective October 1, 2003, we adopted EITF No. 03-11 and began prospectively reporting the settlement of sales and purchases of fuel and purchased power related to our non-trading commodity derivative activities that were not physically delivered on a net basis in our results of operations in the same line as the item hedged. This resulted in decreased revenues and decreased purchased power, fuel and cost of gas sold of $4.2 billion, $2.4 billion and $834 million for 2005, 2004 and the fourth quarter of 2003, respectively. We did not reclassify amounts for periods prior to October 1, 2003. See note 2(d) to our consolidated financial statements.
(4): We adopted EITF No. 02-03 effective January 1, 2003, which affected our accounting for electricity sales to large commercial, industrial and governmental/institutional customers under executed contracts and our accounting for trading and hedging activities. It also impacted these contracts executed after October 25, 2002 in 2002. See note 2(c) to our consolidated financial statements.
(5): During 2003, we recorded a goodwill impairment charge of $985 million. See note 4 to our consolidated financial statements.
(6): We adopted FASB Interpretation No. 46 on January 1, 2003, as it related to our variable interests in three power generation projects that were being constructed by off-balance sheet entities, which pursuant to this guidance required consolidation upon adoption. As a result, we increased our property, plant and equipment and our secured debt obligations by $1.3 billion.
(7): During 2004, 2003 and 2002, we recorded charges of $2 million, $47 million and $128 million, respectively, relating to a payment made to CenterPoint in 2004 of $177 million. See note 13(d) to our consolidated financial statements.
(8): The retail electric energy market in Texas opened to full competition beginning January 1, 2002.
(9): During 2002, we recorded an impairment of our European energy segment's goodwill of $234 million, net of tax, as a cumulative effect of accounting change.

(10): Effective September 30, 2002, we separated from CenterPoint and prior to that date our financial position and results of operations may not reflect as if we had operated as a separate, stand-alone entity.
(11): See note 12 to our consolidated financial statements for discussion of our contingencies.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Business Overview

Strategies and Objectives

Our objective is to be a leader in restructuring and consolidating the competitive electricity industry. As part of this objective, we focus on the competitive segments of the retail and wholesale electricity markets.

Retail Energy. Our retail energy segment is a low capital investment electricity resale business with relatively stable earnings. The keys to success in the retail energy segment are the volume of megawatt hours we sell to customers and the unit margins received from the customers. We earn a margin by selling electricity to end-use customers and securing a margin by simultaneously acquiring supply. Short-term earnings in this business are impacted by local weather patterns and the competitive tactics of other retailers in the market. The longer-term earnings drivers of the business are the level of competitive intensity and our ability to retain and grow market share by having a strong brand and excellent customer service.

During 2006, we expect to complete the successful transition to a fully competitive retail market in Texas, which we expect will result in higher margin levels in 2007. During 2006, we will strive to switch a significant portion of our "price-to-beat" customers to longer-term and innovative new products to maintain our market share in Houston.

Wholesale Energy. Our wholesale energy segment is a capital-intensive, cyclical business whose earnings are significantly impacted by the level of natural gas prices and spark spreads, among other factors. The key earnings drivers are the amount of electricity we generate and the margin we earn for each unit of electricity sold. We cannot control those factors that have the most significant impact on our earnings levels. The factor that we have the most control over is the percentage of time that our generating plants are available to run when it is economic for them to do so. Short-term earnings in our wholesale business are impacted by weather and commodity price levels. Longer-term earnings are driven by the level of commodity prices and regional supply and demand fundamentals.

In February 2006, we completed an evaluation of our wholesale energy segment's hedging strategy and use of capital. We concluded that the benefits we received from hedging were not sufficient to justify our hedging program. As a result, we decided to substantially reduce new hedges of our generation on a prospective basis.

Corporate. A key priority for 2006 is to substantially reduce the amount of capital committed to collateral requirements. We will achieve this primarily through transitioning to an open wholesale model. In addition, we will strive to enter a credit-enhanced structure for the procurement of retail supply. The open model provides a meaningful representation of the earnings power of the company as it excludes the impact of historical wholesale hedging activity, gains on the sales of emission allowances and gains or losses on the sales of assets and equity method investments.

We have made significant progress in restructuring our business processes to be efficient, cost-sensitive and scalable in order to position ourselves to take advantage of future growth opportunities. As of December 31, 2005, we realized $315 million of our previously announced $340 million in cost reductions. While the initial program is substantially complete, we will continue to focus on increasing our operating efficiencies.

In 2005, we completed our planned asset divestiture program to reduce our debt levels. Total proceeds from the sales (from 2003 through 2005) were $3.7 billion (including the $979 million received in February 2006 for the New York plants). We will continue to focus on improving our financial flexibility through enhancing our earnings.

We have made a commitment to provide greater insight into the key earnings drivers of our business. In early 2006, we introduced enhanced financial disclosures that allow for a robust analysis of the impacts various factors have on our earnings.

We believe that stockholder value is enhanced through the development of a highly motivated and customer-focused work force. We have focused on a series of actions designed to build a "great company to work for," including (a) communicating openly with our employees, (b) fostering company pride among our employees, (c) providing a satisfying and safe work environment, (d) recognizing and rewarding employee contributions and capabilities and (e) enrolling our employees to be collaborative leaders committed to our future.

Our ability to achieve these strategic objectives and executing these actions are subject to a number of factors, some of which we may not be able to control. See "Cautionary Statement Regarding Forward-Looking Information" and "Risk Factors" in Item 1A of this Form 10-K.

Factors Affecting Future Performance

Our retail energy segment has been the largest contributor of income to our consolidated results for the last several years. Beginning in 2006, we expect that our wholesale energy segment will contribute more to our consolidated results for the reasons outlined below.

Retail Energy. Key earnings drivers for our retail energy segment include the margins received from sales to our retail customers and the volume of megawatt hours sold to our customers.

During 2005, in response to significant increases in natural gas prices, public policy concerns and to help mitigate the impact of higher natural gas prices on our customers, we agreed to phase-in our "price-to-beat" rate increase by offering discounts to existing residential "price-to-beat" customers. We also entered into hedges equal to the expected load for those customers. We anticipate that our retail energy segment's gross margin will be negatively impacted by approximately $90 million during the first quarter of 2006, based on estimated supply costs and revenue rates. In addition, we have estimated that gross margin will be negatively impacted by up to $70 million during 2006 because the revenue increase from our "price-to-beat" rate will be less than our expected increase in supply costs. However, each of these factors will ultimately depend on our actual revenue rates from our customers and our total supply costs.

During 2006, we expect that our retail energy segment will continue to experience a loss of "price-to-beat" customers due to these customers switching to other suppliers and moving to non "price-to-beat" products. However, we intend to offset this impact by adding new customers. Further, the potential for increased energy conservation, as monthly rates will be higher than in the summer of 2005, could reduce the average usage per customer. Also, with higher bills, switching rates could increase if competitive activity increases.

We do not believe that the current retail margins in the ERCOT Region are indicative of retail margins longer term. In 2007 and 2008, we believe that retail margins will return to more compensatory levels that would be associated with the transition to a fully competitive retail market in the ERCOT Region.

Wholesale Energy. Key earnings drivers for the wholesale energy segment include: (a) the number of hours our generation is potentially economic to operate; (b) the commercial capacity factor of our power plants; (c) unit margins received from our power plants; (d) other margins received, from among other things, capacity payments and ancillary services; and (e) the settlement of our historical hedges, which is expected to be negative.

In 2006, we expect that the results of operations for our wholesale energy segment will improve based on increased demand in key wholesale markets, including California and the PJM Market, increased availability of coal-fueled generation plants and improved margins. To achieve this, we intend to perform additional maintenance on our coal-fueled generation plants and improve the operating efficiency of this business segment.

As stated above, in February 2006, we concluded that the benefits we received from hedging were not sufficient to justify our historical hedging program. As a result, we decided to substantially reduce new hedges of our generation. We intend to continue entering into selective hedges, including originated transactions, based on (a) our assessment of market fundamentals to increase the return from our generation assets and (b) operational and market limitations requiring us to enter into fuel, capacity and emissions transactions to manage our generation assets. We believe that this new strategy will significantly reduce our wholesale energy segment's use of capital; however, our earnings will be subject to volatility based on market price changes. Existing positions will be closed as economically feasible or in accordance with their terms.

Liquidity. Net cash flow provided by operations for 2005 was negatively impacted by increases in margin posting requirements resulting from significant changes in commodity prices. We anticipate reducing collateral postings (including cash and letters of credit) by approximately $1 billion in 2006, which will result in higher operating cash flow.

Consolidated Results of Operations

Summary by Segment

Retail Energy Segment. Our retail energy segment's contribution margin was $342 million during 2005 compared to $377 million during 2004. The $35 million decrease in contribution margin was primarily due to the decrease in gross margin. Excluding unrealized gains/losses, the gross margin decrease of $249 million was primarily due to lower hedge benefit related to "price-to-beat" customers. Lower volumes and reduced margins related to "price-to-beat" customers and higher other supply costs also contributed to lower retail gross margin. This decrease in gross margin was partially offset by a net change in unrealized gains/losses on energy derivatives of $203 million. Selling and marketing expense increased $13 million. However, operation and maintenance expense decreased $32 million primarily due to decreased salaries, benefits and severance expense.

Our retail energy segment's contribution margin was $377 million during 2004 compared to $839 million during 2003. The $462 million decrease in contribution margin was primarily due to the net change in unrealized gains/losses on energy derivatives of $265 million. In addition, gross margin, excluding unrealized gains/losses, decreased $259 million due primarily to lower hedge benefit related to "price-to-beat" customers. Lower volumes and reduced margins related to "price-to-beat" customers and higher other supply costs also contributed to lower retail gross margin. Operation and maintenance expense decreased $29 million primarily due to decreased salaries and benefits expense.

Wholesale Energy Segment. Our wholesale energy segment's contribution margin was $110 million during 2005 compared to $247 million during 2004. The $137 million decrease in contribution margin was primarily due to $171 million change in unrealized gains/losses on energy derivatives. This decrease was partially offset by a $22 million increase in gross margin, excluding unrealized gains/losses on energy derivatives.

Our wholesale energy segment's contribution margin was $247 million during 2004 compared to $381 million during 2003. The $134 million decrease in contribution margin was primarily due to a $215 million decrease in gross margin, excluding unrealized gains/losses on energy derivatives, primarily due to (a) $118 million decrease in the PJM region and (b) $106 million change in our accounts receivable, refund obligation and credit reserves for energy sales in California. This decrease was partially offset by an $89 million change in unrealized gains/losses on energy derivatives.

Unrealized Gains/Losses on Energy Derivatives. We use derivative instruments to manage operational or market constraints, to increase the return on our generation assets and to execute our retail energy segment's supply procurement strategy. Some derivative instruments receive mark-to-market accounting treatment, which requires us to record gains/losses related to future periods based on current changes in forward commodity prices. We refer to these gains and losses prior to settlement, as well as ineffectiveness on cash flow hedges (see note 5 to our consolidated financial statements), as "unrealized gains/losses on energy derivatives." In some cases, the related underlying transactions being hedged receive accrual accounting treatment, resulting in a mismatch of accounting treatments.

2005 Compared to 2004

Net Income (Loss). We reported $331 million consolidated net loss, or $1.09 loss per share, for 2005 compared to $29 million consolidated net loss, or $0.10 loss per share, for 2004. The change is (in millions):

Western states and Cornerstone settlements		$	(359	)
Gain on sale of counterparty claim			(30	)
Net unrealized gains/losses on energy derivatives			32
Retail energy gross margin, excluding unrealized gains/losses			(249	)
Wholesale energy gross margin, excluding unrealized gains/losses			22
Operation and maintenance			45
Selling, general and administrative			33
Loss on sales of receivables			34
Gains on sales of assets and emission allowances, net			148	⁽¹⁾
Depreciation and amortization			7
Losses from investments, net			(32	)
Income (loss) of equity investments, net			35
Interest expense			19
Interest income			(12	)
Other, net			5
Income taxes			137

	Loss from continuing operations		(165	)
Discontinued operations			(129	)

	Net change before cumulative effect of accounting changes		(294	)
Cumulative effect of accounting change in 2004, net of tax			(7	)
Cumulative effect of accounting change in 2005, net of tax			(1	)

	Net change	$	(302	)

(1): Of this amount, $141 million relates to sales of emission allowances. See note 19 to our consolidated financial statements.

Retail Energy Gross Margins. Our retail energy gross margins decreased to $683 million during 2005 compared to $729 million for 2004. The decrease is (in millions):

Net unrealized gains/losses on energy derivatives		$	203	⁽¹⁾
Higher purchased power costs and volume impacts partially offset by higher revenue rates			(249	)⁽²⁾

	Net decrease in margin	$	(46	)

(1): Increase primarily due to (a) $198 million gain due to unrealized losses recognized in prior periods being realized during 2005 as compared to 2004, (b) $75 million gain due to cash flow hedge ineffectiveness during 2005 as compared to 2004 and (c) $51 million gain due to certain contracts failing to meet the normal purchases scope exception. These increases were partially offset by (a) $122 million loss due to the impact of natural gas and power prices on our portfolio of derivatives held during 2005 as compared to 2004 for purposes of economically hedging our supply and (b) $7 million loss due to the reversal of previously recognized unrealized gains on positions entered into during 2005.
(2): Decrease primarily due to (a) lower hedge benefit from "price-to-beat" customers, (b) reduced volumes sold at "price-to-beat" rates to small business and residential customers, (c) increases in costs of transmission and distribution losses in ERCOT, (d) decrease of margins from "price-to-beat" customers and (e) increases in other supply costs. These decreases were partially offset by an increase in volumes sold at non "price-to-beat" rates.

Retail Energy Revenues.

				2005			2004			Change
				(in millions)
Retail energy revenues from end-use retail customers:
	Texas:
		Residential and small business		$	4,005		$	3,531		$	474	⁽¹⁾
		Large commercial, industrial and governmental/institutional			2,185			1,957			228	⁽²⁾
	Outside of Texas:
		Commercial, industrial and governmental/institutional			404			204			200	⁽³⁾

			Total		6,594			5,692			902
Retail energy revenues from resales of purchased power and other hedging activities					474			374			100	⁽⁴⁾
Market usage adjustments					(23	)		(2	)		(21	)⁽⁵⁾

			Total retail energy revenues	$	7,045		$	6,064		$	981

(1): Increase primarily due to (a) increase in sales prices to customers due to increases in the price of natural gas and (b) increased non "price-to-beat" volumes due to increased customers. These increases were partially offset by lower volumes from "price-to-beat" customers due to fewer customers.
(2): Increase primarily due to fixed-price contracts renewed at higher rates due to higher prices of natural gas and variable-rate contracts, which are tied to the market price of natural gas. This increase was partially offset by decreased volumes.
(3): Increase primarily due to increased volumes due to market entry in Maryland and other PJM markets in 2004 and fixed-price contracts renewed at higher rates due to higher prices of natural gas and variable-rate contracts, which are tied to the market price of natural gas.
(4): Increase primarily due to our supply management activities in various markets within Texas.
(5): See note 2(c) to our consolidated financial statements.

Retail Energy Purchased Power.

		2005			2004		Change
		(in millions)
Costs of purchased power		$	6,301		$	5,047	$	1,254	⁽¹⁾
Market usage adjustments			(8	)		16		(24	)⁽²⁾
Unrealized (gains) losses			69			272		(203	)⁽³⁾

	Total retail energy purchased power	$	6,362		$	5,335	$	1,027

(1): Increase primarily due to (a) an increase in price of purchased power due to higher market prices of electricity primarily driven by higher natural gas prices, (b) less favorable hedging activity in 2005 compared to 2004 and (c) increases in costs of transmission and distribution losses in ERCOT. These increases were partially offset by a decrease in customer usage.
(2): See note 2(c) to our consolidated financial statements.
(3): See analysis of net unrealized gains/losses on energy derivatives in the gross margins discussion above.

Wholesale Energy Gross Margins. Our wholesale energy gross margins decreased to $656 million during 2005 compared to $805 million for 2004. The decrease is (in millions):

California energy sales receivables, refund and reserve changes		$	12
Net unrealized gains/losses on energy derivatives			(171	)⁽¹⁾
Adjustment to October 2003 FERC settlement recorded in September 2004			12
PJM region			(56	)⁽²⁾
East gas transport region			(27	)⁽³⁾
West gas transport region			(19	)⁽⁴⁾
Southeast region			12	⁽⁵⁾
West region			15	⁽⁶⁾
MISO region			79	⁽⁷⁾
Other, net			(6	)

	Net decrease in margin	$	(149	)

(1): Decrease primarily due to (a) $89 million higher unrealized losses in 2005 as compared to 2004 on positions entered to hedge the economics of our business operations which receive mark-to-market accounting treatment, (b) $80 million loss from de-designated hedge positions and (c) $15 million reversal of previously recognized unrealized gains resulting from the settlement of the positions during 2005. These decreases are partially offset by a $13 million gain due to changes in cash flow hedge ineffectiveness in 2005 as compared to 2004.
(2): Decrease primarily due to (a) lower realized margins due to unfavorable differences between prices received by our coal plants and settlement prices on our hedged power sales, (b) higher coal costs and (c) a change in the amortization of contractual rights and obligations. These decreases were partially offset by (a) the new Seward plant achieving commercial operation in October 2004 and (b) increased generation due to higher prices and lower plant outages.
(3): Decrease primarily due to (a) significant drop in natural gas prices during the fourth quarter of 2005, and the corresponding impact on market liquidity, resulting in losses on our gas supply and transportation positions, (b) settlement of gas storage hedges at losses while the anticipated withdrawal and sale of natural gas inventory was deferred to the first quarter of 2006 due to more favorable economics and (c) lower of cost or market adjustment on gas inventory.
(4): Decrease primarily due to unfavorable spreads on gas transportation.
(5): Increase primarily due to higher generation at our dual fuel plants due to higher temperatures and disruption in the availability of natural gas plants due to the hurricanes during the third quarter of 2005. This increase is partially offset by lower margins from power purchase agreements.
(6): Increase primarily due to (a) higher margins from power purchase agreements and (b) the restart of Etiwanda units 4 and 3 in June and September 2004, respectively. These increases were partially offset by (a) lower ancillary revenues and margins and (b) lower generation driven by milder weather.

(7): Increase primarily due to (a) higher realized margins as 2004 obligations under a "provider of last resort" contract (which primarily ended during the fourth quarter of 2004) were priced lower than 2005 market prices and (b) increased generation driven by (i) a decrease in outages at the Avon Lake plant and (ii) higher prices. These increases were partially offset by higher coal costs.

Wholesale Energy Revenues.

		2005			2004			Change
		(in millions)
Wholesale energy third-party revenues		$	2,879		$	2,057		$	822	⁽¹⁾
Wholesale energy intersegment revenues			625			349			276	⁽²⁾
Unrealized losses			(218	)		(32	)		(186	)⁽³⁾

	Total wholesale energy revenues	$	3,286		$	2,374		$	912

(1): Increase primarily due to (a) $248 million due to certain gas transactions, which prior to April 1, 2004, were recorded net as a part of the trading activity and are now recorded gross in revenues and fuel and cost of gas sold, (b) increase in natural gas prices and (c) increase in natural gas sales volumes. These increases were partially offset by a decrease in power sales prices and power sales volumes.
(2): Increase primarily due to higher volumes due to more retail energy segment sales in the PJM Market.
(3): See analysis of net unrealized gains/losses on energy derivatives in the gross margins discussion above.

Wholesale Energy Purchased Power, Fuel and Cost of Gas Sold.

		2005			2004			Change
		(in millions)
Wholesale energy third-party costs		$	2,725		$	1,649		$	1,076	⁽¹⁾
Unrealized gains			(95	)		(80	)		(15	)⁽²⁾

	Total wholesale energy	$	2,630		$	1,569		$	1,061

(1): Increase primarily due to (a) $254 million due to certain gas transactions, which prior to April 1, 2004, were recorded net as a part of the trading activity and are now recorded gross in revenues and fuel and cost of gas sold (see footnote (1) under "Wholesale Energy Revenues"), (b) higher prices of natural gas, oil and coal and (c) increased volumes of natural gas and coal purchased.
(2): See analysis of net unrealized gains/losses on energy derivatives in the gross margins discussion above.

Operation and Maintenance.

		2005		2004		Change
		(in millions)
Retail energy		$	190	$	222	$	(32	)
Wholesale energy			544		560		(16	)
Other operations			3		—		3

	Consolidated	$	737	$	782	$	(45	)

The decrease in our retail energy segment is (in millions):

Severance		$	(3	)
Salaries and benefits			(28	)
Other, net			(1	)

	Net decrease in expense	$	(32	)

The decrease in our wholesale energy segment is (in millions):

Severance	$	(6	)
Taxes other than income		(18	)⁽¹⁾
Salaries and benefits, excluding plant personnel		(7	)
Termination of certain services to Texas Genco in May 2004		(7	)
Planned power generation maintenance projects and outages		(6	)
Unplanned power generation maintenance projects and outages		10
Bighorn plant and new Seward plant achieved commercial operation in February 2004 and October 2004, respectively		21
Other, net		(3	)

Net decrease in expense	$	(16	)

(1): Decrease primarily due to the resolution of tax contingencies.

Selling, General and Administrative.

Restructuring costs associated with lease on corporate headquarters		$	(13	)
Severance			(13	)
Settlement of shareholder class action lawsuits			8
Salaries and benefits⁽¹⁾			(26	)
Rents and utilities			(7	)
Contract services and professional fees			(7	)
Marketing			11
Bad debt expense			12
Other, net			2

	Net decrease in expense	$	(33	)

(1): Decrease primarily due to impact of decreased stock price on stock-based incentive plan expense.

Western States and Cornerstone Settlements. See note 13(a) to our consolidated financial statements.

Loss on Sales of Receivables. The decrease of $34 million is due to our ceasing to record sales of receivables as sales for accounting purposes due to the amendment of the facility in September 2004. See note 6 to our consolidated financial statements.

Gain on Sale of Counterparty Claim. See note 13(e) to our consolidated financial statements.

Gains on Sales of Assets and Emission Allowances, Net. See note 19 to our consolidated financial statements.

Depreciation and Amortization.

Equipment impairment charge in 2004 related to turbines and generators		$	(16	)
Accelerated depreciation on Wayne facility in 2004 due to early retirement			(12	)
Information system assets fully depreciated in 2004			(24	)
Increase in amortization of emission allowances			13
Net accelerated depreciation on certain facilities due to early retirements			20
Bighorn plant and new Seward plant achieved commercial operation in February 2004 and October 2004, respectively			22
Other, net			(10	)

	Net decrease in expense	$	(7	)

Income (Loss) of Equity Investments, Net. Income (loss) of equity investments, net changed by $35 million primarily due to a $25 million gain on sale of our El Dorado investment and an $8 million decrease in losses from El Dorado. See note 19 to our consolidated financial statements.

Other, Net. During 2005, other, net primarily represents a $23 million impairment of an investment. See note 18 to our consolidated financial statements.

Interest Expense.

Amortization of deferred financing costs		$	(63	)
Financing fees expensed			(26	)
Decrease in outstanding debt			3
Higher interest rates			23
Lower capitalized interest			46
Other, net			(2	)

	Net decrease in expense	$	(19	)

Interest Income.

Receivables facility		$	(12	)
Interest on California net receivables			(10	)
Net margin deposits			10

	Net decrease in income	$	(12	)

Income Tax Expense (Benefit). During 2005 and 2004, our effective tax rate was 36% and 29%, respectively. See note 10 to our consolidated financial statements.

Discontinued Operations. See note 20 to our consolidated financial statements.

2004 Compared to 2003

Net Income (Loss). We reported $29 million consolidated net loss, or $0.10 loss per share, for 2004 compared to $1,342 million consolidated net loss, or $4.57 loss per share, for 2003. The change is (in millions):

Gain on sale of counterparty claim		$	30
Net unrealized gains/losses on energy derivatives			(176	)
Retail energy gross margin, excluding unrealized gains/losses			(259	)
Wholesale energy gross margin, excluding unrealized gains/losses			(215	)
Operation and maintenance			27
Selling, general and administrative			102
Loss on sales of receivables			3
Gains on sales of assets and emission allowances, net			17	⁽¹⁾
Wholesale Energy goodwill impairment			985
Depreciation and amortization			(95	)
Gains from investments, net			7
Loss of equity investments, net			(7	)
Accrual for payment to CenterPoint			45
Interest expense			(11	)
Other, net			(4	)
Income taxes			191

Loss from continuing operations			640
Discontinued operations			642

Net change before cumulative effect of accounting changes			1,282
Cumulative effect of accounting change in 2003, net of tax			24
Cumulative effect of accounting change in 2004, net of tax			7

	Net change	$	1,313

(1): Of this amount, $19 million relates to sales of emission allowances. See note 19 to our consolidated financial statements.

Retail Energy Gross Margins. Our retail energy gross margins decreased to $729 million during 2004 compared to $1,253 million for 2003. The decrease is (in millions):

Net unrealized gains/losses on energy derivatives		$	(265	)⁽¹⁾
Gains recorded prior to 2003 realized/collected in current periods			45	⁽²⁾
Higher purchased power costs and volume impacts partially offset by higher revenue rates			(258	)⁽³⁾
Change in market usage adjustments			(46	)⁽⁴⁾

	Net decrease in margin	$	(524	)

(1): Decrease primarily due to unrealized losses on short natural gas positions recognized in 2004 as a result of higher natural gas prices.
(2): Increase due to the impact of EITF No. 02-03. See note 2(c) to our consolidated financial statements
(3): Decrease primarily due to (a) reduced hedging benefit from "price-to-beat" customers realized in 2004 compared to 2003, (b) other increases in supply costs, (c) reduced volumes due to fewer "price-to-beat" small business and residential customers and (d) reduced usage from "price-to-beat" residential customers due to milder weather. These decreases were partially offset by an increased usage from our non "price-to-beat" customers primarily due to increased customers.
(4): See note 2(c) to our consolidated financial statements.

Retail Energy Revenues.

				2004			2003			Change
				(in millions)
Retail energy revenues from end-use retail customers:
	Texas:
		Residential and small business		$	3,531		$	3,460		$	71	⁽¹⁾
		Large commercial, industrial and governmental/institutional			1,957			1,526			431	⁽²⁾
	Outside of Texas:
		Commercial, industrial and governmental/institutional			204			40			164	⁽³⁾

			Total		5,692			5,026			666
Retail energy revenues from resales of purchased power and other hedging activities other hedging activities					374			688			(314	)⁽⁴⁾
Market usage adjustments					(2	)		31			(33	)⁽⁵⁾
Unrealized losses					—			(16	)		16	⁽⁶⁾

			Total retail energy revenues	$	6,064		$	5,729		$	335

(1): Increase primarily due to (a) increase in sales prices to customers due to increases in the price of natural gas and (b) increased non "price-to-beat" volumes due to increased customers. These increases were partially offset by lower volumes primarily due to (a) milder weather and (b) fewer "price-to-beat" customers.
(2): Increase primarily due to (a) increased volumes from additional customers and (b) fixed-price contracts renewed at higher rates due to higher prices of natural gas and variable-rate contracts, which are tied to the market price of natural gas.
(3): Increase due to entering parts of the PJM Market in August 2003 and throughout 2004.
(4): Decrease primarily due to $224 million due to the application of EITF No. 03-11 (see note 2(d) to our consolidated financial statements).
(5): See note 2(c) to our consolidated financial statements.
(6): See analysis of net unrealized gains/losses on energy derivatives in the gross margins discussion above.

Retail Energy Purchased Power.

		2004		2003			Change
		(in millions)
Costs of purchased power		$	5,047	$	4,482		$	565	⁽¹⁾
Market usage adjustments			16		3			13	⁽²⁾
Unrealized (gains) losses			272		(9	)		281	⁽³⁾

	Total retail energy purchased power	$	5,335	$	4,476		$	859

(1): Increase primarily due to (a) increase in customer usage, (b) an increase in price of purchased power due to higher market prices of electricity primarily driven by higher natural gas prices and (c) reduced benefit in supply hedging.
(2): See note 2(c) to our consolidated financial statements.
(3): See analysis of net unrealized gains/losses on energy derivatives in the gross margins discussion above.

Wholesale Energy Gross Margins. Our wholesale energy gross margins decreased to $805 million during 2004 compared to $931 million for 2003. The decrease is (in millions):

California energy sales receivables, refund and reserve changes		$	(106	)
Net unrealized gains/losses on energy derivatives			89	⁽¹⁾
Adjustment to October 2003 FERC settlement recorded in September 2004			(12	)
FERC settlement in October 2003			37
PJM region			(118	)⁽²⁾
MISO region			(29	)⁽³⁾
Margins associated with CenterPoint			(14	)⁽⁴⁾
West region			33	⁽⁵⁾
Other, net			(6	)

	Net decrease in margin	$	(126	)

(1): Increase primarily due to (a) $50 million increase in unrealized trading margins in 2004 as compared to 2003, (b) $15 million unrealized gain on positions primarily in the West region, (c) $18 million increase due to ineffectiveness in 2004 as compared to 2003 and (d) $10 million gain as a result of the change in market values on cash flow hedges de-designated in the West region in July 2004.
(2): Decrease primarily due to (a) increased fuel costs, (b) increased unplanned outages, (c) weaker market conditions due in part to milder weather and (d) the retirement of the old Seward plant in the fourth quarter of 2003 and Sayreville units 4 and 5 in February 2004. These decreases were partially offset by Hunterstown and new Seward, which achieved commercial operation in July 2003 and October 2004, respectively.
(3): Decrease primarily due to (a) increased purchased power and the operation of less efficient plants due to the unplanned outages in order to fulfill our contractual load obligations under a "provider of last resort" contract in the second quarter of 2004 and (b) lower volumes in the last half of 2004 as the demand under a "provider of last resort" contract declined due in part to milder weather.
(4): Decrease associated with reduction in billings to CenterPoint for engineering, technical and other support services provided to Texas Genco's facilities under a support agreement, which terminated in 2004.
(5): Increase due to (a) the Bighorn plant achieving commercial operation in February 2004 and entering into a power purchase agreement in June 2004, (b) the restart of Etiwanda units 4 and 3 in June and September 2004, respectively, and (c) increased generation to meet the needs of the Cal ISO.

Wholesale Energy Revenues.

		2004			2003			Change
		(in millions)
Wholesale energy third-party revenues		$	2,057		$	4,406		$	(2,349	)⁽¹⁾
Wholesale energy intersegment revenues			349			225			124	⁽²⁾
Unrealized losses			(32	)		(39	)		7	⁽³⁾

	Total wholesale energy revenues	$	2,374		$	4,592		$	(2,218	)

(1): Decrease primarily due to (a) $1.4 billion due to the application of EITF No. 03-11 (see note 2(d) to our consolidated financial statements), (b) a decrease in power sales volumes primarily due to fewer resales of purchased power as a result of changes in our strategies for risk management and hedging activities in late 2002 and early 2003 and (c) a $106 million change in our accounts receivable, refund obligation and credit reserves for energy sales in California. These decreases were partially offset by (a) an increase in power prices due to increased natural gas and coal prices and (b) a $25 million net change to our FERC settlement obligation.
(2): Increase primarily due to higher power prices as a result of increased natural gas prices, partially offset by lower volumes.
(3): See analysis of net unrealized gains/losses on energy derivatives in the gross margins discussion above.

Wholesale Energy Purchased Power, Fuel and Cost of Gas Sold.

		2004			2003		Change
		(in millions)
Wholesale energy third-party costs		$	1,649		$	3,659	$	(2,010	)⁽¹⁾
Unrealized (gains) losses			(80	)		2		(82	)⁽²⁾

	Total wholesale energy	$	1,569		$	3,661	$	(2,092	)

(1): Decrease primarily due to (a) $1.4 billion due to the application of EITF No. 03-11 (see note 2(d) to our consolidated financial statements) and (b) decreased purchased power volumes primarily due to changes in our strategies for risk management and hedging activities in late 2002 and early 2003. These decreases were partially offset by higher prices of natural gas, coal and purchased power.
(2): See analysis of net unrealized gains/losses on energy derivatives in the gross margins discussion above.

Operation and Maintenance.

		2004		2003		Change
		(in millions)
Retail energy		$	222	$	251	$	(29	)
Wholesale energy			560		558		2

	Consolidated	$	782	$	809	$	(27	)

The decrease in our retail energy segment is (in millions):

Severance		$	4
Salaries and benefits			(27	)
Other, net			(6	)

	Net decrease in expense	$	(29	)

The increase in our wholesale energy segment is (in millions):

Four power generation facilities achieving commercial operation in late July 2003 (Hunterstown and Choctaw), February 2004 (Bighorn) and late October 2004 (new Seward)		$	28
Planned power generation maintenance projects and outages			18
Unplanned power generation maintenance projects and outages			7
Termination of certain services to Texas Genco in May 2004			(11	)
Retirement/mothball of power generation units			(17	)
Salaries and benefits, excluding plant personnel			(34	)
Other, net			11

	Net increase in expense	$	2

Selling, General and Administrative.

Commodity Futures Trading Commission settlement in November 2003		$	(18	)
Severance costs			(16	)⁽¹⁾
Marketing			(16	)
Contractor services and professional fees			(14	)⁽²⁾
Legal costs			(13	)
Bad debt expense			(11	)
Taxes other than income taxes			(8	)⁽³⁾
Salaries and benefits			(7	)⁽⁴⁾
Restructuring costs associated with lease on corporate headquarters			13
Other, net			(12	)

	Net decrease in expense	$	(102	)

(1): Decrease primarily due to executive severance costs in 2003, partially offset by restructuring severance costs in 2004.
(2): Decrease primarily due to cost reduction efforts, reduced refinancing costs that were directly expensed and a settlement in 2004 related to our corporate headquarters lease. These decreases were partially offset by an increase in information technology related costs.
(3): Decrease primarily due to legal entity restructurings in 2003, which resulted in reduced franchise tax costs.
(4): Decrease primarily due to the impact of lower headcount partially offset by higher long-term incentive compensation benefits in 2004 of $21 million primarily due to the Key Employee Award Program expense of $25 million.

Loss on Sales of Receivables. The decrease of $3 million is primarily due to our ceasing to record sales of receivables as sales for accounting purposes due to the amendment of the facility in September 2004, partially offset by an increase in the amount of receivables sold in 2004. See note 6 to our consolidated financial statements.

Accrual for Payment to CenterPoint Energy, Inc. See note 13(d) to our consolidated financial statements.

Gain on Sale of Counterparty Claim. See note 13(e) to our consolidated financial statements.

Gains on Sales of Assets and Emission Allowances, Net. See note 19 to our consolidated financial statements.

Wholesale Energy Goodwill Impairment. See note 4 to our consolidated financial statements.

Depreciation and Amortization.

Equipment impairment charge in 2004 related to turbines and generators			$	16
Accelerated depreciation on Wayne facility in 2004 due to early retirement				12
Early retirement of certain units at Sayreville and Etiwanda facilities in 2003				(14	)
Depreciation for four power generation facilities achieving commercial operation in late July 2003 (Hunterstown and Choctaw), February 2004 (Bighorn) and late October 2004 (new Seward)				35
Net increase in amortization of emission allowances				27
Information systems placed into service during 2004				13
Write-off of software development costs				8
Net change in write-down of office building to fair value less costs to sell in 2003 and 2004				(5	)
	Other, net			3

		Net increase in expense	$	95

Other, net. Other, net changed by $4 million during 2004 compared to 2003 due primarily to a gain of $9 million recognized in 2004 from the sale of an investment.

Interest Expense.

Higher interest rates		$	54
Lower capitalized interest			38
Financing fees expensed			24
Amortization of deferred financing costs			(12	)
Decrease in outstanding debt			(93	)

	Net increase in expense	$	11

Income Tax Expense (Benefit). During 2004 and 2003, our effective tax rates were 29% and not meaningful, respectively. See note 10 to our consolidated financial statements.

Discontinued Operations. See note 20 to our consolidated financial statements.

Liquidity and Capital Resources

Sources of Liquidity and Capital Resources

Our principal sources of liquidity and capital resources are cash flows from operations, borrowings, net proceeds from asset sales, sales of emission allowances and securities offerings. For a description of factors that could affect our liquidity and capital resources, see "Risk Factors" in Item 1A of this Form 10-K and note 12 to our consolidated financial statements.

During 2005, excluding the changes in margin deposits of $1,214 million, we generated $104 million in operating cash flow from continuing operations. In addition, we received (a) $237 million of net proceeds from sales of assets and net sales of emission allowances and (b) $52 million in contingent purchase price payments from the sale of our former European energy operations.

In June 2005, we entered into a collateral arrangement with an energy supplier as a beneficiary in which we granted a security interest in notes receivable related to our receivables facility and related assets of some of our subsidiaries. As a result of this arrangement, the counterparty released approximately $76 million in pledged cash collateral and letters of credit to us. As of December 31, 2005, the collateral arrangement provided $250 million of security, the maximum permitted. In

September 2005, we amended our retail receivables facility to reduce fees, improve terms, extend its maturity until September 2006 and increase the maximum amount that may be borrowed from $350 million to $450 million. In October 2005, we issued $299 million of additional senior secured term loans due 2010.

As of February 13, 2006, we had total available liquidity of $512 million, comprised of $454 million in unused borrowing capacity under our senior secured revolver and $58 million of cash and cash equivalents.

Liquidity and Capital Requirements

Our liquidity and capital requirements primarily reflect our working capital needs, capital expenditures, debt service and collateral requirements. Examples of working capital needs include purchases of fuel and electricity, purchases of emission allowances, plant maintenance costs (including required environmental expenditures) and corporate costs such as payroll. Settlement costs associated with litigation and regulatory proceedings can also have a significant impact on our liquidity and cash requirements. For recent settlements, see note 13 to our consolidated financial statements.

Most counterparties require us to post collateral. The collateral amounts fluctuate depending on commodity prices, price volatility, levels of hedging activity, seasonality and other factors, including changes in our perceived credit standing. As of February 13, 2006, we had posted $2.6 billion in collateral; additional postings of $94 million could have been required by counterparties. Collateral postings increased by $1.5 billion from December 31, 2004 to December 31, 2005 due primarily to natural gas prices, which increased by 68% (based on the 24-month forward NYMEX price of natural gas) for that same period.

Historically, increases in prices of natural gas have caused our collateral postings to increase. However, in October 2005, we agreed to cap prices charged to our "price-to-beat" customers through June 2006. See "Business—Regulation—Texas" in Item 1 of this Form 10-K for a discussion of these discounts. To manage the supply risks associated with this commitment, we entered into a series of natural gas futures and options through December 2006. As a result of these futures and our remaining wholesale hedges, the impact of natural gas price movements on our level of collateral postings is significantly less than it has been historically. Although we retain exposure to changes in the shape of the natural gas forward curve, and our collateral postings may increase if near term prices fall relative to longer-dated prices, our collateral postings are not expected to fluctuate significantly in response to upward or downward shifts across the natural gas forward curve.

We have taken steps to maintain liquidity reserves that we believe prudent in the face of volatile natural gas prices. Over time, we expect our collateral requirements to decline because of our strategy of entering into fewer long-term hedges for our wholesale energy segment.

Capital Requirements. The following table provides information about our actual and estimated future capital requirements:

			2005		2006			2007			2008
			(in millions)
Maintenance capital expenditures:
	Retail energy		$	9	$	10		$	8		$	8
	Wholesale energy⁽¹⁾			28		71			108			59
	Other operations			7		10			8			8

				44		91			124			75
Environmental				8		50	⁽²⁾		85	⁽³⁾		150	⁽⁴⁾
Construction of new generating facilities				30		—			—			—

		Total capital expenditures	$	82	$	141		$	209		$	225

(1): Excludes $7 million for 2006 through 2011 for pre-existing environmental conditions and remediation, which have been accrued for in our consolidated balance sheet as of December 31, 2005. See "Business—Environmental Matters" in Item 1 of this Form 10-K.
(2): We have estimated environmental capital expenditures of $50 million to $70 million for 2006 and have included the low end of the range in the table.
(3): We have estimated environmental capital expenditures of $85 million to $120 million for 2007 and have included the low end of the range in the table.
(4): We have estimated environmental capital expenditures of $150 million to $220 million for 2008 and have included the low end of the range in the table.

Contractual Obligations and Contractual Commitments. The following table includes our obligations and commitments from continuing operations to make future payments under contracts as of December 31, 2005:

Contractual Obligations		Total		2006			2007		2008		2009		2010		2011 and thereafter
		(in millions)
Debt, including credit facilities⁽¹⁾		$	8,077	$	862	⁽²⁾	$	392	$	392	$	776	$	2,254	$	3,401
REMA operating lease payments			1,188		64			65		62		63		52		882
Other operating lease payments			583		91			65		62		62		60		243
Derivative liabilities			2,033		1,220			410		308		33		24		38
Other commodity commitments			2,290		532			320		180		151		119		988
Maintenance agreements obligations			953		24			52		47		34		63		733
Western states and Cornerstone settlements⁽³⁾			158		158			—		—		—		—		—
Other⁽⁴⁾			510		52			31		29		32		26		340

	Total contractual cash obligations	$	15,792	$	3,003		$	1,335	$	1,080	$	1,151	$	2,598	$	6,625

(1): Includes interest payments. Floating rate debt interest was estimated using projected forward LIBOR rates as of December 31, 2005.
(2): Includes $450 million retail receivables facility and $300 million of term loans to be paid with proceeds from the sale of our New York plants. See note 6 to our consolidated financial statements.
(3): Paid approximately $150 million in January 2006.
(4): Includes stadium naming rights, estimated pension and post retirement benefit payments and other contractual obligations.

As of December 31, 2005, we have estimated minimum sales commitments, which are not classified as derivative assets and liabilities, of (in millions):

2006		$	2,637
2007			1,286
2008			658
2009			355
2010			198

	Total	$	5,134

Contingencies and Guarantees. We are involved in a number of legal, environmental and other proceedings before courts and are subject to ongoing investigations by certain governmental agencies that could negatively impact our liquidity. See notes 10 and 12 to our consolidated financial statements and "Risk Factors" in Item 1A of this Form 10-K.

We also enter into guarantee and indemnification arrangements in the normal course of business. See note 11(b) to our consolidated financial statements.

Credit Risk

By extending credit to our counterparties, we are exposed to credit risk. For a discussion of our credit risk and policy, see note 2(e) to our consolidated financial statements.

As of December 31, 2005, our derivative assets and accounts receivable from our wholesale energy and ERCOT power supply counterparties, after taking into consideration netting within each contract and any master netting contracts with counterparties, are:

Credit Rating Equivalent		Exposure Before Collateral⁽¹⁾		Credit Collateral Held⁽²⁾		Exposure Net of Collateral		Number of Counterparties >10%⁽³⁾	Net Exposure of Counterparties >10%⁽³⁾
		(dollars in millions)
Investment grade		$	295	$	67	$	228	—	$	—
Non-investment grade			734		—		734	1		708
No external ratings:⁽⁴⁾
	Internally rated—Investment grade		364		—		364	1		183
	Internally rated—Non-investment grade		239		2		237	1		210

	Total	$	1,632	$	69	$	1,563	3	$	1,101

(1): The table excludes amounts related to contracts classified as normal purchases and sales and non-derivative contractual commitments that are not recorded in our consolidated balance sheets, except for any related accounts receivable. Such contractual commitments contain credit and economic risk if a counterparty does not perform. Nonperformance could have a material adverse impact on our future results of operations, financial condition and cash flows.
(2): Collateral consists of cash, standby letters of credit and other forms approved by management.
(3): See note 2(e) to our consolidated financial statements.
(4): For unrated counterparties, we perform credit analyses including review of financial statements, contractual rights and restrictions and credit support such as parent company guarantees to create an internal credit rating.

Off-Balance Sheet Arrangements

As of December 31, 2005, we have no off-balance sheet arrangements. For information regarding our principles of consolidation, see note 2(b) to our consolidated financial statements.

Historical Cash Flows

Cash Flows—Operating Activities

2005 Compared to 2004 and 2004 Compared to 2003.

		2005			2004			2003			Change from 2004 to 2005			Change from 2003 to 2004
		(in millions)
Operating loss		$	(321	)	$	(13	)	$	(476	)	$	(308	)	$	463
Depreciation and amortization			446			453			358			(7	)		95
Wholesale energy goodwill impairment			—			—			985			—			(985	)
Gains on sales of assets and emission allowances, net			(168	)		(20	)		(3	)		(148	)		(17	)
Net unrealized losses on energy derivatives			192			224			48			(32	)		176
Western states and Cornerstone settlements			359			—			—			359			—
California reserve changes			(1	)		11			(95	)		(12	)		106
Accrual for (payment to) CenterPoint, net.			—			(175	)		47			175			(222	)
Receivables facility proceeds, net			—			232			23			(232	)		209
Margin deposits on energy trading and hedging activities			(1,214	)⁽¹⁾		(451	)⁽¹⁾		223	⁽²⁾		(763	)		(674	)
Net option premiums sold (purchased)			3			(5	)		(101	)		8			96
Interest payments			(347	)		(326	)		(286	)		(21	)		(40	)
Change in accounts and notes receivable, net and accounts payable			35	⁽³⁾		—			(98	)⁽⁴⁾		35			98
Income tax refunds received (net of income taxes paid)			(22	)		62			77			(84	)		(15	)
Other, net			(72	)		13			141			(85	)		(128	)

	Net cash provided by (used in) continuing operations from operating activities		(1,110	)		5			843			(1,115	)		(838	)
	Net cash provided by discontinued operations from operating activities		193			101			151			92			(50	)

	Net cash provided by (used in) operating activities	$	(917	)	$	106		$	994		$	(1,023	)	$	(888	)

(1): Change primarily due to both a decrease in net unrealized value of our broker accounts and increased counterparty obligations.
(2): Change primarily due to the conversion of collateral posted to letters of credit from cash.
(3): Change primarily due to increased accounts payable as a result of increased power purchases in our wholesale energy segment, partially offset by increased accounts receivable due to increases in sales prices to our retail customers.
(4): Change primarily due to decreased accounts payable as a result of decreased purchased power and fuel purchases in our wholesale energy segment, partially offset by decreased accounts receivable related to decrease in power sales volumes.

Cash Flows—Investing Activities

2005 Compared to 2004 and 2004 Compared to 2003.

		2005			2004			2003			Change from 2004 to 2005			Change from 2003 to 2004
		(in millions)
Capital expenditures			(82	)		(160	)		(548	)		78	⁽¹⁾		388	⁽¹⁾
Proceeds from sales of assets, net			149	⁽²⁾		11			2			138			9
Net sales (purchases) of emission allowances			88			(65	)		(62	)		153			(3	)
Restricted cash			14			179			(42	)		(165	)⁽³⁾		221	⁽³⁾
Other, net			6			16			4			(10	)		12

	Net cash provided by (used in) continuing operations from investing activities		175			(19	)		(646	)		194			627
	Net cash provided by discontinued operations from investing activities		131	⁽⁴⁾		919	⁽⁵⁾		1,563	⁽⁶⁾		(788	)		(644	)

	Net cash provided by investing activities	$	306		$	900		$	917		$	(594	)	$	(17	)

(1): Decrease due to completion of our power generation development projects. Hunterstown and Choctaw were completed in July 2003, Bighorn was completed in February 2004 and new Seward was completed in October 2004.
(2): Includes $76 million, $42 million and $28 million related to sales of El Dorado, REMA hydropower plants and landfill-gas fueled power plants, respectively.
(3): Change primarily due to the refinancing in December 2004.
(4): Includes $100 million of net cash proceeds from the sale of Ceredo.
(5): Includes $804 million of net cash proceeds from the sale of hydropower plants.
(6): Includes $1.4 billion of net cash proceeds from the sale of European energy operations and $285 million of net cash proceeds from the sale of Desert Basin.

Cash Flows—Financing Activities

2005 Compared to 2004 and 2004 Compared to 2003.

		2005			2004			2003			Change from 2004 to 2005			Change from 2003 to 2004
		(in millions)
Payments of senior secured term loans due 2007		$	—		$	(1,147	)	$	(2,048	)	$	1,147		$	901
Payments of Orion Power MidWest, L.P. term loan and credit facility			—			(427	)		(135	)		427			(292	)
Payment on senior revolving credit facility			—			—			(350	)		—			350
Payments on senior secured revolver due 2007			—			(183	)		(1,108	)		183			925
Net borrowings under (payments on) receivables facility			223			(123	)		—			346			(123	)
Payments of financing costs			(1	)		(72	)		(166	)		71			94
(Payments) draws under letters of credit to support REMA's lease obligations			(28	)		(14	)		42			(14	)		(56	)
Proceeds under a construction agency financing commitment			—			—			95			—			(95	)
Proceeds from additional PEDFA bond issuance for new Seward plant			—			100			100			(100	)		—
Net borrowings under senior secured revolver due 2009			184			199			—			(15	)		199
Proceeds from senior secured notes			—			750			1,100			(750	)		(350	)
Net proceeds from term loans due 2010			190			662			—			(472	)		662
Proceeds from convertible senior subordinated notes			—			—			275			—			(275	)
Other, net			26			24			81			2			(57	)

	Net cash provided by (used in) continuing operations from financing activities		594			(231	)		(2,114	)		825			1,883
	Net cash used in discontinued operations from financing activities		—			(816	)		(775	)		816			(41	)

	Net cash provided by (used in) financing activities	$	594		$	(1,047	)	$	(2,889	)	$	1,641		$	1,842

New Accounting Pronouncements, Significant Accounting Policies and Critical Accounting Estimates

New Accounting Pronouncements

See note 2 to our consolidated financial statements.

Significant Accounting Policies

See note 2 to our consolidated financial statements.

Critical Accounting Estimates

We make a number of estimates and judgments in preparing our consolidated financial statements. These estimates can differ from actual results and have a significant impact on our recorded assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. We consider an estimate to be a critical accounting estimate if it requires a high level of subjectivity or judgment and a significant change in the estimate would have a material impact on our financial condition or results of operations. Each critical accounting estimate affects both our retail energy and wholesale energy segments, unless indicated otherwise. The Audit Committee of our Board of Directors reviews

each critical accounting estimate with our senior management. Further discussion of these accounting policies and estimates is in the notes to our consolidated financial statements.

Goodwill.

We consider the estimate of fair value to be a critical accounting estimate for our wholesale energy segment because (a) a goodwill impairment could have a material impact on our financial position and results of operations and (b) the estimate is based on a number of highly subjective judgments and assumptions. See notes 2(i) and 4 to our consolidated financial statements.

Property, Plant and Equipment.

We consider the fair value estimate used to calculate impairment of property, plant and equipment a critical accounting estimate. This estimate primarily affects our wholesale energy segment, which holds approximately 97% of our total net property, plant and equipment. See note 2(h) to our consolidated financial statements. In determining the existence of an impairment in carrying value, we make a number of subjective assumptions as to:

•: whether there is an indication of impairment;
•: the grouping of assets;
•: the intention of "holding" versus "selling" an asset;
•: the forecast of undiscounted expected future cash flow over the asset's estimated useful life; and
•: if an impairment exists, the fair value of the asset or asset group.

Derivative Assets and Liabilities.

We report our derivative assets and liabilities, for which the normal purchases and sales exception has not been made, at fair value and consider it to be a critical accounting estimate because they are highly susceptible to change from period to period and are dependent on many subjective factors, including:

•: estimated forward market price curves;
•: valuation adjustments relating to time value;
•: liquidity valuation adjustments;
•: costs of administering future obligations under existing contracts; and
•: credit adjustments, based on estimated defaults by counterparties.

To determine the fair value for energy derivatives where there are no market quotes or external valuation services, we rely on various modeling techniques. There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Therefore, it is possible that results in future periods may be materially different as contracts are ultimately settled.

For additional information regarding our derivative assets and liabilities, see notes 2(d) and 5 to our consolidated financial statements and "Quantitative and Qualitative Disclosures about Non-Trading and Trading Activities and Related Market Risks" in Item 7A of this Form 10-K.

Retail Energy Segment Estimated Revenues and Energy Supply Costs.

Accrued Unbilled Revenues. Accrued unbilled revenues of $400 million as of December 31, 2005 represented 4% of our consolidated revenues and 6% of our retail energy segment's revenues for 2005.

Accrued unbilled revenues of $328 million as of December 31, 2004 represented 4% of our consolidated revenues and 5% of our retail energy segment's revenues for 2004.

Accrued unbilled revenues are critical accounting estimates as volumes and rates are not precisely known at the end of each reporting period and the revenue amounts are material. If our estimate of either electricity usage, volumes or estimated rates were to increase or decrease by 3%, our accrued unbilled revenues as of December 31, 2005 would have increased or decreased by approximately $12 million. A 3% increase or decrease in both our estimated electricity usage and estimated rates would have increased or decreased our accrued unbilled revenues as of December 31, 2005 by approximately $24 million.

Estimated Energy Supply Costs. We record energy supply costs for electricity sales and services to retail customers based on estimated supply volumes and an estimated rate per MWh for the applicable reporting period. This is a critical accounting estimate as volumes and rates are not known at the end of each reporting period and the purchased power amounts are material.

A portion of our energy supply costs ($53 million and $57 million as of December 31, 2005 and 2004, respectively) consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities.

In estimating supply volumes, we consider the effects of historical customer volumes, weather factors and usage by customer class. We estimate our transmission and distribution delivery fees using the same method that we use for electricity sales and services to retail customers. In addition, we estimate ERCOT ISO fees based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the estimated rate and recorded as purchased power in the applicable reporting period. If our estimate of electricity usage volumes increased or decreased by 3%, our energy supply costs would have increased or decreased by approximately $14 million as of December 31, 2005. Changes in our volume usage would have resulted in a similar offsetting change in billed volumes, thus partially mitigating our energy supply costs.

Dependence on ERCOT ISO Settlement Procedures. Preliminary settlement information is due from the ERCOT ISO within two months after electricity is delivered. Final settlement information is due from the ERCOT ISO within six months after electricity is delivered. The six month settlement received from ERCOT is considered final as ERCOT will only resettle if there are data errors greater than 2% of that day's transaction dollars or if alternate dispute resolutions are granted. We record our estimated supply costs and related fees using estimated supply volumes, as discussed above, and adjust those costs upon receipt of the ERCOT ISO information. Delays in settlements could materially affect the accuracy of our recorded energy supply costs and related fees.

Change in Estimates. See note 2(c) to our consolidated financial statements.

Loss Contingencies.

We record loss contingencies when it is probable that a liability has been incurred and the amount can be reasonably estimated. We consider loss contingency estimates to be critical accounting estimates because they entail significant judgment regarding probabilities and ranges of exposure, and the ultimate outcome of the proceedings is unknown and could have a material adverse effect on our results of operations, financial condition and cash flows. See notes 12 and 13 to our consolidated financial statements.

Deferred Tax Assets, Valuation Allowances and Tax Liabilities.

We estimate (a) income taxes in the jurisdictions in which we operate, (b) net deferred tax assets and liabilities based on expected future taxes in the jurisdictions in which we operate, (c) valuation

allowances for deferred tax assets and (d) contingent tax liabilities for estimated exposures related to our current tax positions. These estimates are considered a critical accounting estimate because they require projecting future operating results (which is inherently imprecise). Also, these estimates depend on assumptions regarding our ability to generate future taxable income during the periods in which temporary differences are deductible. See note 10 to our consolidated financial statements for additional information. During 2005 and 2004, we revised our estimates of certain state tax effective rates and reflected these changes in our state deferred tax assets and liabilities.

As of December 31, 2005, we have not recorded a valuation allowance against our deferred tax assets for federal net operating loss carryforwards. Management believes that it is more likely than not that we will realize the federal net operating loss deferred tax assets. Key factors in this assessment include an evaluation of our recent history of earnings and losses (as adjusted), future reversals of temporary differences and identification of other sources of future taxable income, including the identification of tax planning strategies. However, we have recorded valuation allowances against some deferred tax assets for state operating loss carryforwards. The difference in estimates for federal and state operating loss carryforwards is primarily due to our inability to offset state taxable income in one jurisdiction against state taxable losses in another jurisdiction. During 2005, we released valuation allowances against our capital loss carryforwards as the result of net capital gains recorded during the year and the identification of various tax planning strategies that would make the realization of the remaining capital loss carryforwards more likely than not.

Item 7A. Quantitative and Qualitative Disclosures about Non-Trading and Trading Activities and Related Market Risks.

Market Risks and Risk Management

Our primary market risk exposure relates to fluctuations in commodity prices. We also have market risk exposure related to changes in interest rates. As described in note 2(d) to our consolidated financial statements, we have a risk control framework to manage our risk exposure. However, the effectiveness of this framework can never be completely estimated or fully assured. For example, we could experience hedge ineffectiveness from basis price differences, transmission issues, price correlation issues, volume variation or other factors. In addition, a reduction in market liquidity may impair the effectiveness of our risk management practices and resulting hedge strategies. These and other factors could have a material adverse effect on our results of operations, financial condition and cash flows.

Non-trading Market Risks

Commodity Price Risk

Changes in commodity prices prior to the energy delivery period are inherent in our wholesale and retail energy businesses. We use derivative instruments such as futures, forwards, swaps and options, to execute our wholesale hedge strategy and retail supply procurement strategy as discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Business Overview" in Item 7 of this Form 10-K.

As of December 31, 2005, the fair values of the contracts related to our net non-trading derivative assets and liabilities are:

Source of Fair Value			2006			2007			2008			2009			2010			2011 and thereafter			Total fair value
			(in millions)
Prices actively quoted⁽¹⁾			$	(370	)	$	(137	)	$	(140	)	$	10		$	—		$	—		$	(637	)
Prices provided by other external sources⁽²⁾				86			139			(16	)		—			—			—			209
Prices based on models and other valuation methods⁽³⁾				23			(42	)		141			—			3			15			140

	Total mark-to-market non-trading derivatives			(261	)		(40	)		(15	)		10			3			15			(288	)
	Cash flow hedges			(206	)		(126	)		(49	)		(26	)		(25	)		(39	)		(471	)

		Total	$	(467	)	$	(166	)	$	(64	)	$	(16	)	$	(22	)	$	(24	)	$	(759	)

(1): Represents our NYMEX futures positions in natural gas, crude oil and power, which have quoted prices for the next 72, 30 and 36 months, respectively.
(2): Represents our forward positions in natural gas, coal and crude oil and power at points for which over-the-counter market broker quotes are available, which on average, extend 24 or 36 months into the future. Positions are valued against internally developed forward market price curves that are validated and recalibrated against over-the-counter broker quotes. This category includes some transactions whose prices are obtained from external sources and then modeled to hourly, daily or monthly prices, as appropriate.
(3): Represents the value of (a) our valuation adjustments for liquidity, credit and administrative costs, (b) options or structured transactions not quoted by an exchange or over-the-counter broker, but for which the prices of the underlying position are available and (c) transactions for which an internally developed price curve was constructed as a result of the long-dated nature of the transaction or the illiquidity of the market point.

The fair values shown in the table above are subject to significant changes due to fluctuating natural gas and power forward market prices, volatility and credit risk. Market prices assume a functioning market with an adequate number of buyers and sellers to provide liquidity. Insufficient market liquidity could significantly affect the values that could be obtained for these contracts, as well as the costs at which these contracts could be hedged.

We assess the risk of our non-trading derivatives using a sensitivity analysis that measures the potential loss in fair value based on a hypothetical 10% movement in the underlying energy prices. The gain (loss) impacts from our sensitivity analysis are:

As of December 31,		Market Prices		Fair Value of Cash Flow Hedges			Earnings Impact of Other Derivatives			Total Potential Loss in Fair Value
2005		10% decrease		$	(19	)	$	(174	)	$	(193	)
2004		10% increase			(119	)		31			(88	)

This risk analysis does not include the favorable impact that the same hypothetical price movements would have on our physical purchases and sales of fuel and power to which the hedges relate. The adverse impact of changes in commodity prices on our portfolio of non-trading energy derivatives held for hedging purposes would be offset by a favorable impact on the underlying hedged physical transactions, assuming:

•: the derivatives are not closed out in advance of their expected term;
•: the derivatives continue to function effectively as hedges of the underlying risk; and
•: as applicable, anticipated underlying transactions settle as expected.

If any of these assumptions cease to be true, we may experience a benefit or loss relative to the exposure hedged. Non-trading energy derivatives that qualify and are effective as cash flow hedges may still have some percentage that is not effective. See notes 2(d) and 5 to our consolidated financial statements.

Interest Rate Risk

As of December 31, 2005, all of our interest rate derivatives either expired or were terminated. We remain subject to the benefits or losses associated with movements in market interest rates related to our long-term debt and bank facility obligations as well as our floating rate debt and certain margin deposits, which are most vulnerable to changes in LIBOR.

We assess interest rate risk using a sensitivity analysis that measures the potential change in our interest expense based on a hypothetical one percentage point movement in the underlying variable interest rate indices.

If interest rates increased (decreased) one percentage point from their December 31, 2005 and 2004 levels, our annual interest expense would have increased (decreased) by $18 million and $12 million, respectively, and our annual interest expense, net of interest income, would have increased (decreased) by $0 and $6 million, respectively.

The above analysis does not include the mitigating effect of our interest rate hedges. If three-month LIBOR had exceeded 4.4%, an additional increase of one percentage point in interest rates would have increased our annual interest expense as of December 31, 2005 and 2004 by $3 million and $0, respectively, and our annual interest expense, net of interest income, would have decreased by $15 million and $6 million, respectively.

We estimated these amounts by considering the impact of hypothetical changes in interest rates on our variable-rate debt adjusted for: cash and cash equivalents and net margin deposits on energy trading and hedging activities outstanding at the respective balance sheet dates.

If interest rates decreased by one percentage point from their December 31, 2005 and 2004 levels, the fair market values of our fixed-rate debt would have increased by $200 million and $233 million, respectively.

Trading Market Risks

Prior to March 2003, we engaged in proprietary trading activities as discussed in note 5 to our consolidated financial statements. Trading positions entered into prior to our decision to exit this business are being closed on economical terms or are being retained and settled over the contract terms.

As of December 31, 2005, the fair values of the contracts related to our legacy trading positions and recorded as net derivative assets and liabilities are:

Source of Fair Value		2006			2007			2008		2009		2010		2011 and thereafter		Total fair value
		(in millions)
Prices actively quoted		$	9		$	12		$	—	$	—	$	—	$	—	$	21
Prices provided by other external sources			(10	)		(8	)		11		—		—		—		(7	)
Prices based on models and other valuation methods			(26	)		(11	)		—		3		—		—		(34	)

	Total	$	(27	)	$	(7	)	$	11	$	3	$	—	$	—	$	(20	)

The fair values in the above table are subject to significant changes based on fluctuating market prices and conditions. For further discussion of items that impact our portfolio of trading contracts and an explanation of the sources of fair value, see the discussion related to non-trading derivative assets and liabilities.

Our consolidated realized and unrealized margins relating to these positions are (income (loss)):

		2005			2004
		(in millions)
Realized		$	(17	)	$	(22	)
Unrealized			(28	)		26

	Total	$	(45	)	$	4

An analysis of these net derivative assets and liabilities is:

		2005			2004
		(in millions)
Fair value of contracts outstanding, beginning of period		$	26		$	(1	)
Contracts transferred to non-trading			(4	)		—
Contracts realized or settled			22	⁽¹⁾		22
Changes in valuation techniques			—			—
Changes in fair values attributable to market price and other market changes			(64	)		5

	Fair value of contracts outstanding, end of period Total	$	(20	)	$	26

(1): Amount includes realized loss of $17 million and deferred settlements of $5 million.

We primarily assess the risk of our legacy trading positions using a value-at-risk method to maintain our total exposure within limits set by the Audit Committee of our Board of Directors. Value-at-risk is the potential loss in value of trading positions due to adverse market movements over a defined time period within a specified confidence level. We use the parametric variance/covariance method with delta/gamma approximation to calculate value-at-risk.

Our value-at-risk model utilizes four major parameters:

•: Confidence level—95% for natural gas and petroleum products and 99% for power products;
•: Volatility—calculated daily from historical forward prices using the exponentially weighted moving average method;
•: Correlation—calculated daily from daily volatilities and historical forward prices using the exponentially weighted moving average method; and
•: Holding period—natural gas and petroleum products generally have two day-holding periods. Power products have holding periods of five to 20 days based on the risk profile of the portfolio and the liquidation period.

While we believe that our value-at-risk assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates. An inherent limitation of value-at-risk is that past market risk may not produce accurate predictions of future market risk. In addition, value-at-risk calculated for a specified holding period does not fully capture the market risk of positions that cannot be liquidated or offset with hedges within that specified period. Future transactions, market volatility, reduction of market liquidity, failure of counterparties to satisfy their contractual obligations and/or a failure of risk controls could result in material losses from our legacy trading positions.

The daily value-at-risk for our legacy trading positions is:

		2005		2004
		(in millions)
As of December 31		$	7	$	4
Year Ended December 31:
	Average		3		3
	High		9		11
	Low		—		1

Item 8. Financial Statements and Supplementary Data.

The information required by this Item is incorporated by reference from the consolidated financial statements beginning on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on this evaluation, these officers have concluded that, as of the end of such period, our disclosure controls and procedures are effective in alerting them on a timely basis to material information required to be included in our reports filed or submitted under the Securities Exchange Act of 1934, as amended.

Management's Report on Internal Control Over Financial Reporting

The information required by this Item is incorporated by reference from "Reliant Energy Inc.'s Report on Internal Control Over Financial Reporting" on page F-1.

Changes in Internal Controls

In connection with the evaluation described above, we identified no change in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during our fiscal quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

PART III

Item 10. Directors and Executive Officers of the Registrant.

See "Business—Executive Officers" in Item 1 of this Form 10-K. Pursuant to Instruction G to Form 10-K, we incorporate by reference the information to be disclosed in our definitive proxy statement for the annual stockholder meeting at which we will elect directors ("Proxy Statement").

Item 11. Executive Compensation.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Item 13. Certain Relationships and Related Transactions.

Item 14. Principal Accountant Fees and Services.

Pursuant to Instruction G to Form 10-K, we incorporate by reference into each of these items the information to be disclosed in our Proxy Statement.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)	List of Documents Filed as Part of this Report
	(1)	Index to Consolidated Financial Statements of Reliant Energy, Inc. and Subsidiaries.
		Reliant Energy, Inc.'s Report on Internal Control Over Financial Reporting	F-1
		Report of Independent Registered Public Accounting Firm	F-2
		Report of Independent Registered Public Accounting Firm	F-3
		Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003	F-4
		Consolidated Balance Sheets as of December 31, 2005 and 2004	F-5
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003	F-6
		Consolidated Statements of Stockholders' Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004 and 2003	F-8
		Notes to Consolidated Financial Statements	F-11
	(2)	Financial Statement Schedule.
		Schedule II—Reliant Energy, Inc. and Subsidiaries—Reserves for the Years Ended December 31, 2005, 2004 and 2003	F-69
	The following schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements: III, IV and V.
	The following financial statements are included in this report pursuant to Item 3-16 of Regulation S-X:
		Consolidated Financial Statements of Reliant Energy Retail Holdings, LLC and Subsidiaries.
		Report of Independent Registered Public Accounting Firm	F-70
		Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003	F-71
		Consolidated Balance Sheets as of December 31, 2005 and 2004	F-72
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003	F-73
		Consolidated Statements of Member's Equity and Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003	F-74
		Notes to Consolidated Financial Statements	F-75
		Consolidated Financial Statements of Reliant Energy Mid-Atlantic Power Holdings, LLC and Subsidiaries.
		Report of Independent Registered Public Accounting Firm	F-91
		Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003	F-92
		Consolidated Balance Sheets as of December 31, 2005 and 2004	F-93
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003	F-94
		Consolidated Statements of Member's Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004 and 2003	F-95
		Notes to Consolidated Financial Statements	F-96
		Consolidated Financial Statements of Orion Power Holdings, Inc. and Subsidiaries.
		Report of Independent Registered Public Accounting Firm	F-114
		Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003	F-115
		Consolidated Balance Sheets as of December 31, 2005 and 2004	F-116
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003	F-117
		Consolidated Statements of Stockholder's Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004 and 2003	F-118
		Notes to Consolidated Financial Statements	F-119

(3) Index to Exhibits.

The exhibits with the cross symbol (+) are filed with the Form 10-K. The exhibits with the asterisk symbol (*) are compensatory arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

Exhibit Number	Document Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1	Restated Certificate of Incorporation	Reliant Energy, Inc.'s Amendment No. 8 to Registration Statement on Form S-1, dated April 27, 2001	333-48038	3.1
3.2	Second Amended and Restated Bylaws	Reliant Energy, Inc.'s Current Report on Form 8-K, dated September 21, 2004	1-16455	99.1
3.3	Certificate of Ownership and Merger merging a wholly-owned subsidiary into registrant pursuant to Section 253 of the General Corporation Law of the State of Delaware, effective as of April 26, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated April 26, 2004	1-16455	3.1
4.1	Specimen Stock Certificate	Reliant Energy, Inc.'s Amendment No. 5 to Registration Statement on Form S-1, dated March 23, 2001	333-48038	4.1
4.2	Rights Agreement between Reliant Resources, Inc. and The Chase Manhattan Bank, as Rights Agent, including a form of Rights Certificate, dated as of January 15, 2001	Reliant Energy, Inc.'s Amendment No. 8 to Registration Statement on Form S-1, dated April 27, 2001	333-48038	4.2
4.3	Common Stock Warrant Agreement by Reliant Resources, Inc. for the benefit of the holders from time to time, dated as of March 28, 2003	Reliant Energy, Inc.'s Amendment No. 1 to Annual Report on Form 10-K/A for the year ended December 31, 2002	1-16455	4.3
4.4	Indenture relating to 5.00% Convertible Senior Subordinated Notes due 2010 between Reliant Resources, Inc. and Wilmington Trust Company, as Trustee, dated as of June 24, 2003	Reliant Energy, Inc.'s Registration Statement on Form S-3, dated July 24, 2003	333-107295	4.5

4.5	Registration Rights Agreement relating to 5.00% Convertible Senior Subordinated Notes due 2010 among Reliant Resources, Inc., Deutsche Bank Securities Inc., Goldman, Sachs & Co. and Banc of America Securities LLC, dated as of June 24, 2003	Reliant Energy, Inc.'s Registration Statement on Form S-3, dated July 24, 2003	333-107295	4.7
4.6	Indenture relating to 9.25% Senior Secured Notes due 2010 among Reliant Resources, Inc., the Guarantors listed in Schedule I thereto and Wilmington Trust Company, as Trustee, dated as of July 1, 2003	Reliant Energy, Inc.'s Registration Statement on Form S-4, dated July 24, 2003	333-107297	4.5
4.7	Indenture relating to 9.50% Senior Secured Notes due 2013 among Reliant Resources, Inc., the Guarantors listed in Schedule I thereto and Wilmington Trust Company, as Trustee, dated as of July 1, 2003	Reliant Energy, Inc.'s Registration Statement on Form S-4, dated July 24, 2003	333-107297	4.7
4.8	Form of Senior Indenture to be issued under universal shelf	Reliant Energy, Inc.'s Amendment No. 1 to Registration Statement on Form S-3, dated December 10, 2003	333-107296	4.5
4.9	Form of Subordinated Indenture to be issued under universal shelf	Reliant Energy, Inc.'s Amendment No. 1 to Registration Statement on Form S-3, dated December 10, 2003	333-107296	4.6
4.10	Senior Indenture among Reliant Energy, Inc. and Wilmington Trust Company, dated as of December 22, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 27, 2004	1-16455	4.1

4.11	First Supplemental Indenture relating to 6.75% Senior Secured Notes due 2014 between Reliant Energy, Inc., the Guarantors listed therein and Wilmington Trust Company, dated as of December 22, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 27, 2004	1-16455	4.2
4.12	Indenture between Orion Power Holdings, Inc. and Wilmington Trust Company, dated as of April 27, 2000	Orion Power Holdings, Inc. Registration Statement on Form S-1, dated August 18, 2000	333-44118	4.1
10.1	Master Separation Agreement between Reliant Resources, Inc. and Reliant Energy, Incorporated, dated as of December 31, 2000	CenterPoint Energy Houston Electric, LLC's (formerly known as Reliant Energy, Incorporated) Quarterly Report on Form 10-Q for the quarter ended March 31, 2001	1-3187	10.1
10.2	Tax Allocation Agreement between Reliant Resources, Inc. and Reliant Energy, Incorporated, dated as of December 31, 2000	CenterPoint Energy Houston Electric, LLC's (formerly known as Reliant Energy, Incorporated) Quarterly Report on Form 10-Q for the quarter ended March 31, 2001	1-3187	10.8
10.3	Second Amended and Restated Credit and Guaranty Agreement among (i) Reliant Energy, Inc., as Borrower; (ii) the Other Loan Parties referred to therein, as Guarantors; (iii) the Lenders party thereto; (iv) Bank of America, N.A., as Administrative Agent and Collateral Agent; (v) Barclays Bank PLC and Deutsche Bank Securities Inc., as Syndication Agents; and (vi) Goldman Sachs Credit Partners L.P. and Merrill Lynch Capital Corporation, as Documentation Agents, dated as of December 22, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 27, 2004	1-16455	10.1

10.4	Amendment No. 1 to Second Amended and Restated Credit and Guaranty Agreement, dated as of October 26, 2005	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 20, 2005	1-16455	10.3
10.5	Amendment No. 2 to Second Amended and Restated Credit and Guaranty Agreement, dated as of December 19, 2005	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 20, 2005	1-16455	10.1
10.6	Credit and Guaranty Agreement between (i) Reliant Energy, Inc., as Borrower; (ii) the Other Loan Parties, as Guarantors; (iii) the Other Lenders; (iv) Deutsche Bank AG, New York Branch, as Administrative Agent; and (v) Deutsche Bank Securities Inc., as Sole Lead Arranger, Sole Bookrunner and Sole Syndication Agent, dated as of October 7, 2005	Reliant Energy, Inc.'s Current Report on Form 8-K, dated October 11, 2005	1-16455	10.1
10.7	Amendment No. 1 to Credit and Guaranty Agreement, dated as of October 26, 2005	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 20, 2005	1-16455	10.4
10.8	Amendment No. 2 to Credit and Guaranty Agreement, dated as of December 19, 2005	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 20, 2005	1-16455	10.2
10.9	Guarantee Agreement relating to Pennsylvania Economic Development Financing Authority Exempt Facilities Revenue Bonds (Reliant Energy Seward, LLC Project) Series 2001A between Reliant Energy, Inc., as Guarantor, and J.P. Morgan Trust Company, National Association, as Trustee, dated as of December 22, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 27, 2004	1-16455	10.2

10.10	Guarantee Agreement relating to Pennsylvania Economic Development Financing Authority Exempt Facilities Revenue Bonds (Reliant Energy Seward, LLC Project) Series 2002A between Reliant Energy, Inc., as Guarantor, and J.P. Morgan Trust Company, National Association, as Trustee, dated as of December 22, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 27, 2004	1-16455	10.3
10.11	Guarantee Agreement relating to Pennsylvania Economic Development Financing Authority Exempt Facilities Revenue Bonds (Reliant Energy Seward, LLC Project) Series 2002B between Reliant Energy, Inc., as Guarantor, and J.P. Morgan Trust Company, National Association, as Trustee, dated as of December 22, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 27, 2004	1-16455	10.4
10.12	Guarantee Agreement relating to Pennsylvania Economic Development Financing Authority Exempt Facilities Revenue Bonds (Reliant Energy Seward, LLC Project) Series 2003A between Reliant Energy, Inc., as Guarantor, and J.P. Morgan Trust Company, National Association, as Trustee, dated as of December 22, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 27, 2004	1-16455	10.5

10.13	Guarantee Agreement relating to Pennsylvania Economic Development Financing Authority Exempt Facilities Revenue Bonds (Reliant Energy Seward, LLC Project) Series 2004A between Reliant Energy, Inc., as Guarantor, and J.P. Morgan Trust Company, National Association, as Trustee, dated as of December 22, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated December 27, 2004	1-16455	10.6
10.14	Facility Lease Agreement between Conemaugh Lessor Genco LLC and Reliant Energy Mid-Atlantic Power Holdings, LLC, dated as of August 24, 2000	Reliant Energy Mid-Atlantic Power Holdings, LLC's Registration Statement on Form S-4, dated December 8, 2000	333-51464	4.6a
10.15	Schedule identifying substantially identical agreements to Facility Lease Agreement constituting Exhibit 10.14	Reliant Energy Mid-Atlantic Power Holdings, LLC's Registration Statement on Form S-4, dated December 8, 2000	333-51464	4.6b
10.16	Pass Through Trust Agreement between Reliant Energy Mid-Atlantic Power Holdings, LLC and Bankers Trust Company, made with respect to the formation of the Series A Pass Through Trust and the issuance of 8.554% Series A Pass Through Certificates, dated as of August 24, 2000	Reliant Energy Mid-Atlantic Power Holdings, LLC's Registration Statement on Form S-4, dated December 8, 2000	333-51464	4.4a
10.17	Schedule identifying substantially identical agreements to Pass Through Trust Agreement constituting Exhibit 10.16	Reliant Energy Mid-Atlantic Power Holdings, LLC's Registration Statement on Form S-4, dated December 8, 2000	333-51464	4.4b

10.18	Participation Agreement among (i) Conemaugh Lessor Genco LLC, as Owner Lessor; (ii) Reliant Energy Mid-Atlantic Power Holdings, LLC, as Facility Lessee; (iii) Wilmington Trust Company, as Lessor Manager; (iv) PSEGR Conemaugh Generation, LLC, as Owner Participant; (v) Bankers Trust Company, as Lease Indenture Trustee; and (vi) and Bankers Trust Company, as Pass Through Trustee, dated as of August 24, 2000	Reliant Energy Mid-Atlantic Power Holdings, LLC's Registration Statement on Form S-4, dated December 8, 2000	333-51464	4.5a
10.19	Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 10.18	Reliant Energy Mid-Atlantic Power Holdings, LLC's Registration Statement on Form S-4, dated December 8, 2000	333-51464	4.5b
+10.20	First Amendment to Participation Agreement, dated as of November 15, 2001
+10.21	Schedule identifying substantially identical agreements to First Amendment to Participation Agreement constituting Exhibit 10.20
+10.22	Second Amendment to Participation Agreement, dated as of June 18, 2003
+10.23	Schedule identifying substantially identical agreements to Second Amendment to Participation Agreement constituting Exhibit 10.22

10.24	Lease Indenture of Trust, Mortgage and Security Agreement between Conemaugh Lessor Genco LLC, as Owner Lessor, and Bankers Trust Company, as Lease Indenture Trustee, dated as of August 24, 2000	Reliant Energy Mid-Atlantic Power Holdings, LLC's Registration Statement on Form S-4, dated December 8, 2000	333-51464	4.8a
10.25	Schedule identifying substantially identical agreements to Lease Indenture of Trust constituting Exhibit 10.24	Reliant Energy Mid-Atlantic Power Holdings, LLC's Registration Statement on Form S-4, dated December 8, 2000	333-51464	4.8b
10.26	Purchase and Sale Agreement by and between Orion Power Holdings, Inc., Reliant Energy, Inc., Great Lakes Power Inc. and Brascan Corporation, dated as of May 18, 2004	Reliant Energy, Inc.'s Current Report on Form 8-K, dated May 21, 2004	1-16455	99.2
10.27	Purchase and Sale Agreement between Orion Power Holdings, Inc., as Seller, Reliant Energy, Inc., as Guarantor, and Astoria Generating Company Acquisitions, L.L.C., as Buyer, dated as of September 30, 2005	Reliant Energy, Inc.'s Current Report on Form 8-K, dated October 6, 2005	1-16455	10.1
10.28	Settlement and Release of Claims Agreement between among each of the Reliant Parties, OMOI, each of the California Parties, each of the Additional Claimants, each of the Class Action Parties and each of the Local Governmental Parties (each as defined therein), dated as of October 12, 2005	Reliant Energy, Inc.'s Current Report on Form 8-K, dated October 20, 2005	1-16455	10.1

*10.29	Executive Life Insurance Plan, effective as of January 1, 1994, including the first and second amendments thereto (Reliant Energy, Inc. has adopted certain obligations under this plan with respect to the following individuals: James Ajello, Daniel Hannon and Brian Landrum)	Reliant Energy, Inc.'s Amendment No. 8 to Registration Statement on Form S-1, dated April 27, 2001	333-48038	10.30
*10.30	Transition Stock Plan, effective as of May 4, 2001	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2001	1-16455	10.37
*10.31	2002 Stock Plan, effective as of March 1, 2002	Reliant Energy, Inc.'s Registration Statement on Form S-8, dated April 19, 2002	333-86610	4.5
*10.32	Annual Incentive Compensation Plan, effective as of January 1, 2001	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2001	1-16455	10.9
*10.33	2002 Annual Incentive Compensation Plan for Executive Officers, effective as of March 1, 2002	Reliant Energy, Inc.'s 2002 Proxy Statement on Schedule 14A	1-16455	Appendix I
*10.34	Long Term Incentive Plan, effective as of January 1, 2001	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2001	1-16455	10.10
*10.35	2002 Long-Term Incentive Plan, effective as of June 6, 2002	Reliant Energy, Inc.'s Registration Statement on Form S-8, dated April 19, 2002	333-86612	4.5
*10.36	Deferral Plan, effective as of January 1, 2002	Reliant Energy, Inc.'s Registration Statement on Form S-8, dated December 7, 2001	333-74790	4.1
*10.37	First Amendment to Deferral Plan, effective as of January 14, 2003	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2003	1-16455	10.5
*10.38	Successor Deferral Plan, effective as of January 1, 2002	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2004	1-16455	10.30

*10.39	Deferred Compensation Plan, effective as of September 1, 1985, including the first nine amendments thereto (This is now a part of the plan listed as Exhibit 10.38)	Reliant Energy, Inc.'s Amendment No. 8 to Registration Statement on Form S-1, dated April 27, 2001	333-48038	10.25
*10.40	Deferred Compensation Plan, as amended and restated effective as of January 1, 1989, including the first nine amendments (This is now a part of the plan listed as Exhibit 10.38)	Reliant Energy, Inc.'s Amendment No. 8 to Registration Statement on Form S-1, dated April 27, 2001	333-48038	10.26
*10.41	Deferred Compensation Plan, as amended and restated effective as of January 1, 1991, including the first ten amendments thereto (This is now a part of the plan listed as Exhibit 10.38)	Reliant Energy, Inc.'s Amendment No. 8 to Registration Statement on Form S-1, dated April 27, 2001	333-48038	10.27
*10.42	Benefit Restoration Plan, as amended and restated effective as of July 1, 1991, including the first amendment thereto (This is now a part of the plan listed as Exhibit 10.38)	Reliant Energy, Inc.'s Amendment No. 8 to Registration Statement on Form S-1, dated April 27, 2001	333-48038	10.12
*10.43	Key Employee Award Program 2004-2006 of the 2002 Long-Term Incentive Plan and the Form of Agreement for Key Employee Award Program, effective as of February 13, 2004	Reliant Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004	1-16455	10.1
+*10.44	First Amendment to the Key Employee Award Program, effective as of August 10, 2005
*10.45	Form of 2002 Stock Plan Nonqualified Stock Option Award Agreement, 2003 Grants	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2004	1-16455	10.39
*10.46	Form of 2002 Stock Plan Restricted Stock Award Agreement, 2003 Grants	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2004	1-16455	10.40

+*10.47	Change in Control Agreement between Reliant Energy, Inc., Reliant Energy Corporate Services, LLC and Joel V. Staff, effective as of January 15, 2006
+*10.48	Severance Agreement between Reliant Resources, Inc. and Mark M. Jacobs, effective as of August 1, 2005
+*10.49	Change in Control Agreement between Reliant Energy, Inc., Reliant Energy Corporate Services, LLC and Mark M. Jacobs, effective as of March 13, 2006
+*10.50	Change in Control Agreement between Reliant Energy, Inc., Reliant Energy Corporate Services, LLC and Michael L. Jines, effective as of January 15, 2006
+*10.51	Change in Control Agreement between Reliant Energy, Inc., Reliant Energy Corporate Services, LLC and Brian Landrum, effective as of January 15, 2006
+*10.52	Change in Control Agreement between Reliant Energy, Inc., Reliant Energy Corporate Services, LLC and Jerry J. Langdon, effective as of January 15, 2006
*10.53	Severance Agreement between Reliant Resources, Inc. and James B. Robb, effective as of January 14, 2003	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2003	1-16455	10.4
+*10.54	Amendment to Severance Agreement between Reliant Resources, Inc. and James B. Robb, effective as of November 29, 2005

*10.55	Severance Agreement between Reliant Resources, Inc. and Robert W. Harvey, effective as of May 30, 2003	Reliant Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003	1-16455	10.1
*10.56	Amendment to Severance Agreement between Reliant Energy, Inc. and Robert W. Harvey, effective as of February 21, 2005	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2004	1-16455	10.43
+*10.57	Reliant Energy, Inc. Executive Severance Plan, effective as of January 1, 2006
*10.58	Form of 2002 Long-Term Incentive Plan Nonqualified Stock Option Award Agreement for Directors	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2004	1-16455	10.53
*10.59	Form of 2002 Long-Term Incentive Plan Restricted Stock Award Agreement for Directors	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2004	1-16455	10.54
*10.60	Form of 2002 Long-Term Incentive Plan Quarterly Restricted and Premium Restricted Stock Units Award Agreement for Directors	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2004	1-16455	10.55
*10.61	Form of 2002 Long-Term Incentive Plan Quarterly Common Stock and Premium Restricted Stock Award Agreement for Directors	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2004	1-16455	10.56
*10.62	Schedule of 2005 director fees	Reliant Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2004	1-16455	10.57
+*10.63	Reliant Energy, Inc. Non-Employee Directors' Compensation Program, effective as of January 1, 2006
+12.1	Reliant Energy, Inc. and Subsidiaries Ratio of Earnings from Continuing Operations to Fixed Charges
+21.1	Subsidiaries of Reliant Energy, Inc.

+23.1		Consent of Deloitte & Touche LLP
+31.1		Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
+31.2		Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
+32.1		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	RELIANT ENERGY, INC.
		(Registrant)
March 15, 2006	By:	/s/ JOEL V. STAFF Joel V. Staff Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of March 15, 2006.

Signature		Title
/s/ JOEL V. STAFF Joel V. Staff		Chairman and Chief Executive Officer (Principal Executive Officer)
/s/ MARK M. JACOBS Mark M. Jacobs		Executive Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ THOMAS C. LIVENGOOD Thomas C. Livengood		Senior Vice President and Controller (Principal Accounting Officer)
/s/ E. WILLIAM BARNETT E. William Barnett		Director
/s/ DONALD J. BREEDING Donald J. Breeding		Director
/s/ KIRBYJON H. CALDWELL Kirbyjon H. Caldwell		Director
/s/ STEVEN L. MILLER Steven L. Miller		Director
/s/ LAREE E. PEREZ Laree E. Perez		Director
/s/ WILLIAM L. TRANSIER William L. Transier		Director

RELIANT ENERGY, INC.'S REPORT ON INTERNAL
CONTROL OVER FINANCIAL REPORTING

The management of Reliant Energy, Inc. and its subsidiaries (the Company) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2005. In making this assessment, our management used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment we believe that, as of December 31, 2005, our internal control over financial reporting is effective based on those criteria.

Our independent auditors have issued an audit report on our assessment of our internal control over financial reporting. This report appears on page F-2.

/s/ JOEL V. STAFF

Joel V. Staff
Chairman and Chief Executive Officer

/s/ MARK M. JACOBS

Mark M. Jacobs
Executive Vice President and Chief Financial Officer

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Reliant Energy, Inc. and Subsidiaries
Houston, Texas

We have audited management's assessment, included in Reliant Energy, Inc.'s Report on Internal Control Over Financial Reporting on page F-1 that Reliant Energy, Inc. and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005 based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule for the year ended December 31, 2005 of the Company and our report dated March 14, 2006 expressed an unqualified opinion on those financial statements and financial statement schedule.

DELOITTE & TOUCHE LLP

Houston, Texas
March 14, 2006

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Reliant Energy, Inc. and Subsidiaries
Houston, Texas

We have audited the accompanying consolidated balance sheets of Reliant Energy, Inc. and subsidiaries (the "Company"), as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule (Schedule II—Reserves) listed in the Index at Item 15(a)(2). These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Reliant Energy, Inc. and subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in note 2 to the consolidated financial statements, the Company changed its accounting for major maintenance to the "expense as incurred" method in 2004; and asset retirement obligations, energy trading contracts, consolidation of variable interest entities and its presentation of revenues and costs of sales associated with non-trading commodity derivative activities in 2003.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 14, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

DELOITTE & TOUCHE LLP

Houston, Texas
March 14, 2006

F-3

RELIANT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Thousands of Dollars, except per share amounts)

			2005			2004			2003
Revenues:
	Revenues (including $(218,081), $(32,007) and $(54,864) unrealized losses)		$	9,711,995		$	8,098,222		$	10,096,789

Expenses:
	Purchased power, fuel and cost of gas sold (including $25,846, $(192,395) and $7,270 unrealized gains (losses))			8,365,921			6,564,137			7,911,615
	Operation and maintenance			736,954			782,462			809,040
	Selling, general and administrative			292,486			326,171			428,453
	Western states and Cornerstone settlements			359,436			—			—
	Loss on sales of receivables			—			33,741			37,613
	Accrual for payment to CenterPoint Energy, Inc.			—			1,600			46,700
	Gain on sale of counterparty claim			—			(30,000	)		—
	Gains on sales of assets and emission allowances, net			(168,114	)		(19,834	)		(2,819	)
	Wholesale energy goodwill impairment			—			—			985,000
	Depreciation and amortization			445,871			453,042			356,845

		Total operating expense		10,032,554			8,111,319			10,572,447

Operating Loss				(320,559	)		(13,097	)		(475,658	)

Other Income (Expense):
	Income (loss) of equity investments, net			25,458			(9,478	)		(1,652	)
	Other, net			(22,672	)		13,455			8,435
	Interest expense			(399,281	)		(417,514	)		(406,809	)
	Interest income			23,227			34,960			34,955

		Total other expense		(373,268	)		(378,577	)		(365,071	)

Loss from Continuing Operations Before Income Taxes				(693,827	)		(391,674	)		(840,729	)
	Income tax expense (benefit)			(253,080	)		(115,214	)		75,092

Loss from Continuing Operations				(440,747	)		(276,460	)		(915,821	)
	Income (loss) from discontinued operations			110,799			239,800			(402,241	)

Loss Before Cumulative Effect of Accounting Changes				(329,948	)		(36,660	)		(1,318,062	)
	Cumulative effect of accounting changes, net of tax			(608	)		7,290			(24,055	)

Net Loss			$	(330,556	)	$	(29,370	)	$	(1,342,117	)

Basic and Diluted Earnings (Loss) per Share:
	Loss from continuing operations		$	(1.46	)	$	(0.93	)	$	(3.12	)
	Income (loss) from discontinued operations			0.37			0.81			(1.37	)

	Loss before cumulative effect of accounting changes			(1.09	)		(0.12	)		(4.49	)
	Cumulative effect of accounting changes, net of tax			—			0.02			(0.08	)

	Net loss		$	(1.09	)	$	(0.10	)	$	(4.57	)

See Notes to our Consolidated Financial Statements

F-4

RELIANT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, except per share amounts)

			December 31,
			2005			2004
ASSETS
Current Assets:
	Cash and cash equivalents		$	88,397		$	105,054
	Restricted cash			26,906			15,610
	Accounts and notes receivable, principally customer, net of allowance of $34,054 and $41,636			1,171,673			1,071,312
	Inventory			299,099			245,682
	Derivative assets			725,964			305,924
	Margin deposits on energy trading and hedging activities			1,716,035			505,547
	Accumulated deferred income taxes			361,547			118,032
	Prepayments and other current assets			137,498			186,414
	Current assets of discontinued operations			203,332			104,276

		Total current assets		4,730,451			2,657,851

Property, Plant and Equipment, net				5,934,060			6,437,761

Other Assets:
	Goodwill			386,594			440,534
	Other intangibles, net			510,582			540,583
	Net California receivables subject to refund			—			200,086
	Equity investments			29,524			83,819
	Derivative assets			527,799			272,254
	Prepaid lease			259,412			243,463
	Restricted cash			—			25,547
	Other			309,588			259,367
	Long-term assets of discontinued operations			880,796			1,032,759

		Total other assets		2,904,295			3,098,412

Total Assets			$	13,568,806		$	12,194,024

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
	Current portion of long-term debt and short-term borrowings		$	789,325		$	618,854
	Accounts payable, principally trade			886,965			566,104
	Derivative liabilities			1,219,954			401,881
	Margin deposits from customers on energy trading and hedging activities			15,588			19,040
	Other			397,942			463,528
	Current liabilities of discontinued operations			96,456			29,184

		Total current liabilities		3,406,230			2,098,591

Other Liabilities:
	Accumulated deferred income taxes			69,421			229,352
	Derivative liabilities			812,695			311,222
	Other			319,662			387,223
	Long-term liabilities of discontinued operations			779,678			842,425

		Total other liabilities		1,981,456			1,770,222

Long-term Debt				4,317,427			3,938,857

Commitments and Contingencies
Stockholders' Equity:
	Preferred stock; par value $0.001 per share (125,000,000 shares authorized; none outstanding)			—			—
	Common stock; par value $0.001 per share (2,000,000,000 shares authorized; 304,900,193 and 299,812,305 issued)			66			61
	Additional paid-in capital			5,846,747			5,790,007
	Treasury stock at cost (0 and 128,264 shares)			—			(2,209	)
	Retained deficit			(1,698,504	)		(1,367,948	)
	Accumulated other comprehensive loss			(284,281	)		(29,351	)
	Accumulated other comprehensive loss of discontinued operations			(335	)		(4,206	)

		Total stockholders' equity		3,863,693			4,386,354

Total Liabilities and Stockholders' Equity			$	13,568,806		$	12,194,024

See Notes to our Consolidated Financial Statements

F-5

RELIANT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

					2005			2004			2003
Cash Flows from Operating Activities:
	Net loss				$	(330,556	)	$	(29,370	)	$	(1,342,117	)
	(Income) loss from discontinued operations					(110,799	)		(239,800	)		402,241

	Net loss from continuing operations and cumulative effect of accounting changes					(441,355	)		(269,170	)		(939,876	)
	Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
		Cumulative effect of accounting changes				608			(7,290	)		24,055
		Wholesale energy goodwill impairment				—			—			985,000
		Depreciation and amortization				445,871			453,042			356,845
		Deferred income taxes				(278,992	)		(108,688	)		55,259
		Net unrealized losses on energy derivatives				192,235			224,402			47,594
		Amortization of deferred financing costs				15,110			77,881			89,619
		Gains on sales of assets and emission allowances, net				(168,114	)		(19,834	)		(2,819	)
		Western states and Cornerstone settlements				359,436			—			—
		(Income) loss of equity investments, net				(25,458	)		9,478			1,652
		Accrual for payment to CenterPoint Energy, Inc.				—			1,600			46,700
		Other, net				27,498			(7,058	)		(4,971	)
		Changes in other assets and liabilities:
			Accounts and notes receivable, net			(109,736	)		(59,723	)		106,217
			Receivables facility proceeds, net			—			232,000			23,000
			Inventory			(42,253	)		(14,744	)		25,323
			Margin deposits on energy trading and hedging activities, net			(1,213,940	)		(450,851	)		223,173
			Net derivative assets and liabilities			10,978			12,547			(71,152	)
			Accounts payable			144,466			59,233			(204,522	)
			Payment to CenterPoint Energy, Inc.			—			(176,600	)		—
			Other current assets			33,071			(37,399	)		(29,722	)
			Other assets			(32,605	)		(5,562	)		(54,285	)
			Taxes payable/receivable			3,053			47,652			44,721
			Other current liabilities			(34,479	)		1,815			78,446
			Other liabilities			4,495			42,617			42,097

				Net cash provided by (used in) continuing operations from operating activities		(1,110,111	)		5,348			842,354
				Net cash provided by discontinued operations from operating activities		192,948			100,165			151,356

				Net cash provided by (used in) operating activities		(917,163	)		105,513			993,710

Cash Flows from Investing Activities:
	Capital expenditures					(82,296	)		(159,671	)		(548,391	)
	Proceeds from sales of assets, net					149,345			11,325			2,591
	Proceeds from sales of emission allowances					234,421			59,662			14,073
	Purchases of emission allowances					(145,769	)		(124,241	)		(76,486	)
	Restricted cash					14,251			178,885			(42,214	)
	Other					5,500			16,207			4,400

				Net cash provided by (used in) continuing operations from investing activities		175,452			(17,833	)		(646,027	)
				Net cash provided by discontinued operations from investing activities		130,700			919,043			1,563,495

				Net cash provided by investing activities		306,152			901,210			917,468

Cash Flows from Financing Activities:
	Proceeds from long-term debt					299,000			1,512,000			1,612,120
	Payments of long-term debt					(148,333	)		(1,597,568	)		(2,141,137	)
	Increase (decrease) in short-term borrowings and revolving credit facilities, net					407,000			(108,350	)		(1,425,445	)
	Proceeds from issuances of stock					37,885			24,618			7,531
	Payments of financing costs					(1,198	)		(71,884	)		(166,407	)
	Other, net					—			9,156			—

				Net cash provided by (used in) continuing operations from financing activities		594,354			(232,028	)		(2,113,338	)
				Net cash used in discontinued operations from financing activities		—			(815,885	)		(775,482	)

				Net cash provided by (used in) financing activities		594,354			(1,047,913	)		(2,888,820	)

F-6

Effect of Exchange Rate Change on Cash				—			—			9,071

Net Change in Cash and Cash Equivalents				(16,657	)		(41,190	)		(968,571	)

Cash and Cash Equivalents at Beginning of Period				105,054			146,244			1,114,815

Cash and Cash Equivalents at End of Period			$	88,397		$	105,054		$	146,244

Supplemental Disclosure of Cash Flow Information:
	Cash Payments:
		Interest paid (net of amounts capitalized) for continuing operations	$	347,249		$	326,366		$	285,987
		Income taxes paid (net of income tax refunds received) for continuing operations	$	21,812		$	(61,808	)	$	(77,402	)

See Notes to our Consolidated Financial Statements

F-7

RELIANT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)

(Thousands of Dollars)

			Common Stock		Additional Paid In Capital			Treasury Stock			Retained Earnings (Deficit)			Unrealized Gain (Loss) on Available For Sale Securities			Deferred Derivative Gains (Losses)			Foreign Currency Translation Adjustments			Additional Minimum Benefits Liability			Total Accumulated Other Comprehensive Income (Loss)			Discontinued Operations Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity			Comprehensive Income (Loss)
Balance December 31, 2002			$	61	$	5,836,957		$	(158,483	)	$	3,539		$	1,116		$	(14,642	)	$	(1,524	)	$	(2,646	)	$	(17,696	)	$	(11,490	)	$	5,652,888
	Net loss											(1,342,117	)																				(1,342,117	)	$	(1,342,117	)
	Contributions from CenterPoint Energy, Inc.					45,498																											45,498
	Issuance of warrants					14,360																											14,360
	Transactions under stock plans					(55,377	)		68,714																								13,337
	Other comprehensive income (loss):
		Foreign currency translation adjustments, net of tax of $0 and $17 million $98 million																			543						543			(34,343	)		(33,800	)		543
		Changes in minimum pension liability, net of tax of $1 million																						1,369			1,369						1,369			1,369
		Deferred gain from cash flow hedges, net of tax of $45 million and $8 million																75,808									75,808			(14,509	)		61,299			75,808
		Reclassification of net deferred gain from cash flow hedges into net loss, net of tax of $61 million and $21 million																(79,466	)								(79,466	)		39,545			(39,921	)		(79,466	)
		Unrealized loss on available-for-sale securities, net of tax of $0													(350	)											(350	)					(350	)		(350	)
		Reclassification adjustments for gains on sales of available-for-sale securities realized in net loss, net of tax of $0													(764	)											(764	)					(764	)		(764	)
		Other comprehensive loss from discontinued operations																																		(9,307	)

		Comprehensive loss																																	$	(1,354,284	)

Balance December 31, 2003				61		5,841,438			(89,769	)		(1,338,578	)		2			(18,300	)		(981	)		(1,277	)		(20,556	)		(20,797	)		4,371,799

See Notes to our Consolidated Financial Statements

F-8

RELIANT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) (Continued)
(Thousands of Dollars)

			Common Stock		Additional Paid In Capital			Treasury Stock			Retained Earnings (Deficit)			Unrealized Gain (Loss) on Available For Sale Securities			Deferred Derivative Gains (Losses)			Foreign Currency Translation Adjustments		Additional Minimum Benefits Liability			Total Accumulated Other Comprehensive Income (Loss)			Discontinued Operations Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity			Comprehensive Income (Loss)
	Net loss											(29,370	)																			(29,370	)	$	(29,370	)
	Distribution to CenterPoint Energy, Inc.					(509	)																									(509	)
	Warrants					57																										57
	Transactions under stock plans					(50,979	)		87,560																							36,581
	Other comprehensive income (loss):
		Foreign currency translation adjustments, net of tax of $0																			981					981						981			981
		Changes in minimum pension liability, net of tax of $1 million																					1,129			1,129						1,129			1,129
		Deferred gain (loss) from cash flow hedges, net of tax of $24 million and $1 million																42,387								42,387			813			43,200			42,387
		Reclassification of net deferred (gain) loss from cash flow hedges into net loss, net of tax of $35 million and $11 million																(53,298	)							(53,298	)		15,778			(37,520	)		(53,298	)
		Unrealized loss on available-for-sale securities, net of tax of $0													(8	)										(8	)					(8	)		(8	)
		Reclassification adjustments for gains on sales of available-for-sale securities realized in net loss, net of tax of $0													14											14						14			14
		Other comprehensive income from discontinued operations																																	16,591

		Comprehensive loss																																$	(21,574	)

Balance December 31, 2004			$	61	$	5,790,007		$	(2,209	)	$	(1,367,948	)	$	8		$	(29,211	)	$	—	$	(148	)	$	(29,351	)	$	(4,206	)	$	4,386,354

See Notes to our Consolidated Financial Statements

F-9

RELIANT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) (Continued)
(Thousands of Dollars)

			Common Stock		Additional Paid In Capital		Treasury Stock		Retained Earnings (Deficit)			Unrealized Gain (Loss) on Available For Sale Securities			Deferred Derivative Gains (Losses)			Foreign Currency Translation Adjustments		Additional Minimum Benefits Liability			Total Accumulated Other Comprehensive Income (Loss)			Discontinued Operations Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity			Comprehensive Income (Loss)
	Net loss									(330,556	)																			(330,556	)	$	(330,556	)
	Contribution from CenterPoint Energy, Inc.					7,079																								7,079
	Warrants					1,411																								1,411
	Transactions under stock plans			5		48,250		2,209																						50,464
	Other comprehensive income (loss):
		Deferred gain (loss) from cash flow hedges, net of tax of $160 million and $1 million														(233,234	)							(233,234	)		2,378			(230,856	)		(233,234	)
		Reclassification of net deferred (gain) loss from cash flow hedges into net loss, net of tax of $9 million and $1 million														(21,688	)							(21,688	)		1,493			(20,195	)		(21,688	)
		Unrealized loss on available-for-sale securities, net of tax of $0											(8	)										(8	)					(8	)		(8	)
		Other comprehensive income from discontinued operations																															3,871

		Comprehensive loss																														$	(581,615	)

Balance December 31, 2005			$	66	$	5,846,747	$	—	$	(1,698,504	)	$	—		$	(284,133	)	$	—	$	(148	)	$	(284,281	)	$	(335	)	$	3,863,693

See Notes to our Consolidated Financial Statements

F-10

RELIANT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Background and Basis of Presentation

Background. "Reliant Energy" refers to Reliant Energy, Inc. and "we," "us" and "our" refer to Reliant Energy, Inc. and its consolidated subsidiaries. Our business consists primarily of two business segments, retail energy and wholesale energy. See note 17.

Reliant Energy, a Delaware corporation, was formed in August 2000 by CenterPoint Energy, Inc. (CenterPoint) (known as Reliant Energy, Incorporated at the time) in connection with the planned separation of its regulated and unregulated operations. CenterPoint transferred substantially all of its unregulated businesses to us. In May 2001, Reliant Energy became a publicly traded company and in September 2002, CenterPoint distributed its remaining ownership of our common stock to its shareholders.

Basis of Presentation. All significant intercompany transactions have been eliminated. We have reclassified certain amounts from prior periods to conform to the 2005 presentation. These reclassifications had no impact on reported earnings/losses and are described in notes 2(m), 5, 19 and 20.

(2) Summary of Significant Accounting Policies

(a) Use of Estimates and Market Risk and Uncertainties.

Management makes estimates and assumptions to prepare financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) that affect:

•: the reported amount of assets and liabilities,
•: the reported amounts of revenues and expenses and
•: our disclosure of contingent assets and liabilities at the date of the financial statements.

Our critical accounting estimates include: (a) goodwill, (b) property, plant and equipment, (c) derivative assets and liabilities, (d) retail energy segment estimated revenues and energy supply costs, (e) loss contingencies and (f) deferred tax assets, valuation allowances and tax liabilities. Actual results could differ from our estimates.

We are subject to various risks inherent in doing business. See notes 2(c), 2(d), 2(e), 2(h), 2(p), 3(b), 4, 5, 6, 9, 10, 11 and 12.

(b) Principles of Consolidation.

We include our accounts and those of our wholly-owned and majority-owned subsidiaries in our consolidated financial statements. We do not consolidate three power generating facilities (see note 11(a)), which are under operating leases, or a 50% equity investment in a cogeneration plant. Since September 28, 2004, we have consolidated our receivables facility arrangement (see note 6).

(c) Revenues.

Power Generation Revenues. We record gross revenues from the sale of electricity and other energy services under the accrual method. Electric power and other energy services are sold at market-based prices through existing power exchanges or through third party contracts. Energy sales and services that have been delivered but not billed by period-end are estimated.

Retail Energy Revenues. Gross revenues for energy sales and services to residential and small business customers and our electric sales to large commercial, industrial and governmental/institutional

F-11

customers under contracts executed after October 2002 are recognized upon delivery and include estimated energy and services delivered but not billed by the end of the period. Our electric sales to large commercial, industrial and governmental/institutional customers under contracts executed before October 2002 were accounted for under the mark-to-market method of accounting upon contract execution. The change in accounting for some of the contracted sales to large commercial, industrial and governmental/institutional customers during 2002 was due to Emerging Issues Task Force (EITF) No. 02-03.

We recorded a cumulative effect of a change in accounting principle of $42 million loss, net of tax of $22 million, or $0.14 per share, effective January 1, 2003, related to EITF No. 02-03. The cumulative effect reflects the fair value, as of January 1, 2003, of contracts executed prior to October 25, 2002 that had been marked to market under EITF No. 98-10 that did not meet the definition of a derivative.

As of December 31, 2005 and 2004, we recorded unbilled revenues of $400 million and $328 million, respectively, for retail energy sales. Accrued unbilled revenues are based on our estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes, estimated customer usage by class and applicable customer rates. Unbilled revenues are calculated by multiplying volume estimates by our estimated rates by customer class. Estimated amounts are adjusted when actual usage and rates are known and billed.

Changes in Estimates for Retail Energy Sales and Costs. The revenues and the related energy supply costs in our retail energy segment include our estimates of customer usage after consideration of initial usage information provided by the independent system operators and the distribution companies. We revise these estimates and record any changes in the period as information becomes available (collectively referred to as "market usage adjustments"). During 2005, 2004 and 2003, we recognized in gross margin (revenues less purchased power, fuel and cost of gas sold) $15 million of expense, $18 million of expense and $28 million of income, respectively, related to market usage adjustments.

(d) Derivatives and Hedging Activities.

We account for our derivatives instruments and hedging activities in accordance with SFAS No. 133, "Accounting for Derivatives Instruments and Hedging Activities," as amended (SFAS No. 133).

In the fourth quarter of 2005, we commenced an evaluation of our wholesale energy segment's hedging strategy (which includes both designated and non-designated hedging derivative instruments) and use of capital. In February 2006, we concluded that the benefits of hedging our generation do not justify the costs, including collateral postings. As a result, we decided to substantially reduce new hedges of our generation. We intend to continue entering into selective hedges, including originated transactions, based on (a) our assessment of market fundamentals to increase the return from our generation assets and (b) operational and market limitations requiring us to enter into fuel, capacity and emissions transactions to manage our generation assets. We believe that this new strategy will significantly reduce our wholesale energy segment's use of capital; however, our earnings will be subject to volatility based on market price changes. Existing positions will be closed as economically feasible or in accordance with their terms.

For our retail energy segment, we will continue to focus our supply procurement strategy on (a) matching our supply costs with our fixed price sales commitments and (b) procuring physical supply to manage operational issues and within market liquidity constraints. In conjunction with our revised wholesale energy segment's hedge strategy as discussed above, during the fourth quarter of 2005, we decided to procure third party supply for our PJM retail sales commitments. Historically, we used our PJM Interconnection, LLC (PJM) generation to supply these commitments. This new strategy may result in increased collateral cost to supply our retail energy operations in the PJM market, decreasing our ability to be competitive in this market or reducing our gross margins.

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We may also continue to enter into derivatives to manage our exposure to changes in interest rates.

For our hedging activities, we use both derivative and non-derivative contracts that provide for settlement in cash or by delivery of a commodity. The primary types of derivative instruments we use are forwards, futures, swaps and options. We elect one of three accounting methods (cash flow hedge, mark-to-market or accrual accounting) for derivatives based on facts and circumstances. The fair values of our derivative activities are determined by (a) prices actively quoted, (b) prices provided by other external sources or (c) prices based on models and other valuation methods.

If certain conditions are met, a derivative instrument may be designated as a cash flow hedge. A derivative is recognized at fair value in the balance sheet whether or not it is designated as a hedge, except for derivative contracts designated as "normal purchases and sales exceptions," which are not in our consolidated balance sheet or results of operations prior to settlement.

Derivatives designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive income (loss), net of tax, to the extent the contracts are effective as hedges, until the forecasted transactions affect earnings. At the time the forecasted transactions affect earnings, we reclassify the amounts in other comprehensive income into earnings. We record the ineffective portion of changes in fair value of cash flow hedges immediately into earnings. For all other derivatives, changes in fair value are recorded as unrealized gains or losses in our results of operations.

If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in our results of operations. If it becomes probable that a forecasted transaction will not occur, we immediately recognize the related deferred gains or losses in our results of operations. The associated hedging instrument is then marked to market through our results of operations for the remainder of the contract term unless a new hedging relationship is redesignated.

F-13

Prior to October 1, 2003, we generally recorded, on a gross basis in the period of delivery (a) sales in revenues and (b) purchases in purchased power, fuel and cost of gas sold. In July 2003, the EITF issued EITF No. 03-11, which states that realized gains and losses on derivatives contracts not "held for trading purposes" should be reported either on a net or gross basis based on the relevant facts and circumstances. EITF No. 03-11 has no impact on margins or net income. Subsequent to October 1, 2003, due to the adoption of EITF No. 03-11, hedging transactions that do not physically flow are included in the same caption as the items being hedged. A summary of our derivative activities and classification in our results of operations is:

Instrument	Purpose for Holding or Issuing Instrument⁽¹⁾	Transactions that Physically Flow	Transactions that Financially Settle⁽²⁾
Power futures, forward, swap and option contracts	Power sales to end-use retail customers Power sales from wholesale operations Supply management revenues	Revenues Revenues Revenues	N/A Revenues Purchased power, fuel and cost of gas sold
	Power purchases related to our retail operations	Purchased power, fuel and cost of gas sold	Purchased power, fuel and cost of gas sold
	Power purchases related to wholesale operations	Purchased power, fuel and cost of gas sold	Revenues
	Power purchases/sales related to our legacy trading positions	Revenues	Revenues
Natural gas and fuel futures, forward, swap and option contracts	Natural gas and fuel purchases/sales related to our retail operations	N/A	Purchased power, fuel and cost of gas sold
	Natural gas and fuel sales related to wholesale operations	Revenues	Purchased power, fuel and cost of gas sold
	Natural gas and fuel purchases related to wholesale operations	Purchased power, fuel and cost of gas sold	Purchased power, fuel and cost of gas sold
	Natural gas and fuel purchases/sales related to our legacy trading positions	Purchased power, fuel and cost of gas sold	Purchased power, fuel and cost of gas sold
Interest rate swaps and caps	Interest rate risk associated with floating-rate debt	N/A	Interest expense

(1): The purpose for holding or issuing is not impacted by the accounting method elected for each instrument.
(2): Includes classification for mark-to-market derivatives and amounts reclassified from accumulated other comprehensive income (loss) related to cash flow hedges.

In addition to market risk, we are exposed to credit and operational risk. We have a control framework to manage these risks, which include: (a) measuring and monitoring these risks, (b) review and approval of new transactions relative to these risks, (c) transaction validation and (d) portfolio valuation and reporting. We use mark-to-market valuation, value-at-risk and other metrics in monitoring and measuring risk. Our risk control framework includes a variety of separate but complementary processes, which involve commercial and senior management and our Board of Directors. See note 2(e) for further discussion of our credit policy.

Earnings Volatility from Derivative Instruments. We purchase most of the generation capacity necessary to supply our retail energy business in Texas from third parties. Our primary objective is to satisfy the forecasted retail load and maintain adequate capacity reserves to manage operational and market constraints. We routinely hedge most of our fixed purchase and sale commitments. Some types of transactions may cause us to experience volatility in our earnings due to the revenue receiving accrual treatment while a portion of the related supply is marked to market. During the third quarter

F-14

of 2004, for certain new power capacity commitments, we began electing mark-to-market accounting treatment to partially offset the potential impact of price volatility on our short positions in natural gas.

We procure natural gas, coal, oil, natural gas transportation and storage capacity and other energy-related commodities to support our electric generation assets. Some types of transactions may cause us to experience volatility in our earnings due to natural gas inventory related to transportation and storage generally receiving accrual treatment while the related derivative instruments are marked to market through earnings. Effective July 1, 2004, we began electing mark-to-market accounting treatment for new transactions and transactions in the West region that were previously designated as cash flows hedges.

Effective September 1, 2005, we began marking to market through earnings a portion of our cash flow hedge portfolio related to our PJM coal plants for October 2005 through December 2007 due to ineffectiveness. The ineffectiveness resulted from transmission constraints impacting our generating plants, hotter than average weather and higher natural gas prices.

Set-off of Derivative Assets and Liabilities. Where derivative instruments are subject to a master netting agreement and the accounting criteria to net are met, we present our derivative assets and liabilities on a net basis. Derivative assets/liabilities and accounts receivable/payable are presented and set-off separately in our consolidated balance sheets although in most cases contracts permit the set-off of derivative assets/liabilities and accounts receivable/payable with a given counterparty.

(e) Credit Risk.

We have a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. Credit risk is monitored daily and the financial condition of our counterparties is reviewed periodically. We try to mitigate credit risk by entering into contracts that permit netting and allow us to terminate upon the occurrence of certain events of default. We measure credit risk as the replacement cost for our derivative positions plus amounts owed for settled transactions.

As of December 31, 2005, two non-investment grade counterparties and one investment grade counterparty represented 59% ($918 million) and 12% ($183 million), respectively, of our credit exposure, net of collateral. As of December 31, 2004, three non-investment grade counterparties represented 48% ($329 million) of our credit exposure, net of collateral. Since December 31, 2004, our credit exposure increased primarily due to changes in commodity prices. There were no other counterparties representing greater than 10% of our credit exposure, net of collateral.

(f) Selling, General and Administrative Expenses.

Selling, general and administrative expenses include (a) selling and marketing, (b) bad debt expense and (c) other general and administrative expenses. Other general and administrative expenses include, among other items, (a) financial services, (b) legal costs, (c) regulatory costs and (d) certain benefit costs.

(g) Severance Costs.

During 2005, 2004 and 2003, we incurred $9 million, $31 million and $31 million, respectively, in severance costs (included in both operation and maintenance and selling, general and administrative expenses), which were substantially paid in each applicable period.

F-15

(h) Property, Plant and Equipment and Depreciation Expense.

We compute depreciation using the straight-line method based on estimated useful lives. Depreciation expense was $351 million, $372 million and $303 million during 2005, 2004 and 2003, respectively.

			December 31,
		Estimated Useful Lives (Years)	December 31,
		Estimated Useful Lives (Years)	2005			2004
			(in millions)
Electric generation facilities		10-35	$	6,313		$	6,502
Building and building improvements		5-15		31			34
Land improvements		20-35		194			197
Other		3-10		445			465
Land				96			98
Assets under construction				34			48

	Total			7,113			7,344
Accumulated depreciation				(1,179	)		(906	)

	Property, plant and equipment, net		$	5,934		$	6,438

We periodically evaluate property, plant and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. We recorded no material property, plant and equipment impairments during 2005, 2004 and 2003.

In the future, we could recognize impairments if our wholesale energy market outlook changes negatively. In addition, our ongoing evaluation of our wholesale energy business could result in decisions to mothball, retire or dispose of additional generation assets, any of which could result in impairment charges.

(i) Intangible Assets and Amortization Expense.

Goodwill. We perform our goodwill impairment test annually and when events or changes in circumstances indicate that the carrying value may not be recoverable. We previously selected November 1 as our annual goodwill impairment testing date since we had historically completed our annual strategic planning process by that date. We have since modified our strategic planning process, which provides key information used in the analysis of our goodwill impairment test, and such information is no longer completed by November 1. In order to align our annual goodwill impairment test with our annual strategic planning process, to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in 2005, we changed the date on which we perform our annual goodwill impairment test to April 1. The change is not intended to delay, accelerate or avoid an impairment charge. We believe that this accounting change is to an alternative accounting principle that is preferable under the circumstances.

Other Intangibles. We recognize specifically identifiable intangible assets, including emission allowances, contractual rights, power generation site permits and water rights, when specific rights and contracts are acquired. We have no intangible assets with indefinite lives recorded as of December 31, 2005 and 2004.

(j) Stock-based Compensation.

We apply the intrinsic value method of accounting for employee stock-based compensation and expense it ratably over the vesting period. On January 1, 2006, we began to recognize compensation cost for the unvested portion of pre-January 2006 awards and awards granted from that date based on

F-16

the grant-date fair value of those awards. We expect the adoption of the fair value based method of accounting will not have a material impact on our financial position or results of operations. Under the intrinsic value method, we adjust compensation cost for performance-based stock awards and options based on changes in our stock price; however, under the fair value based method, we recognize compensation cost based on grant date fair value recognized over the service period. Under the intrinsic value method, we do not recognize compensation cost for time-based stock options or the employee stock purchase plan; however, under the fair value based method, we recognize compensation cost. The fair value based method of accounting does not change our compensation cost for time-based restricted stock awards or performance-based cash awards.

Using the Black-Scholes model for determining fair values, our pro forma results are:

		2005			2004			2003
		(in millions, except per share amounts)
Net loss, as reported		$	(331	)	$	(29	)	$	(1,342	)
Add: Stock-based compensation expense included in reported net income/loss, net of tax			5			21			7
Deduct: Stock-based compensation expense determined under fair value based method for all awards, net of tax			(17	)		(26	)		(42	)

Pro forma net loss		$	(343	)	$	(34	)	$	(1,377	)

Loss per share:
	Basic and diluted, as reported	$	(1.09	)	$	(0.10	)	$	(4.57	)

	Basic and diluted, pro forma	$	(1.13	)	$	(0.12	)	$	(4.69	)

We use the Black-Scholes option-pricing model with the following weighted average assumptions and resulting fair values:

	Options									Employee Stock Purchase Plan Rights
	2005			2004			2003			2005			2004			2003
Expected life in years		5			5			5			0.5			0.5			0.5
Estimated volatility⁽¹⁾		45.75	%		72.85	%		113.64	%		32.97	%		41.18	%		110.73	%
Risk-free interest rate		4.18	%		3.01	%		2.75	%		2.94	%		1.21	%		1.18	%
Dividend yield		0	%		0	%		0	%		0	%		0	%		0	%
Weighted-average fair value	$	5.72		$	5.00		$	3.10		$	3.25		$	2.29		$	1.80

(1): For 2005 and 2004 options, we estimated volatility based on an equal weighting of historical and implied volatility of our common stock. For employee stock purchase plan rights and 2003 options, we estimated volatility based on the historical volatility of our common stock.

(k) Capitalization of Interest Expense.

During 2005, 2004 and 2003, we capitalized $0, $46 million and $84 million of interest expense, respectively.

(l) Cash and Cash Equivalents.

We record all highly liquid short-term investments with maturities of three months or less as cash equivalents.

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(m) Restricted Cash.

Restricted cash includes cash at certain subsidiaries, the distribution or transfer of which is restricted by financing and other agreements. In our consolidated statements of cash flows for 2004 and 2003, we reclassified $247 million and $(62) million, respectively, from operating cash flows to investing cash flows relating to changes in restricted cash for continuing and discontinued operations.

(n) Allowance for Doubtful Accounts.

We accrue an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings, historical collections, accounts receivable agings and other factors. We write-off accounts receivable balances against the allowance for doubtful accounts when we determine a receivable is uncollectible. Write-offs related to refunds for energy sales in California were recorded in revenues (see note 13(a)).

(o) Inventory.

We value inventories used in the production of electricity at the lower of average cost or market.

		December 31,
		2005		2004
		(in millions)
Materials and supplies, including spare parts		$	149	$	137
Coal			63		54
Natural gas			32		25
Heating oil			55		30

	Total inventory	$	299	$	246

(p) Environmental Costs.

We expense environmental expenditures related to existing conditions that do not have future economic benefit. We capitalize environmental expenditures for which there is a future economic benefit. We record liabilities for expected future costs, on an undiscounted basis, related to environmental assessments and/or remediation when they are probable and can be reasonably estimated. See note 12(b).

(q) Asset Retirement Obligations.

Our asset retirement obligations relate to future costs primarily associated with dismantling power plants and ash disposal site closures. Our asset retirement obligation was $21 million and $15 million as of December 31, 2005 and 2004, respectively.

During 2005, we adopted an accounting interpretation relating to asset retirement obligations. This interpretation clarifies that an asset retirement obligation is unconditional even though uncertainty exists about the timing and/or method of settlement and requires that a liability be recognized if it can be reasonably estimated. Based on this, we (a) recorded a cumulative effect of an accounting change, net of tax, of $1 million ($0.00 per share), (b) increased other long-term liabilities by $2 million and (c) increased property, plant and equipment by $1 million.

The adoption of SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003, resulted in a gain of $19 million, $10 million net of tax, or $0.06 per share, as a cumulative effect on an accounting change in our consolidated results of operations for 2003. The gain includes $16 million, $7 million net of tax from our European energy operations, which are reported as discontinued operations.

F-18

(r) Repair and Maintenance Costs for Power Generation Assets.

We recognize repair and maintenance costs as incurred. Prior to January 2004, we recognized repair and maintenance costs associated with planned major maintenance under the "accrue-in-advance" method for assets acquired prior to December 31, 1999. Effective January 2004, we began expensing these costs as incurred for all of our assets. As a result of this change, we recognized a cumulative effect of an accounting change resulting in an increase in net income of $7 million, net of tax of $3 million, or $0.02 per share.

(s) Deferred Financing Costs.

We incur costs, which are deferred and amortized over the life of the debt, in connection with obtaining financings. See note 6. Changes in deferred financing costs, classified in other long-term assets are:

	2005			2004			2003
	(in millions)
Beginning of year	$	126		$	143		$	27
Capitalized		1			61			206
Amortized		(15	)		(28	)		(35	)
Accelerated amortization/write-offs		—			(50	)		(55	)

End of year	$	112		$	126		$	143

(3) Related Party Transactions

(a) Equity Contributions/Distributions.

We (a) received non-cash contributions of $7 million during 2005 from and (b) made distributions of $1 million during 2004 to CenterPoint in settlement of certain tax matters. See note 10. We received contributions of $45 million during 2003 from CenterPoint primarily related to the non-cash conversion to equity of certain accounts payable.

(b) Indemnities and Releases.

As part of our separation from CenterPoint, we agreed to indemnify our former parent company for liabilities associated with the business we acquired and relating to our initial public offering. See notes 10 and 11(b).

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(4) Intangible Assets

(a) Goodwill.

The following table shows goodwill by segment and the changes:

		Retail Energy		Wholesale Energy			Total
		(in millions)
As of January 1, 2004		$	53	$	430		$	483
	Transfer to discontinued operations⁽¹⁾		—		(42	)		(42	)

As of December 31, 2004			53		388			441
	Transfer to discontinued operations⁽²⁾		—		(42	)		(42	)
	Other⁽³⁾		—		(12	)		(12	)

As of December 31, 2005		$	53	$	334		$	387

(1): Goodwill related to our Orion Power Holdings, Inc. (Orion Power Holdings) and its subsidiaries (Orion Power) hydropower plants. See note 20.
(2): Goodwill related to our Ceredo plant and New York plants. See note 20.
(3): Goodwill related to (a) revisions to the Orion Power purchase price allocation for tax matters of $9 million and (b) various asset sales totaling $3 million. See note 19.

As of December 31, 2005 and 2004, we had $72 million and $80 million, respectively, of goodwill that is deductible for United States income tax purposes for future periods.

July 2003 Goodwill Impairment Test Related to our Wholesale Energy Reporting Unit. The July 2003 sale of our Desert Basin plant required us to allocate a portion of the goodwill in the wholesale energy reporting unit to the Desert Basin plant operations on a relative fair value basis in order to compute the loss on disposal. We also tested the recoverability of the remaining goodwill in our wholesale energy reporting unit as of July 2003.

As a result of this test, we recognized an impairment of $985 million (pre-tax and after-tax) in the third quarter of 2003. This impairment was due to a decrease in the estimated fair value primarily attributable to: (a) reduced projected commercialization opportunities related to our power generation assets; (b) the elimination of proprietary trading; (c) lower projected regulatory capacity values due to the lack of development of appropriate market structures and a lower outlook for revenues from existing regulatory capacity markets; (d) reduced long-term margins from our existing portfolio as a result of lowering our estimates of the margins required to induce new capacity to enter the markets; (e) expectations for the retirement and/or mothballing of some of our facilities; (f) lower market and comparable public company values data; and (g) the level of working capital; partially offset by reductions in our projected commercial, operational and support groups costs and lower projected operations and maintenance expense.

Additional Goodwill Impairment Tests. In addition to the July 2003 goodwill impairment test, we performed impairment tests at the following dates: November 2003, May 2004, November 2004, January 2005, March 2005, April 2005, August 2005 and September 2005 due to either asset sales or our annual impairment tests. No impairments were indicated in these tests.

Estimation of our Wholesale Energy Reporting Unit's Fair Value. We estimate the fair value of our wholesale energy reporting unit based on a number of subjective factors, including: (a) appropriate weighting of valuation approaches (income approach, market approach and comparable public company approach), (b) projections about future power generation margins, (c) estimates of our future cost structure, (d) discount rates for our estimated cash flows, (e) selection of peer group companies for the

F-20

public company approach, (f) required level of working capital, (g) assumed terminal value and (h) time horizon of cash flow forecasts.

Management has determined the fair value of our wholesale energy reporting unit with the assistance of an independent appraiser. In determining the fair value of our wholesale energy reporting unit, we made the following key assumptions: (a) the markets in which we operate will continue to be deregulated; (b) there will be a recovery in electricity margins over time such that companies building new generation facilities can earn a reasonable rate of return on their investment and (c) the economics of future construction of new generation facilities will likely be driven by integrated utilities. As part of our process, we modeled all of our power generation facilities and those of others in the regions in which we operate. Our assumptions for each of our goodwill impairment tests during 2003, 2004 and 2005 were:

Number of years used in internal cash flow analysis	15
EBITDA⁽¹⁾ multiple for terminal values (for September 2005 test)	8.0
EBITDA⁽¹⁾ multiple for terminal values (through August 2005 test)	7.5
Risk-adjusted discount rate for our estimated cash flows	9.0	%
Approximate average anticipated growth rate for demand in power	2.0	%
Long-term after-tax return on investment for new investment	7.5	%

(1): Defined as earnings (loss) before interest expense, interest income, income taxes, depreciation and amortization expenses.

(b) Other Intangibles.

				December 31,
		Remaining Weighted Average Amortization Period (Years)		2005					2004
		Remaining Weighted Average Amortization Period (Years)		Carrying Amount		Accumulated Amortization			Carrying Amount		Accumulated Amortization
				(in millions)
SO₂ emission allowances⁽¹⁾⁽²⁾		—	⁽¹⁾	$	371	$	(179	)	$	298	$	(118	)
NO_x emission allowances⁽¹⁾⁽³⁾		—	⁽¹⁾		344		(147	)		351		(117	)
Contractual rights⁽⁴⁾		1			4		(3	)		4		(3	)
Power generation site permits⁽⁵⁾		30			73		(7	)		73		(5	)
Water rights⁽⁵⁾		30			67		(12	)		67		(10	)
Other⁽⁵⁾		—			3		(3	)		3		(2	)

	Total			$	862	$	(351	)	$	796	$	(255	)

(1): SO₂ is sulfur dioxide and NO_x is nitrogen oxide. Amortized to amortization expense on a units-of-production basis. As of December 31, 2005, we have recorded (a) SO₂ emission allowances through the 2039 vintage year and (b) NO_x emission allowances through the 2039 vintage year.
(2): During 2005, 2004 and 2003, we purchased $130 million, $61 million and $43 million of SO₂ emission allowances, respectively. See note 19 for sales.
(3): During 2005, 2004 and 2003, we purchased $16 million, $64 million and $33 million of NO_x emission allowances, respectively. See note 19 for sales.
(4): Amortized to revenues and fuel expense, as applicable, based on the estimated realization of the fair value established on the acquisition date over the contractual lives.
(5): Amortized to amortization expense on a straight-line basis over the estimated lives.

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Amortization expense consists of:

		2005			2004			2003
		(in millions)
Other intangibles, excluding contractual rights and obligations⁽¹⁾⁽²⁾		$	95		$	81		$	55

Contractual rights		$	(1	)	$	(1	)	$	(1	)
Contractual obligations⁽¹⁾			9			30			28

	Net	$	8		$	29		$	27

(1): Contractual obligations are in other long-term liabilities.
(2): Includes amortization of emission allowances of $90 million, $77 million and $50 million during 2005, 2004 and 2003, respectively.

Estimated amortization expense, based on our intangibles as of December 31, 2005, excluding contractual rights and obligations, for the next five years is (in millions):

2006	$	40
2007		23
2008		13
2009		15
2010		16

(5) Derivatives and Hedging Activities

We use derivative instruments to manage operational or market constraints, to increase return on our generation assets and to execute our retail energy segment's supply procurement strategy. The instruments used are fixed-price derivative contracts to hedge the variability in future cash flows from forecasted sales of power and purchases of fuel and power. Our objective in entering into these fixed-price derivatives is to fix the price for a portion of these transactions. See note 2(d).

Our derivative portfolio, excluding cash flow hedges, is $308 million (net liability) and $114 million (net liability) as of December 31, 2005 and 2004, respectively. Our cash flow hedges are valued at $471 million (net liability) and $21 million (net liability) as of December 31, 2005 and 2004, respectively.

As of December 31, 2005 and 2004, the maximum length of time we are hedging our exposure to the variability in future cash flows that may result from changes in commodity prices is seven years and eight years, respectively. As of December 31, 2005, $115 million of accumulated other comprehensive loss is expected to be reclassified into our results of operations during the next 12 months. However, the actual amount reclassified into earnings could vary from the amounts recorded as of December 31, 2005, due to future changes in market prices.

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Although we discontinued our proprietary trading business in March 2003, we have legacy positions, which will be closed as economically feasible or in accordance with their terms. The margins associated with these transactions are (income (loss)):

		2005			2004			2003
		(in millions)
Revenues		$	(15	)	$	—		$	(14	)
Purchased power, fuel and cost of gas sold			(30	)		4	⁽¹⁾		(35	)⁽¹⁾

	Gross margin	$	(45	)	$	4		$	(49	)

(1): Beginning in 2005, amounts were reclassified from revenues to purchased power, fuel and cost of gas sold based on commodity type.

The income (loss) of our energy and interest rate derivative instruments is:

			2005			2004			2003
			(in millions)
Energy derivatives:
	Hedge ineffectiveness		$	71		$	(17	)	$	(18	)
	Other net unrealized gains (losses)			(263	)		(207	)		(30	)
Interest rate derivatives:
	Hedge ineffectiveness			—			—			(2	)
	Other net unrealized gains (losses)			(16	)		(24	)		(9	)

		Total⁽¹⁾⁽²⁾	$	(208	)	$	(248	)	$	(59	)

(1): No component of the derivatives' gain or loss was excluded from the assessment of effectiveness.
(2): Includes $0, $16 million gain and $0 for 2005, 2004 and 2003, respectively, recognized in our results of continuing operations as a result of the discontinuance of cash flow hedges for forecasted transactions that we determined were probable of not occurring.

For a discussion of our interest rate derivatives, see note 6(e).

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(6) Debt

(a) Overview.

As of December 31, 2005, we were in compliance with all of our debt covenants. Our outstanding debt is:

					December 31,
					2005						2004
					Weighted Average Stated Interest Rate⁽¹⁾		Long-term		Current		Weighted Average Stated Interest Rate⁽¹⁾		Long-term		Current
					(in millions, except interest rates)
*Facilities, Bonds and Notes:*
	Reliant Energy:
		Senior secured revolver due 2009			8.40	%	$	383	$	—	7.13	%	$	199	$	—
		Senior secured term loans (B1) due 2010⁽²⁾			6.09			240		313	4.80			652		10
		Senior secured term loans (B2) due 2010			6.91			296		3	—			—		—
		Senior secured notes due 2010			9.25			550		—	9.25			550		—
		Senior secured notes due 2013			9.50			550		—	9.50			550		—
		Senior secured notes due 2014			6.75			750		—	6.75			750		—
		Convertible senior subordinated notes due 2010 (unsecured)			5.00			275		—	5.00			275		—
	Subsidiary Obligations:
		Orion Power Holdings senior notes due 2010 (unsecured)			12.00			400		—	12.00			400		—
		PEDFA fixed-rate bonds for new Seward plant due 2036			6.75			500		—	6.75			500		—
		REMA term loans (unsecured)			—			—		—	4.94			14		14
		Reliant Energy Channelview, L.P.:
		Term loans and revolving working capital facility:
			Floating rate debt due 2006 to 2024		6.04			259		14	3.83			—		284
			Fixed rate debt due 2014 to 2024		9.55			75		—	9.55			—		75
		RE Retail Receivables, LLC facility due 2006			4.71			—		450	3.90			—		227

			Total facilities, bonds and notes					4,278		780				3,890		610

*Other:*
		Adjustment to fair value of debt⁽³⁾						39		9				49		8
		Adjustment to fair value of debt due to warrants and other						—		—				—		1

			Total other debt					39		9				49		9

				Total debt			$	4,317	$	789			$	3,939	$	619

(1): The weighted average stated interest rates are for borrowings outstanding as of December 31, 2005 or 2004.
(2): As of December 31, 2005 and 2004, we classified $638 million as discontinued operations. See note 20.
(3): Debt and interest rate swaps acquired in the Orion Power acquisition were adjusted to fair market value as of the acquisition date. Included in interest expense is amortization of $9 million, $9 million and $8 million for valuation adjustments for debt for 2005, 2004 and 2003, respectively.

Amounts borrowed and available for borrowing under our revolving credit agreement as of December 31, 2005 are:

	Total Committed Credit		Drawn Amount		Letters of Credit		Unused Amount
			(in millions)
Reliant Energy senior secured revolver due 2009	$	1,700	$	383	$	937	$	380
Reliant Energy Channelview, LP revolving working capital facility due 2007		14		—		—		14

	$	1,714	$	383	$	937	$	394

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Debt maturities as of December 31, 2005 are (in millions):

2006	$	480
2007		31
2008		33
2009		419
2010		2,035	⁽¹⁾
2011 and thereafter		2,060

	$	5,058

(1): Includes $300 million classified as current that we plan to pay down with net proceeds from sale of New York plants. See note 20.

(b) Outstanding Debt.

Senior Secured Term Loans and Senior Secured Revolver. Our term loan B1 bears interest at London Inter Bank Offering Rate (LIBOR) plus 2.375% or a base rate plus 1.375%. Our $1.7 billion revolving credit facility bears interest at LIBOR plus 2.875% or a base rate plus 1.875% and provides for the issuance of up to $1.4 billion of letters of credit. We must prepay this revolving credit facility and term loan B1 (the December 2004 credit facilities) with proceeds from certain asset sales and issuances of equity securities. Additionally, we must make quarterly principal payments of 0.25% of the original principal amount of the term loans.

Subject to certain exceptions, the December 2004 credit facilities restrict our ability to, among other actions, (a) encumber our assets, (b) enter into business combinations or divest our assets, (c) incur additional debt or engage in sale and leaseback transactions, (d) pay dividends or prepay other debt, (e) make investments or acquisitions, (f) enter into transactions with affiliates, (g) make capital expenditures, (h) materially change our business, (i) amend our debt agreements, (j) repurchase our capital stock and (k) engage in certain types of trading activities. In addition, we are required to achieve specified levels for the ratios of (a) adjusted net debt to adjusted net earnings (loss) before interest expense, interest income, income taxes, depreciation, amortization and certain lease expenses (EBITDAR) (consolidated leverage ratio) and (b) adjusted consolidated EBITDAR to adjusted interest expense (consolidated interest coverage ratio)

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The specified level for each ratio is:

Four Fiscal Quarters Ending		Maximum Consolidated Leverage Ratio
December 31, 2005 through September 30, 2006		6.0:1.0
December 31, 2006 through September 30, 2007		5.5:1.0
December 31, 2007 and each fiscal quarter thereafter		5.0:1.0

Four Fiscal Quarters Ending	Minimum Consolidated Interest Coverage Ratio
December 31, 2005	1.8:1.0
March 31, 2006 through December 31, 2006	1.5:1.0	⁽¹⁾
March 31, 2007 through September 30, 2007	1.8:1.0
December 31, 2007 and each fiscal quarter thereafter	2.0:1.0

(1): The Minimum Consolidated Interest Coverage Ratio was amended in December 2005. Additionally, the amendment requires us to use the net unrestricted sales proceeds from our Ceredo and New York plants to prepay, subject to our indentures, the December 2004 term loan.

Certain of our subsidiaries jointly and severally guarantee the December 2004 credit facilities, which are also secured by security interests in assets of our guarantor subsidiaries and the capital stock of some operating subsidiaries. See note 15.

October 2005 Senior Secured Term Loans. In October 2005, we borrowed $299 million in term loans (B2) (the October 2005 credit facility), which bear the same interest rate spreads as the term loan B1. The material terms of the October 2005 credit facility are substantially identical to those of the December 2004 credit facilities discussed above. The collateral that secures the December 2004 credit facilities also secures the October 2005 credit facility except for the capital stock of some of our subsidiaries and certain cash collateral.

If we (a) achieve certain financial ratios for two consecutive fiscal quarters, (b) repay the B1 and B2 term loans in full and (c) are not in default under the December 2004 credit facilities, the revolving credit facility will become unsecured and several covenants will be suspended. We do not expect to satisfy these conditions in 2006.

Senior Secured Notes. The collateral that secures the October 2005 credit facility also secures the senior secured notes. The senior secured notes have covenants similar to those in our credit facilities. If the December 2004 revolving credit facilities become unsecured, the senior secured notes will become unsecured. In addition, certain covenants under the senior secured notes will be suspended in the event we achieve certain investment grade credit ratings.

Convertible Senior Subordinated Notes. These notes are convertible into shares of our common stock at a conversion price of $9.54 per share. We may redeem the notes, in whole or in part, at any time on or after August 20, 2008, if the last reported sales price of our common stock is at least 125% of the conversion price then in effect for a specified period of time.

Orion Power Holdings Senior Notes. These notes were recorded at a fair value of $479 million upon the acquisition of Orion Power. The $79 million premium is being amortized to interest expense over the life of the notes. The senior notes are senior unsecured obligations of Orion Power Holdings, are not guaranteed by any of Orion Power Holdings' subsidiaries and are non-recourse to Reliant Energy. The senior notes have covenants that restrict (subject to certain exceptions) the ability of Orion Power Holdings and certain of its subsidiaries to, among other actions, (a) pay dividends, (b) incur

F-26

indebtedness or issue preferred stock, (c) make investments, (d) divest assets, (e) encumber its assets, (f) enter into transactions with affiliates, (g) engage in unrelated businesses and (h) engage in sale and leaseback transactions. As of December 31, 2005, conditions under these covenants have been met that allow the payment of dividends. However, we expect that after the closing of the sale of the New York plants, which occurred in February 2006, Orion Power Holdings' dividends to Reliant Energy may be partially restricted.

PEDFA Bonds for New Seward Plant. Reliant Energy Seward, LLC (Seward) partially financed the construction of its power plant with proceeds from the issuance of tax-exempt revenue bonds by Pennsylvania Economic Development Financing Authority (PEDFA), which are guaranteed by Reliant Energy.

Reliant Energy Channelview, L.P. Reliant Energy Channelview, L.P. (Channelview) entered into a credit agreement that financed the construction of a power plant. The credit agreement consists of (a) $369 million in term loans and (b) $14 million revolving working capital facility that matures in 2007.

With the exception of a fixed-rate tranche (9.55% for $75 million), the loans bear a floating interest rate based either on LIBOR or base rates plus a margin that increases over time. The facility is secured by substantially all of the assets of Channelview and is non-recourse to Reliant Energy. The facility prohibits Channelview from taking certain actions (subject to exceptions), including paying dividends or making restricted payments unless, among other things, it maintains specified debt service coverage ratios and debt service account balances. As of December 31, 2005, the conditions under these covenants were not met. Channelview is not expected to satisfy these conditions in 2006. We have obtained waivers from the lenders regarding insurance requirements specified in the credit agreement and plan to do so in the future. The current waiver expires in April 2006. Prior to the expiration of this waiver, Channelview intends to obtain a successor waiver or purchase an insurance policy that will conform with the credit agreement.

RE Retail Receivables, LLC Facility. We have a receivables facility arrangement to sell an undivided interest in accounts receivable from our retail business to financial institutions on an ongoing basis. We amended this arrangement in September 2005 to extend its maturity until September 2006, reduce the fees we are charged, increase the proportion of receivables against which we can borrow and increase the maximum capacity available from $350 million to $450 million.

The assets of the special purpose subsidiary that purchases the receivables and then resells receivables under the facility are available first and foremost to satisfy the claims of its creditors. The special purpose subsidiary is a separate entity.

Prior to September 28, 2004, these transactions were accounted for as sales of receivables; as a result, the related receivables and debt were excluded from our consolidated balance sheet. Effective with the September 28, 2004 amendment to this facility, the qualified special purpose entity (QSPE) ceased to be a QSPE and we began consolidating its results of operations and the proceeds from receivables sold to the financial institutions were treated as a financing. As a result, accounts receivable and short-term borrowings of $350 million were included in the consolidated balance sheet as of the amendment date. The borrowings under the facility bear interest at floating rates that include fees based on the facility's level of commitment and utilization. We service the receivables and received a fee of 0.4%, 0.4% and 0.5% of cash collected during 2005, 2004 and 2003, respectively, which approximates our actual service costs. Reliant Energy also guarantees the performance obligations of the originators of the receivables and the servicing of the receivables. The guarantee contains, among other covenants, financial covenants identical to those contained in our December 2004 and October 2005 credit facilities.

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(c) Refinanced or Repaid Historical Debt.

2004 Financing Activity. In December 2004, we completed a $4.25 billion refinancing, the components of which included:

New debt:

•: $1.7 billion revolving credit facility due 2009,
•: $1.3 billion term loan due 2010,
•: $750 million of senior secured notes due 2014 and
•: $100 million of fixed-rate tax-exempt PEDFA bonds (in addition to $400 million of floating-rate tax-exempt revenue bonds which were converted to fixed-rate bonds).

Retired debt:

•: $2.1 billion revolving credit facility due 2007,
•: $1.7 billion term loan due 2007 and
•: $255 million of Orion Power MidWest, L.P. (Orion MidWest) debt and associated interest rate swap agreements due 2005.

REMA Term Loans. Reliant Energy Mid-Atlantic Power Holdings, LLC (REMA LLC) and its subsidiaries (REMA) have sale-leaseback agreements with respect to three of their generating facilities. In 2003, proceeds from the REMA term loans were used to partially fulfill REMA's requirement to provide credit support for its obligations under these leases. During 2005, the term loans were paid in full and replacement credit support was provided in the form of letters of credit issued under the December 2004 credit facilities. The term loans bore interest at LIBOR plus 3%. The term loans were non-recourse to Reliant Energy. See note 11(a).

(d) Warrants.

In March 2003, we issued 7.8 million common stock warrants with an exercise price of $5.09 per share in connection with a credit facility. As of December 31, 2005 and 2004, 7,448,332 and 7,827,589 warrants, respectively, were outstanding and expire in August 2008. We recorded the fair value of the warrants ($15 million) as a discount to debt and an increase to additional paid-in capital. We are amortizing the debt discount to interest expense over the life of the related debt. During 2005, 2004 and 2003, we amortized $0, $7 million and $7 million, respectively, to interest expense.

(e) Interest Rate Derivative Instruments.

Historically, we have used interest rate swaps and caps to hedge the floating interest rate risk associated with our floating rate long-term debt. Some swaps used to hedge our exposure are designated as cash flow hedges, with the effective portion of gains and losses, net of tax, recorded in accumulated other comprehensive loss. The interest rate derivatives not designated as cash flow hedges are marked to market. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense during the periods in which the interest payments being hedged occur. See note 5 for information regarding our derivatives.

Expirations. As of December 31, 2005, the LIBOR interest rate caps associated with Reliant Energy's credit facilities and the interest rate swaps related to the Channelview credit facilities expired. Prior to March 31, 2003, the interest rate caps qualified as cash flow hedges and changes in fair market value were recorded to other comprehensive income. During 2005, 2004 and 2003, we recorded $9 million, $21 million and $19 million, respectively, in interest expense related to these instruments.

F-28

Terminations. In 2002, we liquidated forward-starting interest rate swaps having a notional value of $1.0 billion. As of December 31, 2005 and 2004, we have $17 million and $27 million, respectively, of deferred losses in accumulated other comprehensive loss related to these interest rate swaps. We are amortizing these losses into interest expense through 2012 for the forward-starting interest rate swaps. As of December 31, 2005, $11 million of accumulated other comprehensive loss is expected to be reclassified into interest expense during the next 12 months.

(7) Stockholders' Equity

The following describes our capital stock activity:

		Common Stock	Treasury Stock
		(shares in thousands)
Balance as of January 1, 2003		290,605	9,199
	Issued to benefit plans	3,987	(3,987	)

Balance as of December 31, 2003		294,592	5,212
	Issued to benefit plans	5,084	(5,084	)
	Issued for warrants	8	—

Balance as of December 31, 2004		299,684	128
	Issued to benefit plans	4,877	(128	)
	Issued for warrants	339	—

Balance as of December 31, 2005		304,900	—

(8) Earnings Per Share

For 2005, 2004 and 2003, basic and diluted weighted average shares outstanding are 302,409,000; 297,527,000 and 293,655,000 respectively.

We excluded the following items from diluted earnings (loss) per common share due to the anti-dilutive effect:

	2005			2004			2003
	(shares in thousands, dollars in millions)
Shares excluded from the calculation of diluted earnings (loss) per share		36,538	⁽¹⁾		35,869	⁽¹⁾		17,239	⁽¹⁾
Shares excluded from the calculation of diluted earnings (loss) per share because the exercise price exceeded the average market price		4,471	⁽²⁾		8,934	⁽²⁾		23,346	⁽³⁾
Interest expense that would be added to income if 5.00% convertible senior subordinated notes were dilutive	$	9		$	9		$	5

(1): Potential shares excluded consist of convertible senior subordinated notes, warrants, stock options, restricted stock, performance-based shares and shares related to the employee stock purchase plan.
(2): Includes stock options.
(3): Includes stock options and warrants.

(9) Stock-Based Incentive Plans and Benefit Plans

(a) Stock-Based Incentive Plans.

Overview. The Compensation Committee of the Board of Directors administers our stock-based incentive plans. The Reliant Energy, Inc. 2002 Long-Term Incentive Plan (the 2002 LTIP) and the

F-29

Reliant Energy, Inc. 2002 Stock Plan (the 2002 Stock Plan) permit us to grant various stock-based incentive awards to officers, key employees and directors. Awards include stock options, stock appreciation rights, restricted stock, performance awards, cash awards and stock awards.

Prior to the adoption of the plans, participants received awards under the Long-Term Incentive Plan of Reliant Energy, Inc. (the 2001 LTIP) or the Reliant Energy, Inc. Transition Stock Plan (collectively the previous plans). Awards under the previous plans are no longer permitted. The number of shares initially authorized to be issued under the 2002 LTIP and 2002 Stock Plan was 17.5 million and 6 million, respectively. Shares subject to awards previously granted under the 2001 LTIP that are canceled or forfeited become available for grant under the 2002 LTIP. During 2003, the Board of Directors authorized an increase in shares available for issuance under the 2002 Stock Plan. As such, 34.8 million shares are authorized for issuance under our stock-based incentive plans as of December 31, 2005.

We apply the intrinsic value method of accounting for employee stock-based incentive plans. Awards under our stock-based incentive plans resulted in expense of $8 million, $32 million and $11 million during 2005, 2004 and 2003, respectively. See note 2(j) for pro forma information.

Time-Based Stock Options. We grant time-based stock options to officers, key employees and directors at an exercise price equal to or greater than the fair market value of our stock on the grant date without cost to participants. Generally, options vest 33.33% per year and have a term of ten years.

Summarized time-based option activity is:

	2005				2004				2003
	Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price
Beginning of year	16,246,649		$	14.31	21,882,824		$	13.98	19,168,736		$	16.99
Granted	30,000			12.47	30,000			9.84	4,726,797			3.83
Exercised	(3,423,093	)		8.46	(2,500,090	)		6.94	(333	)		4.95
Canceled or expired	(1,206,889	)		22.22	(3,166,085	)		17.87	(2,012,376	)		18.44

End of year	11,646,667			15.21	16,246,649			14.31	21,882,824			13.98

Exercisable at end of year	10,917,935			15.93	13,784,910			15.79	14,722,136			15.47

For time-based options outstanding as of December 31, 2005:

	Outstanding				Exercisable
Exercise Price Range	Options	Weighted Average Exercise Price		Remaining Contractual Life (Years)	Options	Weighted Average Exercise Price
$3.51 - $10.00	4,965,347	$	5.86	5.0	4,266,615	$	6.15
$10.01 - $20.00	2,802,012		11.35	4.4	2,772,012		11.34
$20.01 - $34.03	3,879,308		29.97	3.1	3,879,308		29.97

Total	11,646,667		15.21	4.2	10,917,935		15.93

Time-Based Restricted Stock Awards. We grant time-based restricted stock awards to officers, key employees and directors without cost to participants. In general, these awards vest, subject to the participant's continued employment, three years from the grant date.

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Summarized restricted stock award activity is:

	2005			2004			2003
Beginning of year		2,415,451			3,002,888			755,267
Granted		309,994			948,962			3,156,103
Released		(727,640	)		(1,016,354	)		(440,578	)
Canceled or forfeited		(142,222	)		(520,045	)		(467,904	)

End of year		1,855,583			2,415,451			3,002,888

Weighted average grant date fair value	$	12.65		$	8.20		$	3.93

Performance-Based Awards. We grant performance-based awards to officers and key employees without cost to participants. The number of performance-based awards earned is determined at the end of each performance period. All of the outstanding performance-based awards as of December 31, 2005, are for the 2004-2006 performance period.

The Compensation Committee granted the 2004-2006 performance-based awards through the Key Employee Award Program (the Program) established under the 2002 LTIP. Under the Program, each performance-based award represents a targeted award of (a) 16,000 shares of performance-based stock, (b) 68,000 performance-based stock options and (c) 16,000 cash units with each cash unit having an equivalent fair market value of one share of our common stock on the vesting date. The Program provides for a payout ranging from 0% to 140% of the targeted award level, as determined by the Compensation Committee in its sole discretion after considering various qualitative and quantitative performance criteria. These criteria include (a) reducing the ratio of our adjusted net debt to adjusted EBITDA to at least 3.5, (b) delivering superior customer value and (c) building a great company to work for, taking into consideration market conditions for each factor. The Compensation Committee has the discretion to weight the various performance objectives as it deems appropriate.

Summarized performance-based stock award activity, including the Program and previous programs and assuming a 140% payout of the Program, is:

	2005			2004			2003
Beginning of year		2,233,582			491,317		1,085,532
Granted		78,400			2,105,600		—
Performance factor adjustment⁽¹⁾		(115,188	)		—		—
Released		(57,594	)		(243,454	)	(263,501	)
Canceled or forfeited		(313,600	)		(119,881	)	(330,714	)

End of year		1,825,600			2,233,582		491,317

Weighted average grant date fair value	$	12.63		$	8.15		N/A

(1): Adjustments from assumed payouts during performance periods to actual awards at period end.

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Summarized performance-based option activity of the Program, assuming a 140% payout, is:

	2005				2004
	Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price
Beginning of year	8,758,400		$	8.15	—		$	—
Granted	333,200			12.63	8,948,800			8.15
Exercised	—			—	—			—
Canceled or expired	(1,332,800	)		8.14	(190,400	)		8.14

End of year	7,758,800			8.35	8,758,400			8.15

Exercisable at end of year	—			—	—			—

For performance-based options outstanding as of December 31, 2005:

		Outstanding							Exercisable
Exercise Price Range		Options		Weighted Average Exercise Price			Remaining Contractual Life (Years)		Options		Weighted Average Exercise Price
$8.14 - $12.63		7,758,800		$	8.35		8.2		—		$	—

Employee Stock Purchase Plan. We have 18 million shares of authorized common stock reserved and approved for issuance under the Reliant Energy, Inc. Employee Stock Purchase Plan (ESPP). Under the ESPP, substantially all regular employees can purchase our common stock through payroll deductions of up to 15% of eligible compensation. The ESPP provides for semiannual offering periods commencing on January 1 and July 1 of each year. The share price paid by an employee equals the lesser of 85% of the average market price on the first or last business day of each offering period. Individual ESPP participants are restricted from purchasing more than $25,000 of common stock in a calendar year.

During January 2006, and during 2005, 2004 and 2003, we issued 359,966 shares, 838,120 shares, 1,580,295 shares and 2,710,776 shares under the ESPP, respectively. Approximately 11.5 million reserved unissued shares were available under the ESPP as of December 31, 2005.

(b) Pension and Postretirement Benefits.

Benefit Plans. We sponsor multiple defined benefit pension plans. We provide subsidized postretirement benefits to some bargaining employees but generally do not provide them to non-bargaining employees.

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We use a December 31 measurement date for our plans. Our benefit obligations and funded status are:

			Pension						Postretirement Benefits
			2005			2004			2005			2004
			(in millions)
Change in Benefit Obligation
	Beginning of year		$	65		$	54		$	72		$	63
	Service cost			6			6			2			2
	Interest cost			4			3			4			4
	Curtailments and benefits enhancement			—			(4	)		—			(1	)
	Benefits paid			(2	)		(1	)		(1	)		—
	Plan amendments			—			8			—			(2	)
	Actuarial (gain) loss			9			(1	)		(10	)		6

		End of year	$	82		$	65		$	67		$	72

Change in Plan Assets
	Beginning of year		$	39		$	26		$	—		$	—
	Employer contributions			11			10			1			—
	Benefits paid			(2	)		(1	)		(1	)		—
	Actual investment return			2			4			—			—

		End of year	$	50		$	39		$	—		$	—

Reconciliation of Funded Status
	Funded status		$	(32	)	$	(26	)	$	(67	)	$	(72	)
	Unrecognized prior service cost			8			9			4			5
	Unrecognized actuarial loss			14			4			6			18

		Net amount recognized	$	(10	)	$	(13	)	$	(57	)	$	(49	)

Effective January 2005, some bargaining and non-bargaining employees no longer accrue benefits under any defined benefit pension plan. This curtailment resulted in a $4 million decrease in the pension benefit obligation during 2004. In addition, during 2004, we made design changes in the benefit formula for some bargaining employees. Some non-bargaining employees whose pension benefits were frozen received an additional benefit. These plan amendments resulted in an $8 million increase in the pension benefit obligation during 2004.

Amounts recognized in the consolidated balance sheets are:

		Pension						Postretirement Benefits
		December 31,						December 31,
		2005			2004			2005			2004
		(in millions)
Accrued benefit cost		$	(16	)	$	(19	)	$	(57	)	$	(49	)
Intangible asset			6			6			—			—

	Net amount recognized	$	(10	)	$	(13	)	$	(57	)	$	(49	)

The accumulated benefit obligation for all pension plans was $73 million and $57 million as of December 31, 2005 and 2004, respectively. All pension plans have accumulated benefit obligations in excess of plan assets.

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Net benefit costs are:

		Pension									Postretirement Benefits
		2005			2004			2003			2005		2004			2003
		(in millions)
Service cost		$	6		$	6		$	6		$	2	$	2		$	2
Interest cost			4			3			3			4		4			3
Expected return on plan assets			(3	)		(2	)		(1	)		—		—			—
Curtailments and benefits enhancement			—			—			—			—		(2	)		—
Net amortization			1			1			—			2		2			2

	Net benefit cost	$	8		$	8		$	8		$	8	$	6		$	7

Assumptions. The significant weighted average assumptions used to determine the benefit obligations are:

	Pension				Postretirement Benefits
	December 31,				December 31,
	2005		2004		2005		2004
Discount rate	5.75	%	5.75	%	5.75	%	5.75	%
Rate of increase in compensation levels	3.0	%	3.0	%	3.0	%	3.0	%

The significant weighted average assumptions used to determine the net benefit costs are:

	Pension						Postretirement Benefits
	2005		2004		2003		2005		2004		2003
Discount rate	5.75	%	6.25	%	6.75	%	5.75	%	6.25	%	6.75	%
Rate of increase in compensation levels	3.0	%	4.5	%	4.0-4.5	%	3.0	%	4.5	%	4.5	%
Expected long-term rate of return on assets	7.5	%	7.5	%	8.5	%	N/A		N/A		N/A

As of December 31, 2005 and 2004, we developed our expected long-term rate of return on pension plan assets based on third party models. These models consider expected inflation, current dividend yields, expected corporate earnings growth and risk premiums based on the expected volatility of each asset category. We weight the expected long-term rates of return for each asset category to determine our overall expected long-term rate of return on pension plan assets. In addition, we review peer data and historical returns.

Our assumed health care cost trend rates used to measure the expected cost of benefits covered by our postretirement plans are:

	2005		2004		2003
Health care cost trend rate assumed for next year	9.0	%	9.75	%	10.5	%
Rate to which the cost trend rate is assumed to gradually decline	5.5	%	5.5	%	5.5	%
Year that the rate reaches the rate to which it is assumed to decline	2011		2011		2011

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Assumed health care cost trend rates can have a significant effect on the amounts reported for our health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects as of December 31, 2005:

	One-Percentage Point
	Increase		Decrease
	(in millions)
Effect on service and interest cost	$	1	$	(1	)
Effect on accumulated postretirement benefit obligation		9		(7	)

Plan Assets. Our pension weighted average asset allocations and target allocation by asset category are:

		Percentage of Plan Assets as of December 31,				Target Allocation
		2005		2004		2006
Domestic equity securities		50	%	55	%	50	%
International equity securities		11		15		10
Global equity securities		10		—		10
Debt securities		29		30		30

	Total	100	%	100	%	100	%

In managing the investments associated with the pension plans, our objective is to exceed, on a net-of-fee basis, the rate of return of a performance benchmark composed of the following indices:

Asset Class		Index	Weight
Domestic equity securities		Wilshire 5000 Index	50	%
International equity securities		MSCI All Country World Ex-U.S. Index	10
Global equity securities		MSCI All Country World Index	10
Debt securities		Lehman Brothers Aggregate Bond Index	30

	Total		100	%

As a secondary measure, we compare asset performance to the returns of a universe of comparable funds, where applicable, over a full market cycle. Our Benefits Committee reviews plan asset performance each quarter by comparing the actual quarterly returns of each asset class to its related benchmark. Our plan assets have generally performed in accordance with the benchmarks.

Cash Obligations. We expect pension cash contributions to approximate $2 million during 2006. Expected benefit payments for the next ten years, which reflect future service as appropriate, are (in millions):

	Pension		Postretirement Benefits
2006	$	1	$	1
2007		1		1
2008		2		2
2009		3		3
2010		3		3
2011-2015		28		27

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(c) Savings Plan.

We have employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code. Under the plans, participating employees may contribute a portion of their compensation generally up to a maximum of 50% pre-tax and 16% after-tax during 2005 and 16% pre-tax or after-tax during 2004 and 2003, with the exception of the Orion Power Holdings savings plan under which contributions are generally up to a maximum of 18% of compensation. Bargaining employees contribute based on their respective agreements. Our savings plans benefit expense, including the matching contributions of generally up to 6% and discretionary contributions, was $19 million, $23 million and $28 million during 2005, 2004 and 2003, respectively.

We sponsor non-qualified deferred compensation plans for key and highly compensated employees. Our obligations under these plans were $37 million and $38 million and related rabbi trust investments were $27 million as of December 31, 2005 and 2004.

(d) Other Employee Matters.

As of December 31, 2005, approximately 33% of our employees are subject to collective bargaining arrangements. Our collective bargaining arrangements expire at various intervals beginning in 2006.

(10) Income Taxes

Our income tax expense (benefit) is:

			2005			2004			2003
			(in millions)
Current:
	Federal		$	7		$	(5	)	$	(23	)
	State			19			(2	)		43

		Total current		26			(7	)		20

Deferred:
	Federal			(305	)		(149	)		88
	State			26			40			(33	)

		Total deferred		(279	)		(109	)		55

Income tax expense (benefit) from continuing operations			$	(253	)	$	(116	)	$	75

Income tax expense (benefit) from discontinued operations			$	(68	)	$	(19	)	$	111

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A reconciliation of the federal statutory income tax rate to the effective income tax rate is:

			2005			2004			2003
			(in millions)
Loss from continuing operations before income taxes			$	(694	)	$	(392	)	$	(841	)
Federal statutory rate				35	%		35	%		35	%

Income tax benefit at statutory rate				(243	)		(137	)		(294	)

Net addition (reduction) in taxes resulting from:
	Federal tax reserves			1			(12	)		9
	State income taxes, net of federal income taxes			29			25			6
	Non-deductible compensation			2			5			—
	Capital loss valuation allowances			(82	)		—			—
	Changes in estimates of deferred tax assets and liabilities			29			—			—
	Wholesale energy goodwill impairment			—			—			345
	Commodity Futures Trading Commission settlement			—			—			6
	Other, net			11			3			3

		Total		(10	)		21			369

Income tax expense (benefit) from continuing operations			$	(253	)	$	(116	)	$	75

Effective rate				36	%		29	%		NM	⁽¹⁾

(1): Not meaningful. The primary reason is due to the wholesale energy segment's goodwill impairment of $985 million, for which no tax benefit can be recognized as the goodwill is non-deductible.

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Deferred tax assets and liabilities are:

			December 31,
			2005			2004
			(in millions)
Deferred tax assets:
Current:
	Derivative liabilities, net		$	211		$	84
	Capital loss carryforwards			86			—
	Western states settlement			51			—
	Allowance for doubtful accounts and credit provisions			11			16
	Employee benefits			4			15
	Other			4			3

		Total current deferred tax assets		367			118

Non-current:
	Employee benefits			51			53
	Net operating loss carryforwards			489			238
	Capital loss carryforwards			40			122
	State tax credit carryforwards			17			12
	Environmental reserves			12			18
	Derivative liabilities, net			106			41
	Other			19			40
	Valuation allowances			(116	)		(234	)

		Total non-current deferred tax assets		618			290

		Total deferred tax assets	$	985		$	408

Deferred tax liabilities:
Current:
	Other		$	—		$	7

		Total current deferred tax liabilities		—			7

Non-current:
	Depreciation and amortization			649			499
	Other			6			—

		Total non-current deferred tax liabilities		655			499

		Total deferred tax liabilities	$	655		$	506

		Accumulated deferred income taxes, net	$	330		$	(98	)

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Tax Attribute Carryovers. Our tax attribute carryovers are:

		December 31, 2005		Statutory Carryforward Period	Expiration Year(s)
		(in millions)		(in years)
Net Operating Loss Carryforwards:
	Federal	$	1,107	20	2022 through 2025
	State		2,139	5 to 20	2006 through 2025
	Foreign		56	7 to 10	2008 through 2014
Capital Loss Carryforwards:		$	361	5	2008 through 2010
State Tax Credit Carryforwards:		$	26	5	2006 through 2010

Agreement with CenterPoint. We ceased being a member of the CenterPoint consolidated tax group as of September 30, 2002 and could be limited in our ability to use tax attributes. CenterPoint's income tax returns for the 1997 to 2002 tax reporting periods are under audit by federal taxing authorities. We have a tax allocation agreement that addresses the allocation of taxes pertaining to our separation from CenterPoint. This agreement provides that we may carry back net operating losses generated subsequent to September 30, 2002 to tax years when we were part of CenterPoint's consolidated tax group. This agreement is subject to CenterPoint's consent and any existing statutory carryback limitations. During 2003, we carried back net operating losses related to 2002 to prior CenterPoint tax years and received tax refunds of $76 million and $30 million during 2004 and 2003, respectively. In addition, pursuant to this agreement with CenterPoint, we will (a) recognize any costs incurred by CenterPoint for temporary differences related to the periods prior to September 30, 2002 up to $15 million as an expense in our results of operations and as an equity contribution and (b) recognize any benefits realized by CenterPoint for temporary differences related to the periods prior to September 30, 2002 up to $1 million as income in our results of operations and as an equity distribution. Amounts in excess of the $15 million and $1 million thresholds will be settled in cash between us and CenterPoint. Pursuant to this agreement, generally, taxes related to permanent differences are the responsibility of CenterPoint. As of December 31, 2005, we cannot predict the amount of any contingent liabilities or assets that we may incur or realize under this agreement.

Valuation Allowances. Our valuation allowances decreased $118 million during 2005, decreased $36 million during 2004 and increased $217 million during 2003. These changes primarily result from actual transactions that either decrease the likelihood that our tax assets will be realized to a level that is below "more likely than not" or that allow us to use a tax asset that was previously subject to a valuation allowance. Such changes also reflect an ongoing assessment of our future ability to use federal, state and foreign tax net operating losses, capital loss carryforwards and other tax assets. These assessments included an evaluation of our recent history of earnings and losses (as adjusted), future reversals of temporary differences and identification of other sources of future taxable income, including the identification of tax planning strategies. We monitor these factors quarterly and there is no assurance that these factors will continue to support a conclusion that the ultimate realization of any particular deferred tax asset is more likely than not. Specifically, the decrease during 2005 is primarily due to the release of valuation allowances against our capital loss carryforwards as the result of net capital gains recorded during the year and the identification of various tax planning strategies that would make the realization of the remaining capital loss carryforwards more likely than not.

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The changes are:

		2005			2004			2003
		(in millions)
State net operating loss carryforwards		$	(6	)	$	47		$	4
Capital loss carryforwards			(120	)⁽¹⁾		(79	)⁽²⁾		199	⁽³⁾
Other, net			8			(4	)		14

	Net change	$	(118	)	$	(36	)	$	217

(1): Net decrease is primarily due to net capital gains recorded during the year and the identification of various tax planning strategies with respect to the sale of certain assets. See note 19. Of this amount, $82 million is recorded in continuing operations and $38 million is recorded in discontinued operations.
(2): Net decrease is primarily due to the utilization of $77 million of previously reserved net capital losses from the sale of our European energy operations primarily resulting from the sale of our hydropower plants, partially offset by the transfer of our Liberty operations, which is recorded in discontinued operations. See note 20.
(3): Net increase is primarily due to a capital loss on the sale of our European energy operations, which is recorded in discontinued operations. See note 20.

Tax Contingencies. Our income tax returns, including years when we were included in CenterPoint's consolidated tax group, for the 1997 to 2004 tax reporting periods are under audit by federal and state taxing authorities. These audits may result in additional taxes or revisions of the timing of tax payments. We evaluate the need for contingent tax liabilities on a quarterly basis and record any estimable and probable tax exposures in our results of operations. In addition, we disclose any material tax contingencies as to which we believe there is a reasonable possibility of a future tax assessment.

We have received proposed tax assessments from certain taxing authorities, which are currently at varying stages of appeals. The issues primarily relate to temporary differences and include deductions for plant abandonments, bad debts, capitalization of costs to plant and inventory, depreciable lives and various other matters. It could take several years to resolve these contingencies.

As of December 31, 2005 and 2004, we have accrued contingent federal and state tax reserves related to our continuing operations of $46 million and $48 million, respectively. These reserve balances are primarily classified in other long-term liabilities. During 2005, we decreased our contingent federal and state tax reserves by $2 million, net primarily as a result of changes in estimates of federal and state tax exposures. During 2004, we reduced our contingent federal and state tax reserves by $12 million, net primarily as a result of changes in estimates of federal tax exposures. We do not believe these contingencies will be resolved within the next 12 months.

As of December 31, 2005 and 2004, we have accrued contingent federal tax reserves related to our discontinued European energy operations of $11 million and $56 million, respectively, included in other long-term liabilities in continuing operations. We reserved these amounts for potential future federal income tax assessments on certain income from our former European subsidiaries. If sustained, these assessments would increase our capital loss carryforwards by $45 million. The decrease of $45 million, which is recorded in discontinued operations, during 2005 is due to the identification of tax planning strategies that would make the realization of additional capital loss carryforwards more likely than not.

Pursuant to the Texas electric restructuring law, we made a payment of $177 million to CenterPoint during 2004 related to our residential customers. See note 13(d). During 2005, we reached a settlement agreement related to the class action lawsuits against us for claims alleging violations of securities laws and associated legal expenses. The settlement agreement provides for a total settlement payment by us of $68 million. See note 13(c). During 2005, we recorded a pre-tax charge of $351 million to settle certain civil litigation and claims relating to the Western states energy crisis. See

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note 13(a). We believe that the substantial majority of these payments and charges are deductible for income tax purposes; however, no assurance can be given that the Internal Revenue Service would not assert, or that a court would not sustain, a contrary position.

(11) Commitments

(a) Lease Commitments.

REMA Leases. One of our subsidiaries, REMA, entered into sale-leaseback transactions, under operating leases that are non-recourse to us. We lease 16.45% and 16.67% interests in the Conemaugh and Keystone facilities, respectively. The leases expire in 2034 and we expect to make payments through 2029. We also lease a 100% interest in the Shawville facility. This lease expires in 2026 and we expect to make payments through that date. At the expiration of these leases, there are several renewal options related to fair market value. REMA LLC's subsidiaries guarantee the lease obligations and we have pledged the equity interests in these subsidiaries as collateral. We provide credit support for REMA's lease obligations in the form of letters of credit under the December 2004 credit facilities. See note 6. During 2005, 2004 and 2003, we made lease payments under these leases of $75 million, $85 million and $77 million, respectively. As of December 31, 2005 and 2004, we have recorded a prepaid lease of $59 million in other current assets and $259 million and $243 million, respectively, in long-term assets. REMA operates these facilities under agreements that could terminate annually with one year's notice and received fees of $9 million, $9 million and $8 million during 2005, 2004 and 2003, respectively, relating to the Conemaugh and Keystone facilities. These fees, which are recorded in operation and maintenance expense, are primarily to cover REMA's administrative support costs of providing these services.

REMA's ability to make distributions or pay subordinated obligations is restricted by conditions within the lease documents. As of December 31, 2005, all of these conditions were met.

Tolling Agreements. We have two tolling arrangements that extend through 2007 and 2012. These arrangements, which qualify as operating leases, entitle us to purchase and dispatch electric generating capacity. We paid $64 million, $61 million and $54 million in tolling payments during 2005, 2004 and 2003, respectively.

Office Space Lease. In 2003, we entered into a long-term operating lease for our corporate headquarters. The lease expires in 2018 and is subject to two five-year renewal options.

Cash Obligations Under Operating Leases. Our projected cash obligations under non-cancelable long-term operating leases as of December 31, 2005 are:

		REMA Leases		Other⁽¹⁾⁽²⁾		Total
		(in millions)
2006		$	64	$	91	$	155
2007			65		65		130
2008			62		62		124
2009			63		62		125
2010			52		60		112
2011 and thereafter			882		243		1,125

	Total	$	1,188	$	583	$	1,771

(1): Includes tolling arrangements, rental agreements for office space and data processing equipment and vehicles.
(2): Excludes projected sublease income on office space of $37 million.

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Operating Lease Expense. Total lease expense for all operating leases was $152 million, $169 million and $162 million during 2005, 2004 and 2003, respectively.

(b) Guarantees.

We have guaranteed certain non-qualified benefits of CenterPoint's existing retirees at September 20, 2002. The estimated maximum potential amount of future payments under this guarantee was approximately $59 million and $62 million as of December 31, 2005 and 2004, respectively. We believe the likelihood that we would incur any significant losses under this guarantee is remote and, therefore, have not recorded a liability in our consolidated balance sheets as of December 31, 2005 or 2004.

We also guarantee the $500 million PEDFA bonds, which are included in our consolidated balance sheet as outstanding debt. Our guarantee is secured by a guarantee from all of our subsidiaries that guarantee the December 2004 credit facilities and the collateral that secures our senior secured notes and October 2005 credit facility. The guarantees require us to comply with covenants substantially identical to those in the senior secured notes indentures. The PEDFA bonds will become secured by certain assets of Seward if the collateral supporting both the senior secured notes and our guarantee is released. Our maximum potential obligation under the guarantee is for payment of the principal of $500 million and related interest charges at a fixed rate of 6.75%.

We have guaranteed payments to a third party relating to energy sales from El Dorado Energy, LLC, a former investment. The estimated maximum potential amount of future payments under this guarantee is approximately $21 million as of December 31, 2005. We secured a portion of the guarantee with letters of credit. We have not recorded a liability in our consolidated balance sheets for this guarantee.

We enter into contracts that include indemnification and guarantee provisions. In general, we enter into contracts with indemnities for matters such as breaches of representations and warranties and covenants contained in the contract and/or against certain specified liabilities. Examples of these contracts include asset sales agreements, retail supply agreements, service agreements and procurement agreements.

In our debt agreements, we typically indemnify against liabilities that arise from the preparation, entry into, administration or enforcement of the agreement.

We are unable to estimate our maximum potential exposure under these provisions until an event triggering payment under these provisions occurs. Based on current information, we consider the likelihood of making any material payments under these provisions to be remote.

(c) Other Commitments.

Fuel Supply, Commodity Transportation, Purchase Power and Electric Capacity Commitments. We are a party to fuel supply contracts, commodity transportation contracts and purchase power and electric capacity contracts of various quantities and durations that are not classified as derivative assets and liabilities. These contracts are not included in our consolidated balance sheet as of December 31,

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2005. Minimum purchase commitment obligations under these agreements are as follows as of December 31, 2005:

		Fuel Commitments		Transportation Commitments		Purchased Power and Electric Capacity Commitments
		(in millions)
2006		$	273	$	118	$	141
2007			142		108		70
2008			60		101		19
2009			54		97		—
2010			23		96		—
2011 and thereafter			165		823		—

	Total	$	717	$	1,343	$	230

As of December 31, 2005, the maximum remaining terms under any individual fuel supply contract is 15 years, any transportation contract is 18 years and any purchased power and electric capacity contract is 3 years.

Sales Commitments. As of December 31, 2005, we have sales commitments, including electric energy and capacity sales contracts, which are not classified as derivative assets and liabilities. The estimated minimum sales commitments under these contracts are as follows (in millions):

2006		$	2,637
2007			1,286
2008			658
2009			355
2010			198

	Total	$	5,134

Naming Rights to Houston Sports Complex. We acquired the naming rights, including advertising and other benefits, for a football stadium and other convention and entertainment facilities included in the stadium complex. Pursuant to this agreement, we are required to pay $10 million per year from 2002 through 2032.

Long-term Power Generation Maintenance Agreements. We have entered into long-term maintenance agreements that cover some periodic maintenance, including parts, on power generation turbines. The long-term maintenance agreements terminate over the next three to 31 years based on turbine usage. During 2005, 2004 and 2003, we incurred expenses of $16 million, $14 million and $8 million, respectively. Estimated cash payments over the next five years for these agreements are as follows (in millions):

2006		$	24
2007			52
2008			47
2009			34
2010			63

	Total	$	220

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(12) Contingencies

(a) Legal Proceedings.

We are parties to many legal proceedings, some of which may involve substantial amounts. Unless otherwise noted, we cannot predict the outcome of these proceedings.

Pending Western States Electricity and Natural Gas Litigation

The following proceedings relate to alleged conduct in the electricity and natural gas markets of California and other western states. In 2005, we settled a number of these proceedings; however, many other proceedings remain pending. See note 13.

Electricity Actions. We are parties to various lawsuits in state and federal courts in California relating to our participation in alleged conduct to increase electricity prices in violation of antitrust laws, unfair competition laws and similar laws. The lawsuits seek treble damages, restitution and expenses. The United States Court of Appeals for the Ninth Circuit upheld the dismissal of many of these lawsuits on the basis that the Federal Energy Regulatory Commission (FERC) has exclusive jurisdiction over the claims. In June 2005, the United States Supreme Court denied a petition to review the dismissal of one of these lawsuits. In August 2005, we reached a settlement for a majority of these lawsuits, which was approved by the FERC and given preliminary approval by the California Superior Court in December 2005. We believe that the courts in which the three remaining lawsuits are pending will apply the Ninth Circuit's prior decisions to those lawsuits. For a description of the settlement terms, see note 13.

Natural Gas Actions. We are parties to 38 lawsuits, a number of which are class action lawsuits, including an action brought by the Nevada Attorney General on behalf of gas consumers in Nevada, in state and federal courts in California, Kansas, New York, Nevada and Tennessee relating to alleged conduct to increase natural gas prices in violation of antitrust and similar laws. The lawsuits seek treble damages, restitution and expenses. The lawsuits also name our subsidiary, Reliant Energy Services, Inc. (Reliant Energy Services), and a number of unaffiliated energy companies as parties. In December 2005, we entered into an agreement in principle to settle the New York class action lawsuits (Cornerstone settlement) involving the alleged manipulation of NYMEX natural gas contracts. The settlement, which is subject to the execution of definitive agreements and court approval, will require us to pay $8 million to the plaintiffs. See note 13.

Criminal Proceeding—Reliant Energy Services. In April 2004, a California federal grand jury indicted Reliant Energy Services and some of its former and current employees for alleged violations of the Commodity Exchange Act, wire fraud and on conspiracy charges. The indictment claims Reliant Energy Services manipulated prices by curtailing electricity generation in California on two days in June 2000. We believe the actions alleged in the indictment did not violate laws in effect during this period and are contesting the indictment vigorously. The earliest we expect the trial to begin is late 2006. If convicted, our subsidiary could be assessed statutory penalties equal to twice the alleged benefit to us from the conduct or twice the alleged harm to the market from the conduct. The indictment alleges that the conduct could have resulted in harm to the market of up to $32 million. In addition, a criminal conviction of Reliant Energy Services could result in potential suspension or debarment from government contracting. We do not believe that the indictment will have any material adverse impact on our business operations.

Los Angeles Department of Water and Power. After filing a similar lawsuit in the California Superior Court in July 2003 (which was transferred to the United States District Court of Nevada and voluntarily dismissed in March 2005), the Los Angeles Department of Water and Power (LADWP) sued us in California Superior Court in January 2004. The lawsuit alleges that we conspired to manipulate natural gas prices in breach of our supply contract with LADWP and in violation of

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California's antitrust laws and the California False Claims Act. The lawsuit seeks treble damages for the alleged overcharges (estimated to be $218 million) for gas purchased by LADWP, interest and legal costs. The lawsuit also seeks (a) a determination that an extension of the contract with LADWP was invalid in that the required municipal approvals for the extension were allegedly not obtained and (b) a return of all money paid by LADWP during that period (estimated to be $681 million).

Montana Attorney General. In June 2003, the Montana Attorney General sued Reliant Energy Services and unaffiliated energy companies in Montana state court alleging an unlawful conspiracy to artificially increase electricity and natural gas prices between 2000 and 2001. The lawsuit, which has never been served on us, seeks injunctive relief, treble damages, restitution of overpayments, disgorgement of unlawful profits and legal expenses.

United States Attorney Investigation

Investigation of Natural Gas Price Reporting Issues. The United States Attorney for the Southern District of Texas has been investigating natural gas price reporting issues. The issues relate to the alleged submission of false data to various energy publications and reporting services. In November 2004, a grand jury indicted a former employee of Reliant Energy Services for alleged misreporting of gas prices and the employee subsequently plead guilty but has not been sentenced. The investigation is ongoing and could result in civil or criminal actions being brought against us, certain of our subsidiaries or other current and former employees.

Other Litigation

Texas Commercial Energy. In July 2003, Texas Commercial Energy, LLP (TCE) sued us and several other ERCOT power market participants in the United States District Court for the Southern District of Texas. TCE claimed damages in excess of $535 million for alleged violations of state and federal antitrust laws, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract and civil conspiracy. The trial court dismissed the lawsuit. The United States Court of Appeals for the Fifth Circuit affirmed the dismissal of the lawsuit and denied TCE's request for a rehearing. In January 2006, the United States Supreme Court denied a petition to review the dismissal of the lawsuit.

Utility Choice Electric. In February 2005, Utility Choice Electric filed a lawsuit that alleges similar claims to the TCE lawsuit and additional claims including, among others, wire fraud, mail fraud and violations of the Racketeer Influenced and Corrupt Organizations Act. In December 2005, the United States District Court for the Southern District of Texas granted our motion to dismiss all federal claims. The court also dismissed without prejudice the state law claims. Following the dismissal, we reached an agreement to settle the remaining state law claims for an immaterial amount.

ERISA Action. In 2002, participants in our and CenterPoint's employee benefits plan filed a class action lawsuit in the United States District Court for the Southern District of Texas against us and CenterPoint that alleges breach of fiduciary duties in violation of the Employee Retirement Income Security Act (ERISA). The lawsuit seeks monetary damages and restitution. In 2004, the court dismissed us from this proceeding. CenterPoint and some members of CenterPoint's benefits committee, whom we agreed to indemnify, remained in this case. In January 2006, the court granted our motion for summary judgment and dismissed the case with prejudice. The plaintiffs have the right to appeal the court's decision.

CenterPoint Indemnity

We have agreed to indemnify CenterPoint against certain losses relating to the lawsuits described above under: (a) "Pending Western States Electricity and Natural Gas Litigation—Natural Gas Actions," and "—Los Angeles Department of Water and Power" and (b) "Other Litigation—ERISA

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Action." In addition, we are also required to indemnify CenterPoint for certain liabilities relating to the initial public offering of our common stock.

PUCT Cases

There are various proceedings pending before the state district court in Travis County, Texas, seeking reviews of the Public Utility Commission of Texas (PUCT) orders relating to the fuel factor component used in our "price-to-beat" tariff. These proceedings pertain to the same issues affirmed by a district court in Travis County and later by the Travis County Court of Appeals in 2004 in a separate proceeding.

(b) Environmental Matters.

New Source Review Matters. The United States Environmental Protection Agency (EPA) and various states are investigating compliance of coal-fueled electric generating stations with the "New Source Review" requirements of the Clean Air Act. The EPA has agreed to share information relating to its investigations with state environmental agencies. We are unable to predict the ultimate outcome of the EPA's investigation. In November 2005, we received a notice of intent to sue pursuant to the Clean Air Act from the state of New Jersey relating to one of our power plants located in Pennsylvania. The allegations relate to conduct that occurred prior to our ownership of the power plant. If the state of New Jersey sues us and is successful, we could incur significant capital expenditures associated with the implementation of emissions reductions on an accelerated basis and possible penalties.

Ash Disposal Site Closures. We are responsible for environmental costs related to the future closures of seven ash disposal sites, five of which are owned in whole or in part by REMA and two of which are owned by Orion MidWest. Based on our evaluations with assistance from third-party consultants and engineers, we recorded the estimated discounted costs associated with these environmental liabilities as part of our asset retirement obligations. See note 2(q).

Remediation Obligations. We are responsible for environmental costs related to site contamination investigations and remediation requirements at four power plants in New Jersey. Based on our evaluations with assistance from third-party consultants and engineers, we recorded the estimated liability for the remediation costs of $7 million as of December 31, 2005 and 2004, respectively.

Environmental Class Action. We received notice of a class action lawsuit filed in Superior Court in Ontario, Canada in June 2005 against us and approximately 20 other utility and power generation companies alleging various claims relating to environmental emissions from coal-fired power plants in the United States and Canada. The lawsuit alleges damages of approximately $42.1 billion, with continuing damages in the amount of approximately $3.5 billion annually. The lawsuit also claims entitlement to punitive and exemplary damages in the amount of $860 million. We converted Canadian dollars to United States dollars using an exchange rate as of December 31, 2005. The complaint was not timely served on us under Canadian law, but the plaintiffs may ask the court to extend the time of service or they may commence a new lawsuit. We do not know whether the plaintiffs will proceed with the lawsuit and are not in a position at this time to assess what impact, if any, an adverse decision might have on our results of operations, financial condition and cash flows; however, we are confident that we have operated and continue to operate our coal-fired plants in material compliance with all applicable federal and state environmental regulations.

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(13) Settlements and Other Charges

(a) Western States and Cornerstone Settlements.

In August 2005, we entered into an agreement, which the FERC approved in December 2005, with the states of California, Oregon and Washington, California's three largest investor-owned utilities and a number of other parties that resolves as to the settling parties the following civil litigation and claims related to the Western states energy crisis:

•: all issues between the settling parties regarding the Western market refund proceedings pending before the FERC for the period January 1, 2000 through June 20, 2001;
•: all issues with respect to pending appeals of prior FERC orders pertaining to the market activity during this period;
•: all issues regarding alleged manipulation of electricity markets during the period January 1, 2000 through December 31, 2001;
•: all market price investigations conducted by the Attorneys General in California, Washington and Oregon;
•: all civil litigation filed by the Attorney General in California, including the pending Clayton Act antitrust lawsuit;
•: all private electricity-related class action lawsuits filed on behalf of ratepayers in California, Washington, Oregon, Idaho and Utah; and
•: all natural gas price issues raised by all of the parties to the agreement except the private class action litigants and local government entities.

Although the settlement resolves a number of the regulatory and civil proceedings relating to the Western states energy crisis of 2000 and 2001, it did not resolve the following Western states electricity and natural gas proceedings: (a) the criminal proceeding against Reliant Energy Services, (b) lawsuits filed by private class action litigants and individual consumers regarding an alleged conspiracy to increase natural gas prices, (c) the lawsuit filed by LADWP, (d) several pending lawsuits filed by individual electricity consumers and (e) the lawsuits filed by the Attorneys General of Nevada and Montana alleging an unlawful conspiracy to increase natural gas and electricity prices. See note 12.

Additionally, in December 2005, we agreed in principle to settle the class action lawsuits filed in New York involving allegations of manipulation of NYMEX natural gas contracts (the Cornerstone settlement). The settlement remains subject to court approval.

During 2005, we recorded charges of $359 million, which include a cash payment of approximately $150 million paid in January 2006. As part of the settlement, we waived claims to and transferred our

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interest in our receivables for power deliveries from January 1, 2000 to June 20, 2001, as well as the interest owed on those receivables. The components of the settlement charge are (in millions):

Accounts receivable related to the period from October 2000 through June 2001, excluding estimated refund obligation		$	268
Estimated refund obligation			(87	)
Discount			(14	)
Interest receivable			41
Cash payments			150	⁽¹⁾
Cornerstone settlement			8	⁽²⁾
Other			(7	)

	Total	$	359	⁽³⁾

(1): This payable is included in accounts payable as of December 31, 2005.
(2): This amount is payable upon final court approval. See note 12.
(3): The settlement also included undertakings not involving the payment of cash or the waiver of rights to receivables.

Prior to reaching a settlement in August 2005, we regularly adjusted our estimated refund obligation, credit reserve and receivables (netted in revenues) and interest income (recorded in interest income) related to these energy sales in California as new information was obtained or events occurred (income (loss)):

		2005			2004			2003
		(in millions)
Estimated refund obligation		$	2		$	(8	)	$	110
Credit reserve			—			21			(15	)
Direct adjustments to gross receivables			—			(11	)		—
Discount			(1	)		(13	)		—
Interest receivable			6			16			13

	Net impact	$	7		$	5		$	108

(b) Nevada Power.

In August 2005, we entered into a settlement agreement with Nevada Power Company resolving (a) a complaint filed by Nevada Power Company with the FERC seeking to revise the prices of long-term forward power contracts and (b) an arbitration claim relating to our alleged participation in an unlawful conspiracy to increase the price of natural gas in Nevada from 2001 to 2002. We recognized a charge of $8 million during 2005.

(c) Shareholder Class Action Lawsuits.

In July 2005, we reached a settlement agreement related to the class action lawsuits against us for claims alleging violations of securities laws. The settlement agreement provides for a total settlement payment by us of $68 million, of which $61.5 million is covered by director and officer insurance policies. In addition, Deloitte & Touche LLP, our independent auditor and a defendant in the litigation, has agreed to make a payment of $7 million. The settlement also includes releases to all claims asserted by the plaintiffs against some of our former officers. During the second quarter of 2005, we recognized a charge of $8 million related to the settlement and associated legal expenses.

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(d) Payment to CenterPoint.

In connection with our separation agreement, we made a payment of $177 million to CenterPoint in 2004 related to our residential customers. We recognized $2 million, $47 million and $128 million during 2004, 2003, and 2002, respectively.

(e) Gain on Sale of Counterparty Claim.

In June 2004, we entered into a settlement agreement with Enron. The settlement agreement provided for the dismissal of all pending litigation between Enron and us and provided for certain allowed bankruptcy claims against Enron. In August 2004, we sold and assigned our claim to a third party. As we had previously written off our net receivables and derivative assets from Enron, we recognized a $30 million gain upon the sale during the third quarter of 2004.

(f) Commodity Futures Trading Commission.

In November 2003, we entered into a settlement with the Commodity Futures Trading Commission in connection with an investigation relating to trading and price reporting issues. The settlement addressed the reporting of natural gas trading information to energy industry publications that compile and report index prices and seven offsetting and pre-arranged electricity trades that were executed on an electronic trading platform in 2000. Pursuant to the terms of the settlement, we paid a penalty of $18 million.

(g) FERC Investigations of Western Market Issues.

In January 2003, in connection with the FERC's investigation of potential manipulation of electricity and natural gas prices in the Western United States, the FERC approved an agreement between its staff and us relating to certain actions taken by some of our traders over a two-day period in June 2000. Under the agreement, we agreed, among other things, to (a) pay $14 million (which was expensed in 2002) directly to customers of the California Power Exchange and (b) submit bids for all of our uncommitted, available capacity from our plants located in California into a California spot market one additional year following termination of the existing must offer obligation or until December 31, 2006, whichever is later.

In October 2003, we entered into a settlement agreement with the FERC resolving all but one of its investigations and proceedings in connection with its ongoing review of western energy markets (which was exclusive of the proceedings described under "Pending Western States Electricity and Natural Gas Litigation—Electricity Actions" in note 12(a) and related settlement described in note 13(a)). The settlement provided, among other things, that we (a) make three cash settlement payments, totaling $25 million, into a fund established for the benefit of California and western market electricity consumers of which we paid $15 million in 2003 and $5 million in 2005 into the fund and an additional payment of $5 million will be made in 2006 and (b) offer capacity from a portion of our generation portfolio in California to the market (totaling 824 MW) for one-year terms for delivery commencing in 2004, 2005 and 2006 on a unit-contingent, gas-tolling basis for which we will pay the difference, up to $25 million, between the collected auction revenues and our projected cash costs to generate the power into the fund described above.

In 2003, we offered, but did not receive qualifying bids under the settlement agreement for the 12-month period beginning April 2004. During September 2004, we entered into a third party multi-year tolling agreement for the power capacity from two of our power generation units in California. The FERC approved our request to treat the tolling arrangement as meeting our obligation to offer capacity described in the paragraph above. In 2003, we recognized a $37 million loss for the settlement based on (a) the present value ($24 million) of the cash settlement payments ($25 million) and (b) the fair value of our obligation to offer capacity from our power generation portfolio

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($13 million) during 2005 and 2006, based on an option valuation model. In 2004, as a result of entering into the multi-year tolling agreement, we accrued an additional $12 million for the obligation to contribute to the above-described fund.

(14) Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and payable and derivative assets and liabilities equal their carrying amounts. Values of our debt (see note 6) are:

		December 31,
		2005				2004
		Carrying Value		Fair Market Value⁽¹⁾		Carrying Value		Fair Market Value⁽¹⁾
		(in millions)
Fixed rate debt		$	3,148	$	3,201	$	3,158	$	3,536
Floating rate debt⁽²⁾			1,958		1,937		1,400		1,405

	Total debt	$	5,106	$	5,138	$	4,558	$	4,941

(1): We based the fair market values of our fixed rate and floating rate debt on (a) incremental borrowing rates for similar borrowing arrangements or (b) information from market participants.
(2): Includes warrant values.

(15) Supplemental Guarantor Information

Our wholly-owned subsidiaries are either (a) full and unconditional guarantors, jointly and severally, or (b) non-guarantors of the senior secured notes. The primary guarantors are: Reliant Energy California Holdings, LLC; Reliant Energy Northeast Holdings, Inc.; Reliant Energy Power Generation, Inc.; Reliant Energy Retail Holdings, LLC and subsidiaries (excluding RE Retail Receivables, LLC) and Reliant Energy Services. The primary non-guarantors are: Channelview, Orion Power, REMA and RE Retail Receivables, LLC.

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Condensed Consolidating Statements of Operations.

		2005
		Reliant Energy			Guarantors			Non-Guarantors			Adjustments⁽¹⁾			Consolidated
		(in millions)
Revenues		$	—		$	9,855		$	1,758		$	(1,901	)	$	9,712

Purchased power, fuel and cost of gas sold			(1	)		9,322			919			(1,874	)		8,366
Operation and maintenance			—			363			399			(25	)		737
Selling, general and administrative			—			203			90			—			293
Loss on sales of receivables			—			63			(63	)		—			—
Western states and Cornerstone settlements			—			359			—			—			359
Gains on sales of assets and emission allowances, net			—			(3	)		(168	)		3			(168	)
Depreciation and amortization			—			220			226			—			446

	Total		(1	)		10,527			1,403			(1,896	)		10,033

Operating income (loss)			1			(672	)		355			(5	)		(321	)

Income of equity investments, net			—			26			—			—			26
Income (loss) of equity investments of consolidated subsidiaries			(193	)		95			—			98			—
Other, net			—			(23	)		—			—			(23	)
Interest expense			(278	)		(38	)		(83	)		—			(399	)
Interest income			1			20			2			—			23
Interest income (expense)—affiliated companies, net			144			(49	)		(95	)		—			—

	Total other income (expense)		(326	)		31			(176	)		98			(373	)

Income (loss) from continuing operations before income taxes			(325	)		(641	)		179			93			(694	)
Income tax expense (benefit)			12			(306	)		35			6			(253	)

Income (loss) from continuing operations			(337	)		(335	)		144			87			(441	)
Income (loss) from discontinued operations			6			130			(85	)		60			111

Income (loss) before cumulative effect of accounting change			(331	)		(205	)		59			147			(330	)
Cumulative effect of accounting change, net of tax			—			—			(1	)		—			(1	)

Net income (loss)		$	(331	)	$	(205	)	$	58		$	147		$	(331	)

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		2004
		Reliant Energy			Guarantors			Non-Guarantors			Adjustments⁽¹⁾			Consolidated
		(in millions)
Revenues		$	—		$	7,411		$	1,337		$	(650	)	$	8,098

Purchased power, fuel and cost of gas sold			—			6,446			762			(644	)		6,564
Operation and maintenance			—			391			397			(6	)		782
Selling, general and administrative			(4	)		210			120			—			326
Loss on sales of receivables			—			45			(11	)		—			34
Accrual for payment to CenterPoint			—			2			—			—			2
Gain on sale of counterparty claim			—			(8	)		(22	)		—			(30	)
Gains on sales of assets and emission allowances, net			—			(3	)		(17	)		—			(20	)
Depreciation and amortization			—			239			214			—			453

	Total		(4	)		7,322			1,443			(650	)		8,111

Operating income (loss)			4			89			(106	)		—			(13	)

Loss of equity investments, net			—			(9	)		—			—			(9	)
Income (loss) of equity investments of consolidated subsidiaries			88			(96	)		—			8			—
Other, net			—			11			2			—			13
Interest expense			(303	)		(71	)		(71	)		27			(418	)
Interest income			—			32			3			—			35
Interest income (expense)—affiliated companies, net			138			(9	)		(71	)		(58	)		—

	Total other expense		(77	)		(142	)		(137	)		(23	)		(379	)

Loss from continuing operations before income taxes			(73	)		(53	)		(243	)		(23	)		(392	)
Income tax expense (benefit)			(67	)		48			(54	)		(43	)		(116	)

Loss from continuing operations			(6	)		(101	)		(189	)		20			(276	)
Income (loss) from discontinued operations			(23	)		94			89			80			240

Loss before cumulative effect of accounting change			(29	)		(7	)		(100	)		100			(36	)
Cumulative effect of accounting change, net of tax			—			7			—			—			7

Net loss		$	(29	)	$	—		$	(100	)	$	100		$	(29	)

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		2003
		Reliant Energy			Guarantors			Non-Guarantors			Adjustments⁽¹⁾			Consolidated
		(in millions)
Revenues		$	—		$	9,341		$	1,472		$	(716	)	$	10,097

Purchased power, fuel and cost of gas sold			—			7,895			733			(716	)		7,912
Operation and maintenance			—			411			398			—			809
Selling, general and administrative			—			290			138			—			428
Loss on sales of receivables			—			37			—			—			37
Accrual for payment to CenterPoint			—			47			—			—			47
Gains on sales of assets and emission allowances, net			—			—			(3	)		—			(3	)
Wholesale energy goodwill impairment			—			126			585			274			985
Depreciation and amortization			11			158			189			—			358

	Total		11			8,964			2,040			(442	)		10,573

Operating income (loss)			(11	)		377			(568	)		(274	)		(476	)

Loss of equity investments, net			—			(2	)		—			—			(2	)
Loss of equity investments of consolidated subsidiaries			(1,177	)		(436	)		—			1,613			—
Other, net			—			1			8			—			9
Interest expense			(339	)		(9	)		(69	)		10			(407	)
Interest income			4			28			3			—			35
Interest income (expense)—affiliated companies, net			169			(17	)		(105	)		(47	)		—

	Total other expense		(1,343	)		(435	)		(163	)		1,576			(365	)

Loss from continuing operations before income taxes			(1,354	)		(58	)		(731	)		1,302			(841	)
Income tax expense (benefit)			(54	)		202			(58	)		(15	)		75

Loss from continuing operations			(1,300	)		(260	)		(673	)		1,317			(916	)
Income (loss) from discontinued operations			(42	)		18			(337	)		(41	)		(402	)

Loss before cumulative effect of accounting changes			(1,342	)		(242	)		(1,010	)		1,276			(1,318	)
Cumulative effect of accounting changes, net of tax			—			(42	)		18			—			(24	)

Net loss		$	(1,342	)	$	(284	)	$	(992	)	$	1,276		$	(1,342	)

(1): These amounts relate to either (a) eliminations and adjustments recorded in the normal consolidation process or (b) reclassifications recorded due to differences in classifications at the subsidiary levels compared to the consolidated level.

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Condensed Consolidating Balance Sheets.

			December 31, 2005
			Reliant Energy		Guarantors		Non-Guarantors		Adjustments⁽¹⁾			Consolidated
							(in millions)
ASSETS
Current Assets:
	Cash and cash equivalents		$	3	$	40	$	45	$	—		$	88
	Restricted cash			—		—		27		—			27
	Accounts and notes receivable, principally customer, net			—		348		840		(16	)		1,172
	Accounts and notes receivable—affiliated companies			802		1,395		1,096		(3,293	)		—
	Inventory			—		161		138		—			299
	Derivative assets			—		639		87		—			726
	Other current assets			1		2,129		91		(6	)		2,215
	Current assets of discontinued operations			2		46		157		(2	)		203

		Total current assets		808		4,758		2,481		(3,317	)		4,730

Property, Plant and Equipment, net				—		3,246		2,688		—			5,934

Other Assets:
	Goodwill			—		84		184		119			387
	Other intangibles, net			—		182		329		—			511
	Notes receivable—affiliated companies			2,506		812		2		(3,320	)		—
	Equity investments			—		30		—		—			30
	Equity investments of consolidated subsidiaries			3,721		364		—		(4,085	)		—
	Derivative assets			—		521		7		—			528
	Other long-term assets			188		150		380		(150	)		568
	Long-term assets of discontinued operations			720		—		873		(712	)		881

		Total other assets		7,135		2,143		1,775		(8,148	)		2,905

		Total Assets	$	7,943	$	10,147	$	6,944	$	(11,465	)	$	13,569

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
	Current portion of long-term debt and short-term borrowings		$	316	$	—	$	473	$	—		$	789
	Accounts payable, principally trade			8		848		31		—			887
	Accounts and notes payable—affiliated companies			—		1,826		1,467		(3,293	)		—
	Derivative liabilities			—		1,081		139		—			1,220
	Other current liabilities			62		305		69		(22	)		414
	Current liabilities of discontinued operations			—		49		49		(2	)		96

		Total current liabilities		386		4,109		2,228		(3,317	)		3,406

Other Liabilities:
	Notes payable—affiliated companies			—		2,512		808		(3,320	)		—
	Derivative liabilities			—		657		156		—			813
	Other long-term liabilities			11		262		266		(150	)		389
	Long-term liabilities of discontinued operations			638		—		854		(712	)		780

		Total other liabilities		649		3,431		2,084		(4,182	)		1,982

Long-term Debt				3,044		501		772		—			4,317

Commitments and Contingencies
Total Stockholders' Equity				3,864		2,106		1,860		(3,966	)		3,864

	Total Liabilities and Stockholders' Equity		$	7,943	$	10,147	$	6,944	$	(11,465	)	$	13,569

F-54

			December 31, 2004
			Reliant Energy		Guarantors		Non-Guarantors		Adjustments⁽¹⁾			Consolidated
			(in millions)
ASSETS
Current Assets:
	Cash and cash equivalents		$	25	$	33	$	47	$	—		$	105
	Restricted cash			—		—		16		—			16
	Accounts and notes receivable, principally customer, net			—		401		667		3			1,071
	Accounts and notes receivable—affiliated companies			218		867		529		(1,614	)		—
	Inventory			—		121		125		—			246
	Derivative assets			—		179		127		—			306
	Other current assets			9		723		78		—			810
	Current assets of discontinued operations			1		6		98		(1	)		104

		Total current assets		253		2,330		1,687		(1,612	)		2,658

Property, Plant and Equipment, net				—		3,485		2,953		—			6,438

Other Assets:
	Goodwill			—		84		295		62			441
	Other intangibles, net			—		146		395		—			541
	Notes receivable—affiliated companies			2,271		1,093		—		(3,364	)		—
	Equity investments			—		84		—		—			84
	Equity investments of consolidated subsidiaries			4,753		251		—		(5,004	)		—
	Derivative assets			—		221		51		—			272
	Restricted cash			—		—		25		—			25
	Other long-term assets			107		283		312		—			702
	Long-term assets of discontinued operations			832		—		1,024		(823	)		1,033

		Total other assets		7,963		2,162		2,102		(9,129	)		3,098

		Total Assets	$	8,216	$	7,977	$	6,742	$	(10,741	)	$	12,194

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
	Current portion of long-term debt and short-term borrowings		$	10	$	1	$	608	$	—		$	619
	Accounts payable, principally trade			3		534		29		—			566
	Accounts and notes payable—affiliated companies			—		662		952		(1,614	)		—
	Derivative liabilities			—		314		88		—			402
	Other current liabilities			56		354		70		3			483
	Current liabilities of discontinued operations			—		7		23		(1	)		29

		Total current liabilities		69		1,872		1,770		(1,612	)		2,099

Other Liabilities:
	Notes payable—affiliated companies			—		2,381		983		(3,364	)		—
	Derivative liabilities			—		204		107		—			311
	Other long-term liabilities			148		328		148		(7	)		617
	Long-term liabilities of discontinued operations			638		—		1,027		(823	)		842

		Total other liabilities		786		2,913		2,265		(4,194	)		1,770

Long-term Debt				2,975		501		463		—			3,939

Commitments and Contingencies
Total Stockholders' Equity				4,386		2,691		2,244		(4,935	)		4,386

		Total Liabilities and Stockholders' Equity	$	8,216	$	7,977	$	6,742	$	(10,741	)	$	12,194

(1): These amounts relate to either (a) eliminations and adjustments recorded in the normal consolidation process or (b) reclassifications recorded due to differences in classifications at the subsidiary levels compared to the consolidated level.

F-55

Condensed Consolidating Statements of Cash Flows.

			2005
			Reliant Energy			Guarantors			Non-Guarantors			Adjustments⁽¹⁾			Consolidated
									(in millions)
Cash Flows from Operating Activities:
	Net cash provided by (used in) continuing operations from operating activities		$	(95	)	$	(1,341	)	$	326		$	—		$	(1,110	)
	Net cash provided by discontinued operations from operating activities			13			8			172			—			193

	Net cash provided by (used in) operating activities			(82	)		(1,333	)		498			—			(917	)

Cash Flows from Investing Activities:
	Capital expenditures			—			(58	)		(24	)		—			(82	)
	Investments in and distributions from subsidiaries, net and advances to and distributions from subsidiaries, net⁽²⁾			(460	)		(6	)		(334	)		800			—
	Proceeds from sales of assets, net			—			104			45			—			149
	Net sales (purchases) of emission allowances			—			(49	)		137			—			88
	Restricted cash			—			—			14			—			14
	Other, net			—			6			—			—			6

		Net cash provided by (used in) continuing operations from investing activities		(460	)		(3	)		(162	)		800			175
		Net cash provided by discontinued operations from investing activities		110			51			80			(110	)		131

		Net cash provided by (used in) investing activities		(350	)		48			(82	)		690			306

Cash Flows from Financing Activities:
	Proceeds from long-term debt			299			—			—			—			299
	Payments of long-term debt			(109	)		(1	)		(38	)		—			(148	)
	Increase in short-term borrowings and revolving credit facilities, net			184			—			223			—			407
	Changes in notes with affiliated companies, net⁽³⁾			—			1,293			(493	)		(800	)		—
	Proceeds from issuances of stock			37			—			—			—			37
	Payments of financing costs			(1	)		—			—			—			(1	)

		Net cash provided by (used in) continuing operations from financing activities		410			1,292			(308	)		(800	)		594
		Net cash used in discontinued operations from financing activities		—			—			(110	)		110			—

		Net cash provided by (used in) financing activities		410			1,292			(418	)		(690	)		594

Net Change in Cash and Cash Equivalents				(22	)		7			(2	)		—			(17	)
Cash and Cash Equivalents at Beginning of Period				25			33			47			—			105

Cash and Cash Equivalents at End of Period			$	3		$	40		$	45		$	—		$	88

F-56

			2004
			Reliant Energy			Guarantors			Non-Guarantors			Adjustments⁽¹⁾			Consolidated
									(in millions)
Cash Flows from Operating Activities:
	Net cash provided by (used in) continuing operations from operating activities		$	(3	)	$	13		$	52		$	(57	)	$	5
	Net cash provided by (used in) discontinued operations from operating activities			(30	)		1			73			57			101

	Net cash provided by (used in) operating activities			(33	)		14			125			—			106

Cash Flows from Investing Activities:
	Capital expenditures			—			(118	)		(42	)		—			(160	)
	Investments in and distributions from subsidiaries, net and advances to and distributions from subsidiaries, net⁽²⁾			606			10			(721	)		105			—
	Purchase and sale of permits and licenses to affiliates			—			(20	)		20			—			—
	Proceeds from sales of assets, net			—			9			2			—			11
	Net purchases of emission allowances			—			(6	)		(59	)		—			(65	)
	Restricted cash			7			—			172			—			179
	Other, net			—			16			—			—			16

		Net cash provided by (used in) continuing operations from investing activities		613			(109	)		(628	)		105			(19	)
		Net cash provided by (used in) discontinued operations from investing activities		(823	)		8			911			823			919

		Net cash provided by (used in) investing activities		(210	)		(101	)		283			928			900

Cash Flows from Financing Activities:
	Proceeds from long-term debt			1,412			100			—			—			1,512
	Payments of long-term debt			(1,147	)		(2	)		(21	)		(427	)		(1,597	)
	Increase (decrease) in short-term borrowings and revolving credit facilities, net			16			—			(124	)		—			(108	)
	Changes in notes with affiliated companies, net⁽³⁾			—			(30	)		135			(105	)		—
	Proceeds from issuances of stock			25			—			—			—			25
	Payments of financing costs			(60	)		(12	)		—			—			(72	)
	Other, net			9			—			—			—			9

		Net cash provided by (used in) continuing operations from financing activities		255			56			(10	)		(532	)		(231	)
		Net cash used in discontinued operations from financing activities		(10	)		—			(410	)		(396	)		(816	)

		Net cash provided by (used in) financing activities		245			56			(420	)		(928	)		(1,047	)

Net Change in Cash and Cash Equivalents				2			(31	)		(12	)		—			(41	)
Cash and Cash Equivalents at Beginning of Period				23			64			59			—			146

Cash and Cash Equivalents at End of Period			$	25		$	33		$	47		$	—		$	105

F-57

			2003
			Reliant Energy			Guarantors			Non-Guarantors			Adjustments⁽¹⁾			Consolidated
			(in millions)
Cash Flows from Operating Activities:
	Net cash provided by continuing operations from operating activities		$	13		$	723		$	121		$	(14	)	$	843
	Net cash provided by (used in) discontinued operations from operating activities			(43	)		26			154			14			151

	Net cash provided by (used in) operating activities			(30	)		749			275			—			994

Cash Flows from Investing Activities:
	Capital expenditures			(21	)		(467	)		(60	)		—			(548	)
	Investments in and distributions from subsidiaries, net and advances to and distributions from subsidiaries, net⁽²⁾			1,635			—			35			(1,670	)		—
	Purchase and sale of permits and licenses to affiliates			—			(19	)		19			—			—
	Proceeds from sales of assets, net			—			—			2			—			2
	Net sales (purchases) of emission allowances			—			4			(66	)		—			(62	)
	Restricted cash			—			—			(42	)		—			(42	)
	Other, net			—			4			—			—			4

		Net cash provided by (used in) continuing operations from investing activities		1,614			(478	)		(112	)		(1,670	)		(646	)
		Net cash provided by discontinued operations from investing activities		—			284			1,279			—			1,563

		Net cash provided by (used in) investing activities		1,614			(194	)		1,167			(1,670	)		917

Cash Flows from Financing Activities:
	Proceeds from long-term debt			1,375			195			42			—			1,612
	Payments of long-term debt			(2,048	)		(5	)		(4	)		(85	)		(2,142	)
	Decrease in short-term borrowings and revolving credit facilities, net			(1,370	)		—			(4	)		(51	)		(1,425	)
	Changes in notes with affiliated companies, net⁽³⁾			—			(1,084	)		(586	)		1,670			—
	Proceeds from issuances of stock			8			—			—			—			8
	Payments of financing costs			(167	)		—			—			—			(167	)

		Net cash used in continuing operations from financing activities		(2,202	)		(894	)		(552	)		1,534			(2,114	)
		Net cash used in discontinued operations from financing activities		(16	)		—			(895	)		136			(775	)

		Net cash used in financing activities		(2,218	)		(894	)		(1,447	)		1,670			(2,889	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents				—			—			9			—			9

Net Change in Cash and Cash Equivalents				(634	)		(339	)		4			—			(969	)
Cash and Cash Equivalents at Beginning of Period				657			403			55			—			1,115

Cash and Cash Equivalents at End of Period			$	23		$	64		$	59		$	—		$	146

(1): These amounts relate to either (a) eliminations and adjustments recorded in the normal consolidation process or (b) reclassifications recorded due to differences in classifications at the subsidiary levels compared to the consolidated level.
(2): Net investments in and distributions from subsidiaries and net advances to and distributions from subsidiaries are classified as investing activities.
(3): Net changes in notes with affiliated companies are classified as financing activities.

F-58

(16) Unaudited Quarterly Information

			2005
			First Quarter			Second Quarter		Third Quarter			Fourth Quarter
			(in millions)
Revenues			$	1,718		$	2,431	$	2,963		$	2,615
Gross margin⁽¹⁾				375			593		266			138
Income (loss) from continuing operations				(42	)		51		(267	)		(183	)
Income (loss) from discontinued operations				17			48		(3	)		49
Income (loss) before cumulative effect of accounting change				(25	)		99		(270	)		(134	)
Net income (loss)				(25	)		99		(270	)		(135	)
Basic Earnings (Loss) Per Share:
	Income (loss) from continuing operations		$	(0.14	)	$	0.17	$	(0.88	)	$	(0.60	)
	Income (loss) from discontinued operations			0.06			0.16		(0.01	)		0.16

	Income (loss) before cumulative effect of accounting change			(0.08	)		0.33		(0.89	)		(0.44	)
	Cumulative effect of accounting change, net of tax			—			—		—			—

		Net income (loss)	$	(0.08	)	$	0.33	$	(0.89	)	$	(0.44	)

Diluted Earnings (Loss) Per Share:
	Income (loss) from continuing operations		$	(0.14	)	$	0.15	$	(0.88	)	$	(0.60	)
	Income (loss) from discontinued operations			0.06			0.14		(0.01	)		0.16

	Income (loss) before cumulative effect of accounting change			(0.08	)		0.29		(0.89	)		(0.44	)
	Cumulative effect of accounting change, net of tax			—			—		—			—

		Net income (loss)	$	(0.08	)	$	0.29	$	(0.89	)	$	(0.44	)

F-59

			2004
			First Quarter			Second Quarter			Third Quarter		Fourth Quarter
			(in millions)
Revenues			$	1,528		$	2,051		$	2,565	$	1,954
Gross margin⁽¹⁾				383			373			596		182
Income (loss) from continuing operations				(55	)		(83	)		75		(213	)
Income (loss) from discontinued operations				10			11			270		(51	)
Income (loss) before cumulative effect of accounting change				(45	)		(72	)		345		(264	)
Net income (loss)				(38	)		(72	)		345		(264	)
Basic Earnings (Loss) Per Share:
	Income (loss) from continuing operations		$	(0.18	)	$	(0.28	)	$	0.25	$	(0.71	)
	Income (loss) from discontinued operations			0.03			0.04			0.91		(0.17	)

	Income (loss) before cumulative effect of accounting change			(0.15	)		(0.24	)		1.16		(0.88	)
	Cumulative effect of accounting change, net of tax			0.02			—			—		—

		Net income (loss)	$	(0.13	)	$	(0.24	)	$	1.16	$	(0.88	)

Diluted Earnings (Loss) Per Share:
	Income (loss) from continuing operations		$	(0.18	)	$	(0.28	)	$	0.23	$	(0.71	)
	Income (loss) from discontinued operations			0.03			0.04			0.81		(0.17	)

	Income (loss) before cumulative effect of accounting change			(0.15	)		(0.24	)		1.04		(0.88	)
	Cumulative effect of accounting change, net of tax			0.02			—			—		—

		Net income (loss)	$	(0.13	)	$	(0.24	)	$	1.04	$	(0.88	)

(1): Revenues less purchased power, fuel and cost of gas sold.

Variances in revenues and gross margin from quarter to quarter were primarily due to (a) seasonal fluctuations in demand for electric energy and energy services and (b) changes in energy commodity prices, including unrealized gains/losses on energy derivatives. During 2005, we incurred $192 million in unrealized losses on energy derivatives ($120 million gain in the first quarter, $143 million gain in the second quarter, $354 million loss in the third quarter and $101 million loss in the fourth quarter, including $15 million due to the reclassification of a derivative contract from a cash flow hedge to mark-to-market). During 2004, we incurred $224 million in unrealized losses on energy derivatives ($27 million gain in the first quarter, $59 million loss in the second quarter, $54 million loss in the third quarter and $138 million loss in the fourth quarter).

Changes in net income (loss) from quarter to quarter were primarily due to:

•: seasonal fluctuations in demand for electric energy and energy services;
•: changes in energy commodity prices, including unrealized gains/losses on energy derivatives; and
•: timing of maintenance expenses.

In addition, net income (loss) changed from quarter to quarter in 2005 by (amounts are pre-tax unless indicated otherwise):

•: $359 million charge related to the Western states and Cornerstone settlements ($351 million in the third quarter and $8 million in the fourth quarter);
•: $239 million loss in discontinued operations related to the loss on disposition of our New York plants ($149 million loss in the third quarter and $90 million loss in the fourth quarter);

F-60

•: $160 million gain on sales of emission allowances ($93 million gain in the third quarter and $53 million gain in the fourth quarter);
•: $27 million loss in discontinued operations related to the loss on disposition of our Ceredo plant in the third quarter;
•: $25 million gain on the sale of El Dorado in the third quarter;
•: $23 million charge for the impairment of an investment in the second quarter;
•: $53 million decrease in income tax expense due to changes in valuation allowances and changes in estimates of deferred tax assets and liabilities ($6 million increase in the second quarter, $21 million decrease in the third quarter and $38 million decrease in the fourth quarter) (see note 10);
•: $12 million gain on the sale of the REMA hydropower plants in the second quarter; and
•: $8 million net charge related to the settlement of the shareholder class action lawsuits in the second quarter.

Also, net income (loss) changed from quarter to quarter in 2004 by (amounts are pre-tax unless indicated otherwise):

•: $208 million in income from discontinued operations due to gain on sale of hydropower plants in the third ($212 million in income) and fourth ($4 million in loss) quarters;
•: $77 million in income tax benefit from discontinued operations due to the utilization of previously reserved capital losses from the sale of our European energy operations as we incurred a net gain on the sale/transfer of our hydropower plants and Liberty ($103 million in tax benefit in the third quarter and $26 million in tax expense in the fourth quarter);
•: $70 million in loss from discontinued operations due to loss on transfer of Liberty in the fourth quarter;
•: $50 million write-off of deferred financing costs in the fourth quarter;
•: $30 million for the gain on sale of counterparty claim in the third quarter;
•: $16 million charge for equipment impairment related to turbines and generators in the first quarter;
•: $12 million charge related to adjustment to October 2003 FERC settlement recorded in the third quarter;
•: $12 million charge related to accelerated depreciation on retired generation assets in the first quarter; and
•: $5 million in income related to changes in our estimated refund obligation, credit reserve, receivables and interest receivable for energy sales in California ($22 million in income in the first quarter, $7 million in income in the second quarter, $6 million in income in the third quarter and $30 million in loss in the fourth quarter).

(17) Reportable Segments

We have two principal business segments:

•: Retail energy—provides electricity and energy services to approximately 1.9 million retail electricity customers in Texas, including residential and small business customers and large commercial, industrial and governmental/institutional customers. We also serve commercial, industrial and governmental/ institutional customers in the PJM market; and

F-61

•: Wholesale energy—provides electricity and energy services in the competitive wholesale energy markets in the United States. In this connection, we own and operate or contract for power generation capacity. As of December 31, 2005, we had approximately 15,956 MW of owned or leased generation capacity in operation.

We also have unallocated corporate functions and other investments.

Our segments are the strategic operating units under which we manage our business, including the allocation of resources and assessment of performance. We use contribution margin to evaluate our business segments because we use that measure in organizing and managing our business. Contribution margin is defined as total revenues less (a) purchased power, fuel and cost of gas sold, (b) operation and maintenance, (c) selling and marketing and (d) bad debt expense. We manage the costs not included in contribution margin (other general and administrative, depreciation, amortization, interest and income taxes) on a company-wide basis.

The accounting policies of our segments are described in note 2. We account for intersegment revenues at current market prices.

F-62

Financial data for our segments are as follows:

	Retail Energy		Wholesale Energy			Other Operations			Eliminations			Consolidated
	(in millions)
2005:
Revenues from external customers⁽¹⁾	$	7,045	$	2,661		$	6		$	—		$	9,712
Intersegment revenues		—		625			—			(625	)		—
Gross margin⁽²⁾⁽³⁾		683		656			7			—			1,346
Operation and maintenance expenses		190		544			3			—			737
Selling and marketing expenses		95		—			—			—			95
Bad debt expense		56		2			—			—			58
Contribution margin⁽³⁾		342		110			4			—			456
Expenditures for long-lived assets⁽⁴⁾		9		66			7			—			82
Equity investments as of December 31, 2005		—		30			—			—			30
Total assets of December 31, 2005		2,762		9,871			1,691	⁽⁵⁾		(755	)		13,569
2004:
Revenues from external customers⁽¹⁾	$	6,064	$	2,034	⁽⁶⁾	$	—		$	—		$	8,098
Intersegment revenues		—		340			—			(340	)		—
Gross margin⁽²⁾⁽⁷⁾		729		805			—			—			1,534
Operation and maintenance expenses		222		560			—			—			782
Selling and marketing expenses		82		—			—			—			82
Bad debt expense		48		(2	)		—			—			46
Contribution margin⁽⁷⁾		377		247			—			—			624
Expenditures for long-lived assets⁽⁴⁾		3		151			6			—			160
Equity investments as of December 31, 2004		—		84			—			—			84
Total assets as of December 31, 2004		1,391		9,759			1,546	⁽⁵⁾		(502	)		12,194
2003:
Revenues from external customers⁽¹⁾	$	5,729	$	4,367	⁽⁸⁾	$	1		$	—		$	10,097
Intersegment revenues		—		225			—			(225	)		—
Gross margin⁽²⁾⁽⁹⁾		1,253		931			1			—			2,185
Operation and maintenance expenses		251		558			—			—			809
Selling and marketing expenses		98		—			—			—			98
Bad debt expense		65		(8	)		—			—			57
Contribution margin⁽⁹⁾		839		381			1			—			1,221
Expenditures for long-lived assets⁽⁴⁾		23		482			43			—			548
Equity investments as of December 31, 2003		—		95			—			—			95
Total assets as of December 31, 2003		1,156		9,480			2,837	⁽⁵⁾		(176	)		13,297

(1): Substantially all revenues are in the United States.
(2): Revenues less purchased power, fuel and cost of gas sold.
(3): Includes $(69) million, $(123) million and $(192) million in retail energy, wholesale energy and consolidated, respectively, results relating to unrealized gains (losses) on energy derivatives, which is a non-cash item.
(4): Long-lived assets include net property, plant and equipment, net goodwill, net other intangibles and equity investments. All of our long-lived assets are in the United States.
(5): Other operations include discontinued operations of $1,084 million, $1,137 million and $2,284 million as of December 31, 2005, 2004 and 2003, respectively.

F-63

(6): Includes $792 million in revenues from a single counterparty, which represented 10% of our consolidated revenues and 39% of our wholesale energy segment's revenues. As of December 31, 2004, no amounts were outstanding from this counterparty.
(7): Includes $(272) million, $48 million and $(224) million in retail energy, wholesale energy and consolidated, respectively, results relating to unrealized gains (losses) on energy derivatives, which is a non-cash item.
(8): Includes $1.1 billion in revenues from a single counterparty, which represented 11% of our consolidated revenues and 25% of our wholesale energy segment's revenues. As of December 31, 2003, no amounts were outstanding from this counterparty.
(9): Includes $(7) million, $(41) million and $(48) million in retail energy, wholesale energy and consolidated, respectively, results relating to unrealized gains (losses) on energy derivatives, which is a non-cash item.

			2005			2004			2003
			(in millions)
Reconciliation of Contribution Margin to Operating Loss and Operating Loss to Net Loss:
	Contribution margin		$	456		$	624		$	1,221
	Other general and administrative			140			198			273
	Western states and Cornerstone settlements			359			—			—
	Loss on sales of receivables			—			34			37
	Accrual for payment to CenterPoint			—			2			47
	Gain on sale of counterparty claim			—			(30	)		—
	Gains on sales of assets and emission allowances, net			(168	)		(20	)		(3	)
	Wholesale energy goodwill impairment			—			—			985
	Depreciation and amortization			446			453			358

	Operating loss			(321	)		(13	)		(476	)
	Income (loss) of equity investments, net			26			(9	)		(2	)
	Other, net			(23	)		13			9
	Interest expense			(399	)		(418	)		(407	)
	Interest income			23			35			35

	Loss from continuing operations before income taxes			(694	)		(392	)		(841	)
	Income tax expense (benefit)			(253	)		(116	)		75

	Loss from continuing operations			(441	)		(276	)		(916	)
	Income (loss) from discontinued operations			111			240			(402	)

	Loss before cumulative effect of accounting changes			(330	)		(36	)		(1,318	)
	Cumulative effect of accounting changes, net of tax			(1	)		7			(24	)

		Net loss	$	(331	)	$	(29	)	$	(1,342	)

(18) Impairment of Cost Method Investment

During the second quarter of 2005, we recorded a non-cash charge of $23 million (recorded in other, net) for the impairment of our investment in a communications services company. The impairment charge was based on an internal valuation of projected future cash flows and earnings conducted in connection with the preparation of our interim financial statements. As of December 31, 2005, our remaining non-energy investments have a net book value of $5 million and are included in other long-term assets.

(19) Sales of Assets and Emission Allowances

We included the following assets (all from our wholesale energy segment) in our results of operations through the date of sale.

REMA Hydropower Plants. Two hydropower plants sold for $42 million in April 2005.

F-64

Landfill-gas Fueled Power Plants. Our landfill-gas fueled power plants sold for $28 million in July 2005.

El Dorado Investment. Our 50% interest in El Dorado Energy, LLC sold for $132 million in July 2005 and we received $76 million after adjustment for net project debt. We recognized a gain on the disposal of $25 million (recorded in income of equity investments, net) during the third quarter of 2005.

Emission Allowances. The sales and purchases of emission allowances are classified as investing activities in the consolidated statements of cash flows. We reclassified net purchases of $65 million and $62 million for 2004 and 2003, respectively, from operating to investing cash flows. Net sales proceeds from emission allowances:

	2005			2004		2003
	(in millions)
SO₂	$	206	⁽¹⁾	$	40	$	11
NO_x		28	⁽²⁾		20		3

	$	234		$	60	$	14

(1): Sold 242,000 tons relating to 2005 through 2009 vintage years.
(2): Sold 9,000 tons relating to 2005 through 2007 vintage years.

During January and February 2006, we sold 132,000 tons of emission allowances relating to 2006 through 2009 vintage years for $166 million and recognized a gain of $140 million.

Summary of Gains and Losses.

		2005			2004		2003
		(in millions)
REMA hydropower plants		$	12		$	—	$	—
Landfill-gas fueled power plants			(4	)		—		—
Emission allowances⁽¹⁾			160			19		1
Other, net			—			1		2

	Gains on sales of assets and emission allowances, net	$	168		$	20	$	3

(1): For 2004 and 2003, these amounts were previously classified in amortization expense; however, we reclassified them to gains on sales of assets and emission allowances, net.

(20) Discontinued Operations

(a) New York Plants.

General. On February 23, 2006, we closed on the sale of our three remaining New York plants with an aggregate net generating capacity of approximately 2,100 MW for $979 million. During the third quarter of 2005, we began to report the results of the New York plants as discontinued operations. These plants were a part of our wholesale energy segment.

Use of Proceeds. We applied $704 million of cash proceeds, which is net of estimated city, state and transfer taxes and transaction costs, to pay down our senior secured term loans. The remaining net cash proceeds of $249 million are currently subject to an asset sale offer to holders of the Orion Power Holdings senior notes, which expires on March 24, 2006. We do not expect the Orion Power Holdings

F-65

bondholders to accept the offer. Upon expiration of the offer and to the extent permitted under the terms of the Orion Power Holdings senior notes, we plan to apply the remaining net cash proceeds to pay down our senior secured term loans. Under the terms of certain debt agreements at the time we signed the purchase and sale agreement, we were required to apply all net cash proceeds from the sale, excluding $300 million, to pay off debt. Under these provisions, we estimated that we would be required to pay down our senior secured term loans due 2010 by approximately $638 million when the sale of the New York plants closed.

Assumptions Related to Debt, Deferred Financing Costs and Interest Expense on Discontinued Operations. Based on our contractual obligation (at the time the purchase and sale agreement was executed) to utilize a portion of the net proceeds from the sale to prepay debt, we have classified $638 million of debt as discontinued operations as of December 31, 2005 and 2004. See note 6. We have also classified as discontinued operations the related deferred financing costs and interest expense on this debt. We allocated $39 million, $50 million and $32 million of related interest expense during 2005, 2004 and 2003, respectively, to discontinued operations.

(b) Ceredo Plant.

In 2005, we sold our 505 MW Ceredo power plant for $100 million. We used the net cash proceeds of $100 million to pay down a portion of our senior secured term loans. During the third quarter of 2005, we began to report results of Ceredo's operations as discontinued operations effective January 1, 2005. The plant was a part of our wholesale energy segment.

(c) Liberty.

In 2004, we transferred our ownership interests in Liberty, including its non-recourse debt, to Liberty's lenders. Liberty owned a 530 MW power generation facility and had been in default under its credit agreement. The plant was a part of our wholesale energy segment. We have reported the results of our Liberty operations as discontinued operations since the fourth quarter of 2004. We did not provide or receive any cash consideration in connection with the transfer to Liberty's lenders. We allocated $21 million and $19 million of related interest expense during 2004 and 2003, respectively, to discontinued operations.

(d) Orion Power Hydropower Plants.

In 2004, we sold 71 hydropower plants and a gas-fired generation plant with a total aggregate net generating capacity of 770 MW for $870 million. The plants were a part of our wholesale energy segment. We have reported the results of our Hydropower plant operations as discontinued operations since the second quarter of 2004. Our estimated net proceeds after transaction and related costs were $804 million. We used the net proceeds from the sale to repay debt, pay taxes and settle an interest rate swap termination.

Pursuant to the terms of certain credit agreements to apply all net cash proceeds from the sale to pay off indebtedness (including swap obligations), we have reported the debt repaid through the sale, related interest rate swaps and related deferred financing costs, including associated interest, as discontinued operations. We allocated $47 million and $43 million of related interest expense during 2004 and 2003, respectively, to discontinued operations.

(e) Desert Basin.

In 2003, we sold our 588 MW Desert Basin plant. These operations were a part of our wholesale energy segment. We have reported the results of our Desert Basin plant operations as discontinued operations since the third quarter of 2003. We used the net proceeds from the sale of $285 million to prepay indebtedness under our March 2003 credit facilities.

F-66

(f) European Energy.

In 2003, we sold our European energy operations, which formerly were a reportable segment. We have reported the results of our European energy operations as discontinued operations since the first quarter of 2003.

We received net cash proceeds of $1.4 billion. We used these net proceeds (a) to prepay the Euro 600 million bank term loan borrowed to finance a portion of the original acquisition costs and (b) to prepay $567 million of debt under our credit facilities from March 2003. We allocated $48 million of related interest expense during 2003 to discontinued operations.

In addition to the initial cash proceeds, we are entitled to receive 90% of any cash distributions in excess of Euro 110 million received by the purchaser from the former coordinating body for the Dutch electricity sector as contingent consideration for the sale. We received payments of $52 million and $8 million during 2005 and 2004, respectively.

(g) All Discontinued Operations.

The following summarizes certain financial information of the businesses reported as discontinued operations:

	New York Plants			Ceredo Plant⁽¹⁾			Liberty			Orion Power Hydropower Plants			Desert Basin			European Energy			Total
2005
Revenues	$	996		$	—		$	—		$	—		$	—		$	—		$	996
Income (loss) before income tax expense/benefit		18	⁽²⁾		(27	)⁽³⁾		—			—			—			52			43
2004
Revenues	$	633			N/A		$	86		$	95		$	—		$	—		$	814
Income (loss) before income tax expense/benefit		123			N/A			(98	)⁽⁴⁾		187	⁽⁵⁾		—			9			221
2003
Revenues	$	489			N/A		$	37		$	118		$	49		$	658		$	1,351
Income (loss) before income tax expense/benefit		50			N/A			(24	)		(7	)		(57	)⁽⁶⁾		(253	)⁽⁷⁾		(291	)

(1): Prior to January 1, 2005, Ceredo did not qualify for discontinued operations.
(2): Includes $239 million estimated loss on disposal.
(3): Includes $27 million loss on disposal.
(4): Includes $70 million loss on disposal.
(5): Includes $208 million gain on disposal.
(6): Includes $84 million loss on disposal.
(7): Includes $310 million loss on disposal.

F-67

The following summarizes the assets and liabilities related to New York discontinued operations:

				December 31,
				2005		2004
				(in millions)
Current Assets:
	Accounts receivable, net			$	51	$	46
	Derivative assets				87		6
	Other current assets				65		52

		Total current assets			203		104
Property, Plant and Equipment, net					761		952
Other Assets:
	Other intangibles, net				69		71
	Derivative assets				43		—
	Other				8		10

		Total long-term assets			881		1,033

			Total Assets	$	1,084	$	1,137

Current Liabilities:
	Accounts payable, principally trade			$	30	$	16
	Derivative liabilities				50		7
	Other current liabilities				16		6

		Total current liabilities			96		29
Other Liabilities:
	Accumulated deferred income taxes				120		185
	Other liabilities				22		19

		Total other liabilities			142		204
Long-term Debt					638		638

	Total long-term liabilities				780		842

		Total Liabilities			876		871

Accumulated other comprehensive loss				$	—	$	(4	)

F-68

RELIANT ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II—RESERVES
For the Years Ended December 31, 2005, 2004 and 2003
(Thousands of Dollars)

Column A	Column B		Column C					Column D			Column E
			Additions
Description	Balance at Beginning of Period		Charged to Income			Charged to Other Accounts⁽¹⁾		Deductions from Reserves⁽²⁾			Balance at End of Period
2005
Allowance for doubtful accounts	$	41,636	$	57,817		$	—	$	(65,399	)	$	34,054
Reserves deducted from derivative assets		87,323		128,306			33		(18,278	)		197,384
Reserves for severance		1,325		8,664			—		(8,129	)		1,860
2004
Allowance for doubtful accounts		46,184		45,707			—		(50,255	)		41,636
Reserves deducted from derivative assets		16,273		52,110			19,948		(1,008	)		87,323
Reserves for accrue-in-advance major maintenance		9,647		(9,647	)⁽³⁾		—		—			—
Reserves for severance		4,592		30,618			—		(33,885	)		1,325
2003
Allowance for doubtful accounts		61,421		57,378			—		(72,615	)		46,184
Reserves deducted from derivative assets		67,452		(31,257	)		—		(19,922	)		16,273
Reserves for accrue-in-advance major maintenance		6,735		2,912			—		—			9,647
Reserves for severance		5,979		31,377			—		(32,764	)		4,592

(1): Represents charges to accumulated other comprehensive income/loss.
(2): Deductions from reserves represent losses or expenses for which the respective reserves were created. In the case of the allowance for doubtful accounts, such deductions are net of recoveries of amounts previously written off.
(3): See note 2(r) to our consolidated financial statements.

F-69

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Reliant Energy, Inc., Sole Member of Reliant Energy Retail Holdings, LLC
Houston, Texas

We have audited the accompanying consolidated balance sheets of Reliant Energy Retail Holdings, LLC and subsidiaries (the "Company"), as of December 31, 2005 and 2004, and the related consolidated statements of operations, member's equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Reliant Energy Retail Holdings, LLC and subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in note 2 to the consolidated financial statements, the Company changed its accounting for energy trading contracts and its presentation of revenues and costs of sales associated with non-trading commodity derivative activities in 2003.

DELOITTE & TOUCHE LLP

Houston, Texas
March 14, 2006

F-70

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Thousands of Dollars)

			2005			2004			2003
Revenues:
	Electricity sales and services revenues		$	5,997,644		$	5,820,647		$	5,105,240

Expenses:
	Purchased power			621,075			3,399,267			3,368,772
	Purchased power—affiliates			4,629,342			1,392,472			522,227
	Operation and maintenance			175,382			205,387			243,692
	Operation and maintenance—affiliates			17,401			12,834			8,266
	Selling, general and administrative			153,792			138,279			175,987
	Selling, general and administrative—affiliates			49,568			85,557			86,833
	Loss on sales of receivables			—			33,741			37,613
	Accrual for payment to CenterPoint Energy, Inc.			—			1,600			46,700
	Loss on sale of assets			4,329			—			—
	Depreciation and amortization			48,656			43,894			35,911

		Total operating expense		5,699,545			5,313,031			4,526,001

Operating Income				298,099			507,616			579,239

Other Income (Expense):
	Other, net			275			309			103
	Interest expense			(19,196	)		(10,070	)		(6,009	)
	Interest income			300			12,298			12,555
	Interest income, net—affiliates			102,244			83,040			17,869

		Total other income		83,623			85,577			24,518

Income Before Income Taxes				381,722			593,193			603,757
	Income tax expense			148,824			221,279			231,556

Income Before Cumulative Effect of Accounting Change				232,898			371,914			372,201
	Cumulative effect of accounting change, net of tax			—			—			5,832

Net Income			$	232,898		$	371,914		$	378,033

See Notes to the Consolidated Financial Statements

F-71

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)

			December 31,
			2005		2004
ASSETS
Current Assets:
	Cash and cash equivalents		$	8,722	$	7,962
	Accounts and notes receivable and unbilled revenue, principally customer, net of allowance of $29,556 and $36,522			852,686		663,079
	Margin deposits on energy trading and hedging activities			250		16,950
	Accumulated deferred income taxes			9,882		19,491
	Prepayments and other current assets			17,171		77,975

		Total current assets		888,711		785,457

Property, Plant and Equipment, net				73,468		142,073

Other Assets:
	Goodwill			31,631		31,631
	Other intangibles, net			203		1,907
	Derivative assets			—		87,402
	Notes receivable—affiliate			1,893,828		1,280,445
	Other			1,492		1,278

		Total other assets		1,927,154		1,402,663

Total Assets			$	2,889,333	$	2,330,193

LIABILITIES AND MEMBER'S EQUITY
Current Liabilities:
	Short-term borrowings		$	450,000	$	227,000
	Accounts payable, principally trade			125,036		209,777
	Accounts payable—affiliates			491,683		94,918
	Retail customer deposits			62,450		62,287
	State income taxes payable			16,850		15,880
	Other taxes payable			42,121		36,794
	Accrual for transmission and distribution charges			44,310		57,561
	Other			20,247		20,964

		Total current liabilities		1,252,697		725,181

Other Liabilities:
	Accumulated deferred income taxes			24,023		50,770
	Derivative liabilities			—		39,520
	Other			15,919		11,014

		Total other liabilities		39,942		101,304

Commitments and Contingencies
Member's Equity:
	Other member's equity			1,596,694		1,503,710
	Accumulated other comprehensive loss			—		(2	)

		Total member's equity		1,596,694		1,503,708

Total Liabilities and Member's Equity			$	2,889,333	$	2,330,193

See Notes to the Consolidated Financial Statements

F-72

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

					2005			2004			2003
Cash Flows from Operating Activities:
	Net income				$	232,898		$	371,914		$	378,033
	Adjustments to reconcile net income to net cash provided by operating activities:
		Cumulative effect of accounting change				—			—			(5,832	)
		Depreciation and amortization				48,656			43,894			35,911
		Deferred income taxes				(6,203	)		80,723			(49,295	)
		Federal income tax contributions from Reliant Energy, Inc., net				136,564			130,450			242,678
		Net unrealized (gains) losses on energy derivatives				—			(20,335	)		45,675
		Accrual for payment to CenterPoint Energy, Inc.				—			1,600			46,700
		Loss on sale of assets				4,329			—			—
		Other, net				—			—			4,077
		Changes in other assets and liabilities:
			Accounts and notes receivable and unbilled revenue, net			(201,964	)		(44,331	)		(28,147	)
			Receivables facility proceeds, net			—			232,000			23,000
			Accounts receivable/payable—affiliates			122,966			77,201			67,812
			Margin deposits on energy trading and hedging activities, net			—			(4,700	)		(12,250	)
			Net derivative assets and liabilities			350			13,576			63,480
			Accounts payable			14,123			35,533			27,553
			Other current assets			2,564			(29,561	)		(17,232	)
			Other current liabilities			5,384			(22,518	)		15,393
			Other assets			654			1,364			907
			Retail customer deposits			163			5,118			5,419
			State income taxes payable			4,244			(25,178	)		10,737
			Other taxes payable			5,327			4,480			1,201
			Payment to CenterPoint Energy, Inc.			—			(176,600	)		—
			Accrual for transmission and distribution charges			317			4,578			(8,623	)
			Other liabilities			2,707			5,344			(2,125	)

				Net cash provided by operating activities		373,079			684,552			845,072

Cash Flows from Investing Activities:
	Capital expenditures					(9,239	)		(5,371	)		(34,136	)
	Proceeds from sale of assets, net					27,303			—			—

				Net cash provided by (used in) investing activities		18,064			(5,371	)		(34,136	)

Cash Flows from Financing Activities:
	Payments of long-term debt					—			(1,721	)		(4,981	)
	Increase (decrease) in short-term borrowings, net					223,000			(123,000	)		—
	Changes in notes with Reliant Energy, Inc., net					(613,383	)		(556,354	)		(1,182,918	)

				Net cash used in financing activities		(390,383	)		(681,075	)		(1,187,899	)
Net Change in Cash and Cash Equivalents						760			(1,894	)		(376,963	)
Cash and Cash Equivalents at Beginning of Period						7,962			9,856			386,819

Cash and Cash Equivalents at End of Period					$	8,722		$	7,962		$	9,856

Supplemental Disclosure of Cash Flow Information:
	Cash Payments:
		Interest paid to affiliate			$	6,920		$	5		$	4,403
		Interest paid (net of amounts capitalized) to third party				19,355			9,853			4,392
		Income taxes paid (net of income tax refunds received)				14,096			35,282			21,898
	Non-cash Disclosure:
		Contributions from Reliant Energy, Inc., net				133,564			130,450			286,244
		Transfer of Reliant Energy Electric Solutions, LLC to Reliant Energy, Inc.				(273,476	)		—			—

See Notes to the Consolidated Financial Statements

F-73

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER'S EQUITY AND COMPREHENSIVE INCOME

(Thousands of Dollars)

		Other Member's Equity			Accumulated Other Comprehensive Income (Loss)			Total Member's Equity			Comprehensive Income
Balance at December 31, 2002		$	337,069		$	—		$	337,069
Net income			378,033						378,033		$	378,033
Contributions from member			286,244						286,244
Other comprehensive income (loss):
Deferred gain from cash flow hedges, net of tax of $19 million						30,018			30,018			30,018
Reclassification of net deferred gain from cash flow hedges into net income, net of tax of $13 million						(20,782	)		(20,782	)		(20,782	)

	Comprehensive income										$	387,269

Balance at December 31, 2003			1,001,346			9,236			1,010,582
Net income			371,914						371,914		$	371,914
Contributions from member			130,450						130,450
Other comprehensive income (loss):
Deferred gain from cash flow hedges, net of tax of $5 million						7,616			7,616			7,616
Reclassification of net deferred gain from cash flow hedges into net income, net of tax of $10 million						(16,854	)		(16,854	)		(16,854	)

	Comprehensive income										$	362,676

Balance at December 31, 2004			1,503,710			(2	)		1,503,708
Net income			232,898						232,898			232,898
Contributions from member			133,564						133,564
Transfer of Reliant Energy Electric Solutions, LLC to Reliant Energy, Inc.			(273,478	)		2			(273,476	)

	Comprehensive income										$	232,898

Balance at December 31, 2005		$	1,596,694		$	—		$	1,596,694

See Notes to the Consolidated Financial Statements

F-74

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Background and Basis of Presentation

Background. "RERH LLC" refers to Reliant Energy Retail Holdings, LLC, a Delaware limited liability company. "RERH" refers to Reliant Energy Retail Holdings, LLC and its consolidated subsidiaries. "Reliant Energy" refers to Reliant Energy, Inc. and its consolidated subsidiaries. RERH LLC is a wholly-owned subsidiary of Reliant Energy and was formed in September 2000. Reliant Energy is the sole member and holds all 1,000 shares of RERH LLC.

RERH provides electricity products and related services to end-use customers ranging from residential and small business customers to large commercial, industrial and governmental/institutional customers. During 2003, RERH began providing retail energy products and services to commercial, industrial and governmental/institutional customers in New Jersey and Maryland. During 2004, RERH began marketing retail energy to this same class of customers in other areas of the wholesale and retail electric market operated by PJM Interconnection, LLC (PJM), primarily in the District of Columbia and Pennsylvania.

As of December 31, 2005, RERH's subsidiaries include:

Subsidiary		Formation Date
Reliant Energy Retail Services, LLC (Retail Services)		September 2000
Reliant Energy Solutions East, LLC (Solutions East)		February 2002
RE Retail Receivables, LLC		June 2002

In January 2003, RERH purchased all the outstanding common stock in Reliant Energy Renewables, Inc. (Renewables) from Reliant Energy Power Generation, Inc., an affiliated company and a subsidiary of Reliant Energy for approximately $27,000 and assumed all notes payable to affiliated companies. The purchase price was based on Renewables' book value. The acquisition was treated as a reorganization of entities under common control. In July 2005, RERH sold the common stock and all related assets and liabilities of Renewables. See note 11.

Effective September 28, 2004, RERH consolidated RE Retail Receivables, LLC (see note 5). Effective January 1, 2005, Reliant Energy Solutions, LLC was merged into Retail Services and RERH transferred its interest in Reliant Energy Electric Solutions, LLC (REES) to Reliant Energy.

F-75

Assets and liabilities related to REES were as follows as of December 31, 2004 (in millions):

Current Assets:
	Accounts receivable, net			$	12
	Accounts and notes receivable, net—RERH affiliated companies				373
	Derivative assets				1
	Other current assets				73

		Total current assets			459

Other Assets:
	Derivative assets				87
	Other				2

		Total long-term assets			89

			Total Assets	$	548

Current Liabilities:
	Accounts payable, principally trade			$	99
	Accounts payable, net—non-RERH affiliated companies				99
	Derivative liabilities				5
	Other current liabilities				14

		Total current liabilities			217

Other Liabilities:
	Derivative liabilities				40
	Other liabilities				18

		Total long-term liabilities			58

			Total Liabilities	$	275

	Net Investment			$	273

Revenues and pre-tax income related to REES were as follows:

	2004		2003
	(in millions)
Income before income taxes⁽¹⁾	$	82	$	68
Income before cumulative effect of accounting changes⁽¹⁾		51		44
Net income⁽¹⁾		51		50

(1): A significant portion of the results of operations were energy supply management activities related to the intercompany activities between REES and certain of RERH's wholly-owned subsidiaries, with the remainder being contracts with the General Land Office.

Basis of Presentation. These consolidated statements include all revenues and costs directly attributable to RERH including costs for facilities and costs for functions and services performed by Reliant Energy and charged to RERH. All significant intercompany transactions have been eliminated. RERH has reclassified certain immaterial amounts from prior periods to conform to the 2005 presentation. These reclassifications had no impact on reported earnings/losses.

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(2) Summary of Significant Accounting Policies

(a) Use of Estimates and Market Risk and Uncertainties.

Management makes estimates and assumptions to prepare financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) that affect:

•: the reported amount of assets and liabilities,
•: the reported amounts of revenues and expenses and
•: our disclosure of contingent assets and liabilities at the date of the financial statements.

RERH's critical accounting estimates include: (a) derivative assets and liabilities (prior to 2005); (b) estimated revenues and energy supply costs; and (c) deferred tax assets, valuation allowances and tax liabilities. Actual results could differ from the estimates.

RERH is subject to various risks inherent in doing business. See notes 2(c), 2(d), 2(e), 4, 5, 6, 7, 8 and 9.

(b) Principles of Consolidation.

RERH LLC includes the accounts and those of its wholly-owned and majority-owned subsidiaries in its consolidated financial statements. Since September 28, 2004, RERH has consolidated its receivables facility arrangement (see note 5).

(c) Revenues.

Retail Revenues. Gross revenues for energy sales and services to residential and small business customers and electric sales to large commercial, industrial and governmental/institutional customers under contracts executed after October 2002 are recognized upon delivery and include estimated energy and services delivered but not billed by the end of the period. Electric sales to large commercial, industrial and governmental/institutional customers under contracts executed before October 2002 were accounted for under the mark-to-market method of accounting upon contract execution. The change in accounting for some of the contracted sales to large commercial, industrial and governmental/institutional customers during 2002 was due to Emerging Issues Task Force (EITF) No. 02-03.

RERH recorded a cumulative effect of a change in accounting principle of $6 million gain, net of tax of $4 million, effective January 1, 2003, related to EITF No. 02-03. The cumulative effect reflects the fair value, as of January 1, 2003, of contracts executed prior to October 25, 2002 that had been marked to market under EITF No. 98-10 that did not meet the definition of a derivative.

As of December 31, 2005 and 2004, RERH recorded unbilled revenues of $363 million and $328 million, respectively, for retail energy sales. Accrued unbilled revenues are based on RERH's estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes, estimated customer usage by class and applicable customer rates. Unbilled revenues are calculated by multiplying volume estimates by estimated rates by customer class. Estimated amounts are adjusted when actual usage and rates are known and billed.

Changes in Estimates. The revenues and the related energy supply costs include estimates of customer usage after consideration of initial usage information provided by the independent system operators and the distribution companies. RERH revises these estimates and records any changes in

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the period as information becomes available (collectively referred to as "market usage adjustments"). During 2005, 2004 and 2003, RERH recognized in gross margin (revenues less purchased power) $13 million of expense, $18 million of expense and $28 million of income, respectively, related to market usage adjustments.

(d) Derivatives and Hedging Activities.

RERH accounts for its derivatives instruments and hedging activities in accordance with SFAS No. 133, "Accounting for Derivatives Instruments and Hedging Activities," as amended (SFAS No. 133)

Prior to RERH transferring its interest in REES to Reliant Energy, for hedging activities, RERH used both derivative and non-derivative contracts that provided for settlement in cash or by delivery of a commodity. The primary types of derivative instruments used were forwards, futures, swaps and options. RERH elected one of three accounting methods (cash flow hedge, mark-to-market or accrual accounting) for derivatives based on facts and circumstances. The fair values of derivative activities were determined by (a) prices actively quoted, (b) prices provided by other external sources or (c) prices based on models and other valuation methods.

If certain conditions are met, a derivative instrument may be designated as a cash flow hedge. A derivative is recognized at fair value in the balance sheet whether or not it is designated as a hedge, except for derivative contracts designated as "normal purchases and sales exceptions," which are not in its consolidated balance sheet or results of operations prior to settlement. As of December 31, 2005, RERH did not have any derivatives designated as cash flow hedges.

Derivatives designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. The changes in fair value of cash flow hedges were deferred in accumulated other comprehensive income (loss), net of tax, to the extent the contracts were effective as hedges, until the forecasted transactions affected earnings. At the time the forecasted transactions affected earnings, RERH reclassified the amounts in other comprehensive income (loss) into earnings. RERH recorded the ineffective portion of changes in fair value of cash flow hedges immediately into earnings. For all other derivatives, changes in fair value were recorded as unrealized gains or losses in its results of operations.

If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in its results of operations. If it becomes probable that a forecasted transaction will not occur, RERH immediately recognizes the related deferred gains or losses in its results of operations. The associated hedging instrument is then marked to market through its results of operations for the remainder of the contract term unless a new hedging relationship is redesignated.

Prior to October 1, 2003, RERH generally recorded, on a gross basis in the period of delivery (a) sales in revenues and (b) purchases in purchased power. In July 2003, the EITF issued EITF No. 03-11, which states that realized gains and losses on derivatives contracts not "held for trading purposes" should be reported either on a net or gross basis based on the relevant facts and circumstances. EITF No. 03-11 has no impact on margins or net income. Subsequent to October 1, 2003, due to the adoption of EITF No. 03-11, hedging transactions that do not physically flow are

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included in the same caption as the items being hedged. A summary of RERH's derivative activities and classification in its results of operations is:

Instrument		Purpose for Holding or Issuing Instrument⁽¹⁾		Transactions that Physically Flow		Transactions that Financially Settle⁽²⁾
Power futures, forward, swap and option contracts		Power sales to end-use retail customers Supply management revenues Power purchases		Revenues Revenues Purchased power		N/A Purchased power Purchased power
Natural gas and fuel futures, forward, swap and option contracts		Natural gas and fuel purchases/sales		N/A		Purchased power

(1): The purpose for holding or issuing is not impacted by the accounting method elected for each instrument.
(2): Includes classification for mark-to-market derivatives and amounts reclassified from accumulated other comprehensive income (loss) related to cash flow hedges.

In addition to market risk, RERH is exposed to credit and operational risk. Reliant Energy has a control framework, to which RERH is subject, to manage these risks, which include: (a) measuring and monitoring these risks, (b) review and approval of new transactions relative to these risks, (c) transaction validation and (d) portfolio valuation and reporting. RERH uses mark-to-market valuation, value-at-risk and other metrics in monitoring and measuring risk. Reliant Energy's risk control framework includes a variety of separate but complementary processes, which involve commercial and senior management and Reliant Energy's Board of Directors. See note 2(e) for further discussion of RERH's credit policy.

Set-off of Derivative Assets and Liabilities. Where derivative instruments are subject to a master netting agreement and the accounting criteria to net are met, RERH presents its derivative assets and liabilities on a net basis. Derivative assets/liabilities and accounts receivable/payable are presented and set-off separately in the consolidated balance sheets although in most cases contracts permit the set-off of derivative assets/liabilities and accounts receivable/payable with a given counterparty.

(e) Credit Risk.

RERH has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transition approvals. Credit risk is monitored and the financial condition of RERH's counterparties are reviewed periodically. RERH tries to mitigate credit risk by entering into contracts that permit netting and allow RERH to terminate upon the occurrence of certain events of default. RERH measures credit risk as the replacement cost for its derivative positions (through December 31, 2004) plus amounts owed for settled transactions.

As of December 31, 2004, one non-investment grade counterparty represented 90% ($107 million) of RERH's credit exposure, net of collateral, primarily related to its derivative assets and Electric Reliability Council of Texas (ERCOT) power supply counterparties. RERH did not have any credit exposure from this one counterparty as of December 31, 2005 as the transactions were with REES, which is no longer a subsidiary of RERH. REES has net credit exposure of $708 million as of December 31, 2005 to this non-investment grade counterparty. If the counterparty defaulted, RERH would experience increased purchased power costs going forward. There were no other counterparties representing greater than 10% of RERH's credit exposure, net of collateral.

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(f) Selling, General and Administrative Expenses.

(g) Severance Costs.

During 2005, 2004 and 2003, RERH incurred $2 million, $8 million and $3 million, respectively, in severance costs (included in both operation and maintenance and selling, general and administrative expenses), which were substantially paid in each applicable period.

(h) Property, Plant and Equipment and Depreciation Expense.

RERH computes depreciation using the straight-line method based on estimated useful lives. Depreciation expense was $48 million, $43 million and $35 million during 2005, 2004 and 2003, respectively.

			December 31,
		Estimated Useful Lives (Years)	December 31,
		Estimated Useful Lives (Years)	2005			2004
			(in millions)
Information technology		3-10	$	174		$	190
Generation facilities		20		—			31
Furniture and leasehold improvements		3-10		9			14
Assets under construction				5			3

	Total			188			238
Accumulated depreciation				(115	)		(96	)

	Property, plant and equipment, net		$	73		$	142

RERH periodically evaluates property, plant and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. RERH recorded no material property, plant and equipment impairments during 2005, 2004 and 2003.

(i) Intangible Assets and Amortization Expense.

Goodwill. RERH performs its goodwill impairment test annually and when events or changes in circumstances indicate that the carrying value may not be recoverable. RERH previously selected November 1 as its annual goodwill impairment testing date since Reliant Energy had historically completed its annual strategic planning process by that date. Reliant Energy has since modified its strategic planning process, which provides key information used in the analysis of RERH's goodwill impairment test, and such information is no longer completed by November 1. In order to align RERH's annual goodwill impairment test with Reliant Energy's annual strategic planning process, to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in 2005, RERH changed the date on which it performs the annual goodwill impairment test to April 1. The change is not intended to delay, accelerate or avoid an impairment charge. RERH believes that this accounting change is to an alternative accounting principle that is preferable under the circumstances.

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Other Intangibles. RERH recognizes specifically identifiable intangible assets, including emission allowances, demand side management contracts and permanent seat licenses, when specific rights and contracts are acquired. RERH has no intangible assets with indefinite lives recorded as of December 31, 2005 and 2004.

(j) Stock-based Compensation.

RERH applies the intrinsic value method of accounting for employee stock-based compensation and expenses it ratably over the vesting period. On January 1, 2006, RERH began to recognize compensation cost for the unvested portion of pre-January 2006 awards and awards granted from that date based on the grant-date fair value of those awards. RERH expects the adoption of the fair value based method of accounting will not have a material impact on its financial position or results of operations. Under the intrinsic value method, RERH adjusts compensation cost for performance-based stock awards and options based on changes in Reliant Energy's stock price; however, under the fair value based method, RERH recognizes compensation cost based on grant date fair value recognized over the service period. Under the intrinsic value method, RERH does not recognize compensation cost for time-based stock options or Reliant Energy's employee stock purchase plan; however, under the fair value based method, RERH recognizes compensation cost. The fair value based method of accounting does not change RERH's compensation cost for time-based restricted stock awards or performance-based cash awards.

Using the Black-Scholes model for determining fair values, RERH's pro forma results are:

	2005			2004			2003
	(in millions)
Net income, as reported	$	233		$	372		$	378
Add: Stock-based compensation expense included in reported net income, net of tax		—			3			1
Deduct: Stock-based compensation expense determined under fair value based method for all awards, net of tax		(2	)		(4	)		(7	)

Pro forma net income	$	231		$	371		$	372

RERH uses the Black-Scholes option-pricing model with the following weighted average assumptions and resulting fair values.

	Reliant Energy Stock Options									Reliant Energy Employee Stock Purchase Plan Rights
	2005			2004			2003			2005			2004			2003
Expected life in years		5			5			5			0.5			0.5			0.5
Estimated volatility⁽¹⁾		45.75	%		72.85	%		113.64	%		32.97	%		41.18	%		110.73	%
Risk-free interest rate		4.18	%		3.01	%		2.75	%		2.94	%		1.21	%		1.18	%
Dividend yield		0	%		0	%		0	%		0	%		0	%		0	%
Weighted-average fair value	$	5.72		$	5.00		$	3.10		$	3.25		$	2.29		$	1.80

(1): For 2005 and 2004 options, RERH estimated volatility based on an equal weighting of historical and implied volatility of Reliant Energy's common stock. For employee stock purchase plan rights and 2003 options, RERH estimated volatility based on the historical volatility of Reliant Energy's common stock.

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(k) Income Taxes.

RERH is included in the consolidated income tax returns of Reliant Energy and calculates its income tax provision on a separate return basis, whereby Reliant Energy pays all federal income taxes on RERH's behalf and is entitled to any related tax savings. The difference between RERH's current federal income tax expense or benefit, as calculated on a separate return basis, and related amounts paid or received to/from Reliant Energy, if any, are recorded in RERH's financial statements as adjustments to member's equity on its consolidated balance sheets. Deferred income taxes reflected on RERH's consolidated balance sheet will ultimately be settled with Reliant Energy through member's equity. See notes 3 and 7.

(l) Cash and Cash Equivalents.

RERH records all highly liquid short-term investments with maturities of three months or less as cash equivalents.

(m) Allowance for Doubtful Accounts.

RERH accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings, historical collections, accounts receivable agings and other factors. RERH writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.

(3) Related Party Transactions

These financial statements include significant transactions between RERH and Reliant Energy. The majority of these transactions involve the purchase or sale of power or related services by Reliant Energy from or to RERH and allocations of costs to RERH for certain support services. The following describes the impacts on the financial statements for the particular transactions:

Notes Receivable—Affiliate. Reliant Energy manages RERH's daily cash balances. Excess cash is advanced to Reliant Energy, which provides a cash management function, and is recorded in long-term notes receivable—affiliated company. As cash is required to fund operations, Reliant Energy funds RERH's bank accounts. RERH records interest income or expense, based on whether RERH invested excess funds, or borrowed funds from Reliant Energy. The amount of net interest income is $102 million, $83 million and $18 million during 2005, 2004 and 2003, respectively.

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Support Services. Reliant Energy provides RERH commercial support and other corporate support services. During 2004 and 2003, Reliant Energy allocated certain support services costs to RERH based on RERH's operating expenses relative to the operating expenses of other entities to which Reliant Energy provides similar services, allocated certain other support costs to RERH based on number of employees and also charged RERH for certain services based on usage and based on number of employees. Effective January 2005, Reliant Energy began allocating certain support services costs to RERH based on RERH's underlying planned operating expenses relative to the underlying planned operating expenses of other entities to which Reliant Energy provides similar services and also began charging RERH for certain services based on usage and based on number of employees. Management believes these methods of allocation are reasonable and do not yield significantly different results between the two methodologies. These allocations and charges were not necessarily indicative of what would have been incurred had RERH been an unaffiliated entity. Amounts charged and allocated to RERH for these services were $67 million, $98 million and $93 million during 2005, 2004 and 2003, respectively, and are included in operation and maintenance—affiliates and selling, general and administrative expenses—affiliates. Included in these amounts are $6 million, $13 million and $10 million for 2005, 2004 and 2003, respectively, for RERH's share of allocated rent expense, which is included in selling, general and administrative expense—affiliates.

Naming Rights to Houston Sports Complex. In 2000, Reliant Energy acquired the naming rights, including advertising and other benefits, for a football stadium and other convention and entertainment facilities. Pursuant to this agreement, Reliant Energy is required to pay $10 million per year from 2002 through 2032. These costs are charged to RERH by Reliant Energy and are included in selling, general and administrative expense.

Payment to CenterPoint in 2004. In connection with Reliant Energy's separation agreement with CenterPoint Energy, Inc. (CenterPoint), Reliant Energy made a payment of $177 million to CenterPoint in November 2004 related to RERH's residential customers. In 2002, RERH entered into an agreement with Reliant Energy to reimburse Reliant Energy for the payment. RERH recognized $2 million, $47 million and $128 million during 2004, 2003 and 2002, respectively. RERH reduced its long-term notes receivable—affiliate for the related reimbursement to Reliant Energy. See note 7.

Reliant Energy Services and REES Energy Supply Services. Prior to 2003, Reliant Energy Services primarily provided RERH with its energy supply services. During 2003, certain supply contracts were transferred from Reliant Energy Services to RERH's subsidiary at the time, REES. The value of those contracts was $43 million, net of tax of $27 million, in 2003. This transfer was included in contributions from member in 2003. As discussed in note 1, RERH transferred its interest in REES to Reliant Energy on January 1, 2005. During 2005, 2004 and 2003, REES and Reliant Energy Services primarily provided the energy supply services to RERH. During 2005 and 2004, the administrative costs for these services were included in the corporate support services allocations. The administrative costs for these services were $2 million during 2003 and were recorded in operations and maintenance—affiliates.

As discussed above, Reliant Energy Services and REES enter into contracts with third parties for the purposes of supplying RERH with some of the electricity necessary to serve its retail customers. These supply contracts are subject to the provisions of the master commodity purchase and sale agreements, master netting arrangements and other contractual arrangements that Reliant Energy Services and REES utilize with third-party customers and suppliers in connection with their supply portfolio management activities, including those activities undertaken for RERH. Consequently, the cost associated with credit support for the supply portfolio managed by Reliant Energy Services and REES for RERH could differ significantly from those that RERH would experience if it managed all of its electricity supply portfolio directly with third parties.

RERH reimburses Reliant Energy Services and REES for the ultimate price of any electricity sold from Reliant Energy Services/REES to RERH, including costs of derivative instruments, upon final

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delivery of that electricity. RERH does not account for the unrealized value associated with the derivative instruments executed by Reliant Energy Services/REES with third parties because the contracts are executed by Reliant Energy Services/REES.

Purchased power from REES was $4.6 billion during 2005 and purchased power from Reliant Energy Services was $1.4 billion and $522 million during 2004 and 2003, respectively. These amounts were recorded as purchased power—affiliates. During 2004 and 2003, REES was a consolidated subsidiary of RERH; therefore, purchased power from REES during 2004 and 2003 is included in purchased power. Sales and purchases of electricity related to large commercial, industrial and governmental/institutional customers under contracts entered into prior to October 25, 2002, are accounted for on the mark-to-market basis (see note 2(d) for further discussion) and are presented on a net basis. During 2005, 2004 and 2003, RERH recognized $0.2 million, $14 million and $63 million, respectively, of previously unrealized losses related to supply contracts accounted for on a mark-to-market basis prior to 2003.

Income Taxes. During 2005, 2004 and 2003, Reliant Energy made equity contributions to RERH for deemed distributions related to federal income taxes of $133 million, $130 million and $243 million, respectively. See note 7.

(4) Derivatives and Hedging Activities

RERH, through REES and Reliant Energy Services, historically used derivative instruments to manage operational or market constraints and to execute its supply procurement strategy. The instruments used were fixed-price derivative contracts to hedge the variability in future cash flows from forecasted sales of power and purchases of power. RERH's objective in entering into these fixed-price derivatives was to fix the price for a portion of these transactions. See note 2(d).

RERH's derivative portfolio, excluding cash flow hedges, was $44 million (net asset) as of December 31, 2004. RERH's cash flow hedges were insignificant as of December 31, 2004.

During 2004 and 2003, there was no hedge ineffectiveness recognized from derivatives that were designated and qualified as cash flow hedges. In addition, no component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness for these periods. If it became probable that an anticipated transaction would not occur, RERH realized in net income (loss) the deferred gains and losses recognized in accumulated other comprehensive income/loss. During 2004 and 2003, there were no amounts recognized in the results of operations as a result of the discontinuance of cash flow hedges because it was probable that the forecasted transaction would not occur. As a result of RERH transferring its interest in REES effective January 2005, RERH did not have any cash flow hedges or other derivatives during 2005.

(5) Receivables Facility

RERH has a receivables facility arrangement to sell an undivided interest in accounts receivable from its business to financial institutions on an ongoing basis. RERH amended this arrangement in September 2005 to extend its maturity until September 2006, reduce the fees it is charged, increase the proportion of receivables against which it can borrow and increase the maximum capacity available from $350 million to $450 million.

Prior to September 28, 2004, these transactions were accounted for as sales of receivables; as a result, the related receivables and debt were excluded from the consolidated balance sheet. Effective with the September 28, 2004 amendment to this facility, the qualified special purpose entity (QSPE)

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ceased to be a QSPE and RERH began consolidating its results of operations and the proceeds from receivables sold to the financial institutions were treated as a financing. As a result, accounts receivable and short-term borrowings of $350 million were included in the consolidated balance sheet as of the amendment date. The borrowings under the facility bear interest at floating rates that include fees based on the facility's level of commitment and utilization. RERH services the receivables and received a fee of 0.4%, 0.4% and 0.5% of cash collected during 2005, 2004 and 2003, respectively, which approximates the actual service costs. Reliant Energy also guarantees the performance obligations of the originators of the receivables and the servicing of the receivables.

(6) Benefit Plans

(a) Stock-Based Incentive Plans.

Overview. RERH's eligible employees participate in stock-based incentive plans described below. The Compensation Committee of Reliant Energy's Board of Directors administers Reliant Energy's stock-based incentive plans. The Reliant Energy, Inc. 2002 Long-Term Incentive Plan (the 2002 LTIP) and the Reliant Energy, Inc. 2002 Stock Plan (the 2002 Stock Plan) permit Reliant Energy to grant various stock-based incentive awards to officers, key employees and directors. Awards include stock options, stock appreciation rights, restricted stock, performance awards, cash awards and stock awards.

RERH applies the intrinsic value method of accounting for employee stock-based incentive plans. Awards to RERH employees under Reliant Energy's stock-based incentive plans resulted in expense of $0, $5 million and $1 million during 2005, 2004 and 2003, respectively. See note 2(j) for pro forma information.

Time-Based Stock Options. Reliant Energy grants time-based stock options to RERH's employees at an exercise price equal to or greater than the fair market value of Reliant Energy's stock on the grant date without cost to participants. Generally, options vest 33.33% per year and have a term of ten years.

Summarized time-based option activity is:

	2005			2004			2003
	Options	Weighted Average Exercise Price		Options	Weighted Average Exercise Price		Options	Weighted Average Exercise Price
Granted	—	$	—	—	$	—	607,067	$	3.52
Outstanding at end of year	1,351,042		16.95	1,699,933		16.34	3,227,228		15.96
Exercisable at end of year	1,250,823		18.03	1,389,393		18.46	1,687,221		18.99

As of December 31, 2005, exercise prices for Reliant Energy's stock options outstanding and held by RERH's employees ranged from $3.51 to $34.03.

Time-Based Restricted Stock Awards. Reliant Energy grants time-based restricted stock awards to RERH's employees without cost to participants. In general, these awards vest, subject to the participant's continued employment, three years from the grant date.

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Summarized restricted stock award activity is:

	2005		2004		2003
Granted		80,235		228,062		295,713
Outstanding at end of year		334,904		260,380		332,968
Weighted average grant date fair value	$	12.63	$	8.20	$	3.51

Performance-Based Awards. Reliant Energy grants performance-based awards to RERH's employees without cost to participants. The number of performance-based awards earned is determined at the end of each performance period. All of the outstanding performance-based awards as of December 31, 2005 are for the 2004-2006 performance period.

Reliant Energy's Compensation Committee granted the 2004-2006 performance-based awards through the Key Employee Award Program (the Program) established under the 2002 LTIP. Under the Program, each performance-based award represents a targeted award of (a) 16,000 shares of performance-based stock, (b) 68,000 performance-based stock options and (c) 16,000 cash units with each cash unit having an equivalent fair market value of one share of Reliant Energy's common stock on the vesting date. The Program provides for a payout ranging from 0% to 140% of the targeted award level, as determined by Reliant Energy's Compensation Committee in its sole discretion after considering various qualitative and quantitative performance criteria. These criteria include (a) reducing Reliant Energy's ratio of adjusted net debt to adjusted EBITDA to at least 3.5, (b) delivering superior customer value and (c) building a great company to work for, taking into consideration market conditions for each factor. EBITDA is defined as earnings (loss) before interest expense, interest income, income taxes, depreciation and amortization expense. Reliant Energy's Compensation Committee has the discretion to weight the various performance objectives as it deems appropriate.

Summarized performance-based stock award activity, including the Program and previous programs and assuming a 140% payout of the Program, is:

	2005	2004		2003
Granted	—		358,400	—
Outstanding at end of year	179,200		350,350	58,500
Weighted average grant date fair value	N/A	$	8.24	N/A

Summarized performance-based option activity of the Program, assuming a 140% payout, is:

	2005			2004
	Options	Weighted Average Exercise Price		Options	Weighted Average Exercise Price
Granted	—	$	—	1,523,200	$	8.24
Outstanding at end of year	761,600		8.34	1,332,800		8.25
Exercisable at end of year	—		—	—		—

As of December 31, 2005, exercise prices for Reliant Energy's performance-based stock options outstanding and held by RERH's employees ranged from $8.14 to $12.63.

Employee Stock Purchase Plan. Reliant Energy has 18 million shares of authorized common stock reserved and approved for issuance under the Reliant Energy, Inc. Employee Stock Purchase Plan (ESPP). Under the ESPP, substantially all regular RERH employees can purchase Reliant Energy common stock through payroll deductions of up to 15% of eligible compensation. The ESPP provides for semiannual offering periods commencing on January 1 and July 1 of each year. The share price paid by an employee equals the lesser of 85% of the average market price on the first or last business

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day of each offering period. Individual ESPP participants are restricted from purchasing more than $25,000 of common stock in a calendar year.

During January 2006 and during 2005, 2004 and 2003, Reliant Energy issued 72,809 shares, 201,049 shares, 485,747 shares and 910,056 shares to RERH's employees under the ESPP, respectively.

(b) Savings Plan.

RERH's employees participate in Reliant Energy's employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code. Under the plans, participating employees may contribute a portion of their compensation generally up to a maximum of 50% pre-tax and 16% after-tax during 2005 and 16% pre-tax or after-tax during 2004 and 2003. RERH's savings plan benefit expense, including matching and discretionary contributions, was $5 million, $7 million and $9 million during 2005, 2004 and 2003, respectively.

(7) Income Taxes

RERH's income tax expense (benefit) is:

			2005			2004		2003
			(in millions)
Current:
	Federal		$	137		$	130	$	243
	State			18			10		38

		Total current		155			140		281

Deferred:
	Federal			(10	)		71		(42	)
	State			4			10		(7	)

		Total deferred		(6	)		81		(49	)

Income tax expense			$	149		$	221	$	232

A reconciliation of the federal statutory income tax rate to the effective income tax rate is:

			2005			2004			2003
			(in millions)
Income before income taxes			$	382		$	593		$	604
Federal statutory rate				35	%		35	%		35	%

Income tax expense at statutory rate				134			208			211

Net addition (reduction) in taxes resulting from:
	State income taxes, net of federal income taxes			14			13			20
	Other, net			1			—			1

		Total		15			13			21

Income tax expense			$	149		$	221		$	232

Effective rate				39	%		37	%		38	%

F-87

Deferred tax assets and liabilities are:

			December 31,
			2005			2004
			(in millions)
Deferred tax assets:
Current:
	Derivative liabilities, net		$	—		$	1
	Allowance for doubtful accounts and credit provisions			9			14
	Employee benefits			—			3
	Other			1			1

		Total current deferred tax assets		10			19

Non-current:
	Employee benefits			3			2
	Net operating loss carryforwards			1			2
	Other			—			1
	Valuation allowances			(1	)		(2	)

		Total non-current deferred tax assets		3			3

		Total deferred tax assets	$	13		$	22

Deferred tax liabilities:
Non-current:
	Depreciation and amortization		$	21		$	34
	Derivative assets, net			—			18
	Other			6			1

		Total non-current deferred tax liabilities		27			53

		Total deferred tax liabilities	$	27		$	53

		Accumulated deferred income taxes, net	$	(14	)	$	(31	)

Tax Attribute Carryovers. Tax attribute carryovers are:

		December 31, 2005		Statutory Carryforward Period	Expiration Year(s)
		(in millions)		(in years)
Net Operating Loss Carryforwards:
	State	$	41	5 to 7	2007 through 2009

Tax Contingencies. Reliant Energy's income tax returns, including years when it was included in CenterPoint's consolidated tax group, for the 1997 to 2004 tax reporting periods are under audit by federal and state taxing authorities. These audits may result in additional taxes or revisions of the timing of tax payments. As RERH is a part of the consolidated income tax returns of Reliant Energy, it could be subject to additional taxes. RERH evaluates the need for contingent tax liabilities on a quarterly basis and records any estimable and probable tax exposures in its results of operations. In addition, RERH discloses any material tax contingencies as to which it believes there is a reasonable possibility of a future tax assessment.

Pursuant to the Texas electric restructuring law, Reliant Energy, which was subsequently reimbursed by RERH, made a payment of $177 million to CenterPoint during 2004 related to RERH's residential customers. See note 3. RERH believes this payment is deductible for income tax purposes;

F-88

however, no assurance can be given that the Internal Revenue Service would not assert, or that a court would not sustain, a contrary position.

(8) Commitments

(a) Lease Commitments.

Cash Obligations Under Operating Leases. RERH's projected cash obligations under non-cancelable long-term operating leases as of December 31, 2005 are (in millions):

2006		$	4
2007			3
2008			2
2009			2
2010			2
2011 and thereafter			—

	Total	$	13

Operating Lease Expense. Total lease expense for all operating leases was $9 million, $5 million and $5 million during 2005, 2004 and 2003, respectively.

(b) Guarantees.

Guarantor. Together with certain of Reliant Energy's other subsidiaries, RERH, excluding RE Retail Receivables, LLC, is a guarantor of certain obligations under credit and debt agreements of Reliant Energy. As of December 31, 2005, RERH's maximum potential amount of future payments under these guarantees is approximately $4.9 billion and $3.6 billion is outstanding for continuing operations. These obligations mature at various dates from 2009 through 2036.

Equity Pledged as Collateral to Reliant Energy. RERH LLC's equity is pledged as collateral under certain of Reliant Energy's credit and debt agreements, which have an outstanding balance from continuing operations of $3.6 billion as of December 31, 2005.

Other. RERH enters into contracts that include indemnification and guarantee provisions. In general, RERH enters into contracts with indemnities for matters such as breaches of representations and warranties and covenants contained in the contract and/or against certain specified liabilities. Examples of these contracts include asset sales agreements, retail supply agreements, service agreements and procurement agreements.

RERH is unable to estimate its maximum potential exposure under these provisions until an event triggering payment under these provisions occurs. Based on current information, RERH considers the likelihood of making any material payments under these provisions to be remote.

F-89

(c) Other Commitments.

Sales Commitments. As of December 31, 2005, RERH has sales commitments, including electric energy and capacity sales contracts, which are not classified as derivative assets and liabilities. The estimated minimum sales commitments under these contracts are as follows (in millions):

2006		$	2,043
2007			924
2008			416
2009			144
2010			73

	Total	$	3,600

(9) Contingencies

Legal Matters.

RERH is party to a number of legal and other proceedings before courts and governmental agencies. Unless otherwise noted, RERH cannot predict the outcome of these proceedings.

Texas Commercial Energy. In July 2003, Texas Commercial Energy, LLP (TCE) sued RERH and several other ERCOT power market participants in the United States District Court for the Southern District of Texas. TCE claimed damages in excess of $535 million for alleged violations of state and federal antitrust laws, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract and civil conspiracy. The trial court dismissed the lawsuit. The United States Court of Appeals for the Fifth Circuit affirmed the dismissal of the lawsuit and denied TCE's request for a rehearing. In January 2006, the United States Supreme Court denied a petition to review the dismissal of the lawsuit.

Utility Choice Electric. In February 2005, Utility Choice Electric filed a lawsuit that alleges similar claims to the TCE lawsuit and additional claims including, among others, wire fraud, mail fraud and violations of the Racketeer Influenced and Corrupt Organizations Act. In December 2005, the United States District Court for the Southern District of Texas granted RERH's motion to dismiss all federal claims. The court also dismissed without prejudice the state law claims. Following the dismissal, RERH reached an agreement to settle the remaining state law claims for an immaterial amount.

PUCT Cases. There are various proceedings pending before the state district court in Travis County, Texas, seeking reviews of the Public Utility Commission of Texas (PUCT) orders relating to the fuel factor component used in RERH's "price-to-beat" tariff. These proceedings pertain to the same issues affirmed by a district court in Travis County and later by the Travis County Court of Appeals in 2004 in a separate proceeding.

(10) Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and payable and derivative assets and liabilities and third-party debt equal their carrying amounts.

(11) Sales of Landfill-Gas Fueled Power Plants

RERH sold Renewables, which owned landfill-gas fueled power plants, for $28 million in July 2005 and recognized a loss of $4 million.

F-90

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Reliant Energy Northeast Generation, Inc., Sole Member of Reliant Energy Mid-Atlantic Power Holdings, LLC
Houston, Texas

We have audited the accompanying consolidated balance sheets of Reliant Energy Mid-Atlantic Power Holdings, LLC and subsidiaries (the "Company"), as of December 31, 2005 and 2004, and the related consolidated statements of operations, member's equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Reliant Energy Mid-Atlantic Power Holdings, LLC and subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in note 2 to the consolidated financial statements, the Company changed its accounting for asset retirement obligations in 2003.

DELOITTE & TOUCHE LLP

Houston, Texas
March 14, 2006

F-91

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Thousands of Dollars)

			2005			2004			2003
Revenues:
	Revenues		$	42,906		$	517,908		$	545,944
	Revenues—affiliates			587,336			(31,160	)		48,429

		Total		630,242			486,748			594,373
Expenses:
	Fuel and purchased power			230,391			204,916			188,105
	Fuel and purchased power—affiliates			20,465			8,862			16,840
	Operation and maintenance			72,712			104,416			126,023
	Operation and maintenance—affiliates			45,997			27,021			34,626
	Facilities leases			59,848			59,848			59,848
	General and administrative—affiliates			44,956			60,212			62,247
	Gain on sale of counterparty claim			—			(22,000	)		—
	Gains on sales of assets and emission allowances, net			(109,798	)		(14,955	)		(2,468	)
	Depreciation and amortization			83,544			85,988			79,865

		Total operating expense		448,115			514,308			565,086

Operating Income (Loss)				182,127			(27,560	)		29,287

Other Income (Expense):
	Other, net			53			1,462			1,565
	Interest expense			(1,418	)		(2,058	)		(1,601	)
	Interest expense—affiliates			(64,746	)		(59,374	)		(60,729	)
	Interest income			939			812			554

		Total other expense		(65,172	)		(59,158	)		(60,211	)

Income (Loss) Before Income Taxes				116,955			(86,718	)		(30,924	)
	Income tax expense (benefit)			14,579			4,674			(15,692	)

Income (Loss) Before Cumulative Effect of Accounting Changes				102,376			(91,392	)		(15,232	)
	Cumulative effect of accounting changes, net of tax			(225	)		—			2,305

Net Income (Loss)			$	102,151		$	(91,392	)	$	(12,927	)

See Notes to the Consolidated Financial Statements

F-92

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)

			December 31,
			2005			2004
ASSETS
Current Assets:
	Cash and cash equivalents		$	31,067		$	39,029
	Restricted cash			—			3,105
	Accounts receivable			4,455			5,776
	Receivables from affiliates, net			16,493			30,313
	Inventory			80,980			71,764
	Prepaid lease			59,030			59,030
	Derivative assets			65,206			63,913
	Accumulated deferred income taxes			31,652			10,423
	Prepayments and other current assets			10,736			2,200

		Total current assets		299,619			285,553

Property, Plant and Equipment, net				693,865			747,600

Other Assets:
	Goodwill			3,635			3,853
	Other intangibles, net			117,763			145,051
	Derivative assets			—			25,291
	Prepaid lease			259,412			243,463
	Restricted cash			—			25,547
	Other			64,676			34,403

		Total other assets		445,486			477,608

Total Assets			$	1,438,970		$	1,510,761

LIABILITIES AND MEMBER'S EQUITY
Current Liabilities:
	Current portion of long-term debt		$	77		$	14,141
	Accounts payable, principally trade			11,365			11,645
	Subordinated accounts payable to affiliates, net			133,492			155,192
	Subordinated interest payable to affiliates, net			104,759			—
	Derivative liabilities			138,615			76,221
	Other			30,730			15,202

		Total current liabilities		419,038			272,401

Other Liabilities:
	Subordinated interest payable to affiliates, net			—			291,581
	Derivative liabilities			155,495			107,353
	Benefit obligations			35,000			27,324
	Other			18,285			31,484

		Total other liabilities		208,780			457,742

Subordinated Note Payable to Affiliate				618,658			618,658

Long-term Debt				814			14,961

Commitments and Contingencies
Member's Equity:
	Common stock; no par value (1,000 shares authorized, issued and outstanding)			—			—
	Additional paid-in capital			251,520			233,694
	Retained earnings (deficit)			71,039			(31,112	)
	Accumulated other comprehensive loss			(130,879	)		(55,583	)

		Total member's equity		191,680			146,999

Total Liabilities and Member's Equity			$	1,438,970		$	1,510,761

See Notes to the Consolidated Financial Statements

F-93

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

					2005			2004			2003
Cash Flows from Operating Activities:
	Net income (loss)				$	102,151		$	(91,392	)	$	(12,927	)
	Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
		Cumulative effect of accounting changes				225			—			(2,305	)
		Depreciation and amortization				83,544			85,988			79,865
		Deferred income taxes				2,385			15,184			(3,896	)
		Federal income tax contributions from (distributions to) Reliant Energy, Inc., net				3,826			(8,392	)		(18,101	)
		Net unrealized (gains) losses on energy derivatives				5,885			(3,985	)		(4,661	)
		Gains on sales of assets and emission allowances, net				(109,798	)		(14,955	)		(2,468	)
		Other, net				(493	)		2,363			(7,437	)
		Changes in other assets and liabilities:
			Accounts receivable			1,321			133			(1,239	)
			Accounts receivable from affiliates, net			13,820			5,865			20,790
			Inventory			(9,216	)		5,272			1,179
			Net derivative assets and liabilities			—			—			3,124
			Prepaid lease			(15,949	)		(25,682	)		(17,727	)
			Accounts payable			(857	)		(4,175	)		(1,668	)
			Other current assets			(8,536	)		1,626			124
			Other current liabilities			(1,773	)		2,009			(2,583	)
			Other assets			(1,218	)		(513	)		(4,290	)
			Subordinated accounts payable to affiliates, net			(21,700	)		(13,104	)		60,376
			Subordinated interest payable to affiliates, net			(186,822	)		58,314			356
			Taxes payable/receivable			17,279			720			(336	)
			Other liabilities			9,160			4,118			2,951

				Net cash provided by (used in) operating activities		(116,766	)		19,394			89,127

Cash Flows from Investing Activities:
	Capital expenditures					(7,785	)		(13,113	)		(22,259	)
	Proceeds from sales of assets, net					42,560			—			—
	Proceeds from sales of permits and rights to affiliate					—			19,600			19,215
	Proceeds from sales of emission allowances					108,422			43,508			12,504
	Purchases of emission allowances					(34,834	)		(75,266	)		(30,227	)
	Restricted cash					28,652			13,686			(42,338	)
	Other, net					—			1,971			—

				Net cash provided by (used in) investing activities		137,015			(9,614	)		(63,105	)

Cash Flows from Financing Activities:
	Proceeds from long-term debt					—			—			42,207
	Payments of long-term debt					(28,211	)		(14,093	)		—
	Payments on subordinated notes payable to affiliate					—			—			(66,939	)

				Net cash used in financing activities		(28,211	)		(14,093	)		(24,732	)

Net Change in Cash and Cash Equivalents						(7,962	)		(4,313	)		1,290
Cash and Cash Equivalents at Beginning of Period						39,029			43,342			42,052

Cash and Cash Equivalents at End of Period					$	31,067		$	39,029		$	43,342

Supplemental Disclosure of Cash Flow Information:
	Cash Payments:
		Interest paid to affiliate			$	244,976		$	—		$	60,634
		Interest paid (net of amounts capitalized) to third party				1,539			1,983			1,611
		Income taxes paid (net of income tax refunds received)				(1,739	)		267			6,637
	Non-cash Disclosure:
		Contributions from (distributions to) Reliant Energy, Inc., net				17,826			(8,392	)		(18,101	)

See Notes to the Consolidated Financial Statements

F-94

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER'S EQUITY AND COMPREHENSIVE
INCOME (LOSS)

(Thousands of Dollars)

		Common Stock									Accumulated Other Comprehensive Income (Loss)
		Common Stock			Additional Paid-In Capital			Retained Earnings (Deficit)						Total Member's Equity			Comprehensive Income (Loss)
		Shares	Amount		Additional Paid-In Capital			Retained Earnings (Deficit)						Total Member's Equity			Comprehensive Income (Loss)
Balance, December 31, 2002		1,000	$	—	$	260,187		$	73,207		$	21,278		$	354,672
Net loss									(12,927	)					(12,927	)	$	(12,927	)
Distributions						(18,101	)								(18,101	)
Deferred loss from cash flow hedges, net of tax of $23 million												(33,317	)		(33,317	)		(33,317	)
Reclassification of net deferred gain from cash flow hedges, net of tax of $3 million												(3,792	)		(3,792	)		(3,792	)

	Comprehensive loss																$	(50,036	)

Balance, December 31, 2003		1,000		—		242,086			60,280			(15,831	)		286,535
Net loss									(91,392	)					(91,392	)	$	(91,392	)
Distributions						(8,392	)								(8,392	)
Deferred loss from cash flow hedges, net of tax of $44 million												(63,128	)		(63,128	)		(63,128	)
Reclassification of net deferred loss from cash flow hedges, net of tax of $16 million												23,376			23,376			23,376

	Comprehensive loss																$	(131,144	)

Balance, December 31, 2004		1,000		—		233,694			(31,112	)		(55,583	)		146,999
Net income									102,151						102,151		$	102,151
Contributions						17,826									17,826
Deferred loss from cash flow hedges, net of tax of $91 million												(128,132	)		(128,132	)		(128,132	)
Reclassification of net deferred loss from cash flow hedges, net of tax of $37 million												52,836			52,836			52,836

	Comprehensive income																$	26,855

Balance, December 31, 2005		1,000	$	—	$	251,520		$	71,039		$	(130,879	)	$	191,680

See Notes to the Consolidated Financial Statement

F-95

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Background and Basis of Presentation

Background. "REMA LLC" refers to Reliant Energy Mid-Atlantic Power Holdings, LLC, a Delaware limited liability company. "REMA" refers to REMA LLC and its consolidated subsidiaries. "Reliant Energy" refers to Reliant Energy, Inc. and its consolidated subsidiaries. REMA LLC was formed in December 1998 and is an indirect subsidiary of Reliant Energy Power Generation, Inc., a wholly-owned subsidiary of Reliant Energy.

REMA owns or leases interests in 16 operating electric generation plants in Pennsylvania, New Jersey and Maryland with an annual average net generating capacity of approximately 3,576 megawatts (MW).

Basis of Presentation. These consolidated statements include all revenues and costs directly attributable to REMA including costs for facilities and costs for functions and services performed by Reliant Energy and charged to REMA. All significant intercompany transactions have been eliminated. REMA has reclassified certain amounts from prior periods to conform to the 2005 presentation. These reclassifications had no impact on reported earnings/losses and are described in notes 2(k) and 13.

(2) Summary of Significant Accounting Policies

(a) Use of Estimates and Market Risk and Uncertainties.

Management makes estimates and assumptions to prepare financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) that affect:

•: the reported amount of assets and liabilities,
•: the reported amounts of revenues and expenses and
•: our disclosure of contingent assets and liabilities at the date of the financial statements.

REMA's critical accounting estimates include: (a) property, plant and equipment; (b) derivative assets and liabilities; and (c) deferred tax assets, valuation allowances and tax liabilities. Actual results could differ from the estimates.

REMA is subject to various risks inherent in doing business. See notes 2(d), 2(e), 2(g), 2(m), 5, 7, 8, 9 and 10.

(b) Principles of Consolidation.

REMA LLC includes its accounts and those of its wholly-owned subsidiaries in its consolidated financial statements. REMA does not consolidate three power generating facilities (see note 9(a)), which are under operating leases.

(c) Revenues.

REMA records gross revenues from the sale of electricity and other energy services under the accrual method. Electric power and other energy services are sold at market-based prices through existing power exchanges or through third party contracts. Energy sales and services that have been delivered but not billed by period-end are estimated.

F-96

(d) Derivatives and Hedging Activities.

REMA accounts for its derivatives instruments and hedging activities in accordance with SFAS No. 133, "Accounting for Derivatives Instruments and Hedging Activities," as amended (SFAS No. 133).

For REMA's hedging activities, it uses both derivative and non-derivative contracts that provide for settlement in cash or by delivery of a commodity. The primary types of derivative instruments REMA uses are forwards, futures, swaps and options. REMA elects one of three accounting methods (cash flow hedge, mark-to-market or accrual accounting) for derivatives based on facts and circumstances. The fair values of derivative activities are determined by (a) prices actively quoted, (b) prices provided by other external sources or (c) prices based on models and other valuation methods.

If certain conditions are met, a derivative instrument may be designated as a cash flow hedge. A derivative is recognized at fair value in the balance sheet whether or not it is designated as a hedge, except for derivative contracts designated as "normal purchases and sales exceptions," which are not in its consolidated balance sheet or results of operations prior to settlement.

Derivatives designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive income (loss), net of tax, to the extent the contracts are effective as hedges, until the forecasted transactions affect earnings. At the time the forecasted transactions affect earnings, REMA reclassifies the amounts in other comprehensive income (loss) into earnings. REMA records the ineffective portion of changes in fair value of cash flow hedges immediately into earnings. For all other derivatives, changes in fair value are recorded as unrealized gains or losses in its results of operations.

If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in its results of operations. If it becomes probable that a forecasted transaction will not occur, REMA immediately recognizes the related deferred gains or losses in its results of operations. The associated hedging instrument is then marked to market through its results of operations for the remainder of the contract term unless a new hedging relationship is redesignated.

Prior to October 1, 2003, REMA generally recorded, on a gross basis in the period of delivery (a) sales in revenues and (b) purchases in fuel and purchased power. In July 2003, the EITF issued EITF No. 03-11, which states that realized gains and losses on derivatives contracts not "held for trading purposes" should be reported either on a net or gross basis based on the relevant facts and circumstances. EITF No. 03-11 has no impact on margins or net income. Subsequent to October 1, 2003, due to the adoption of EITF No. 03-11, hedging transactions that do not physically flow are included the same caption as the items being hedged. A summary of REMA's derivative activities and classification in its results of operations is:

Instrument		Purpose for Holding or Issuing Instrument⁽¹⁾		Transactions that Physically Flow		Transactions that Financially Settle⁽²⁾
Power futures, forward, swap and option contracts		Power sales Power purchases		Revenues Fuel and purchased power		Revenues Revenues
Natural gas and fuel futures, forward, swap and option contracts		Natural gas and fuel purchases		Fuel and purchased power		Fuel and purchased power

(1): The purpose for holding or issuing is not impacted by the accounting method elected for each instrument.

F-97

(2): Includes classification for mark-to-market derivatives and amounts reclassified from accumulated other comprehensive income (loss) related to cash flow hedges.

In addition to market risk, REMA is exposed to credit and operational risk. Reliant Energy has a control framework, to which REMA is subject, to manage these risks, which include: (a) measuring and monitoring these risks, (b) review and approval of new transactions relative to these risks, (c) transaction validation and (d) portfolio valuation and reporting. REMA uses mark-to-market valuation, value-at-risk and other metrics in monitoring and measuring risk. Reliant Energy's risk control framework includes a variety of separate but complementary processes, which involve commercial and senior management and Reliant Energy's Board of Directors. See note 2(e) for further discussion of REMA's credit policy.

(e) Credit Risk.

REMA has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. Credit risk is monitored daily and the financial condition of counterparties is reviewed periodically. REMA tries to mitigate credit risk by entering into contracts that permit netting and allow it to terminate upon the occurrence of certain events of default. REMA measures credit risk as the replacement cost for its derivative positions plus amounts owed for settled transactions.

As of December 31, 2005, two non-investment grade counterparties represented 91% ($15 million) of REMA's credit exposure, net of collateral. As of December 31, 2004, two non-investment grade counterparties represented 64% ($52 million) of REMA's credit exposure, net of collateral. There were no other counterparties representing greater than 10% of REMA's credit exposure, net of collateral.

(f) General and Administrative Expenses—Affiliates.

General and administrative expenses from affiliates include, among other items, (a) selling and marketing, (b) financial services, (c) legal costs, (d) regulatory costs and (e) certain benefit costs. See note 3.

(g) Property, Plant and Equipment and Depreciation Expense.

REMA computes depreciation using the straight-line method based on estimated useful lives. Depreciation expense was $33 million, $47 million and $51 million during 2005, 2004 and 2003, respectively.

			December 31,
		Estimated Useful Lives (Years)	December 31,
		Estimated Useful Lives (Years)	2005			2004
			(in millions)
Electric generation facilities		10-30	$	813		$	826
Land improvements		22-26		2			2
Other		3-10		9			9
Land				27			28
Assets under construction				7			24

	Total			858			889
Accumulated depreciation				(164	)		(141	)

	Property, plant and equipment, net		$	694		$	748

REMA periodically evaluates property, plant and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is

F-98

highly dependent on the underlying assumptions of related cash flows. REMA recorded no material property, plant and equipment impairments during 2005, 2004 and 2003.

In the future, REMA could recognize impairments if its wholesale energy market outlook changes negatively. In addition, REMA's ongoing evaluation of its business could result in decisions to mothball, retire or dispose of additional generation assets, any of which could result in impairment charges.

(h) Intangible Assets and Amortization Expense.

Goodwill. REMA performs its goodwill impairment test annually and when events or changes in circumstances indicate that the carrying value may not be recoverable. REMA previously selected November 1 as its annual goodwill impairment testing date since Reliant Energy had historically completed its annual strategic planning process by that date. Reliant Energy has since modified its strategic planning process, which provides key information used in the analysis of REMA's goodwill impairment test, and such information is no longer completed by November 1. In order to align REMA's annual goodwill impairment test with Reliant Energy's annual strategic planning process, to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in 2005, REMA changed the date on which it performs the annual goodwill impairment test to April 1. The change is not intended to delay, accelerate or avoid an impairment charge. REMA believes that this accounting change is to an alternative accounting principle that is preferable under the circumstances.

Other Intangibles. REMA recognizes specifically identifiable intangible assets, including emission allowances, when specific rights and contracts are acquired. REMA has no intangible assets with indefinite lives recorded as of December 31, 2005 and 2004.

(i) Income Taxes.

REMA is included in the consolidated income tax returns of Reliant Energy and calculates its income tax provision on a separate return basis, whereby Reliant Energy pays all federal income taxes on REMA's behalf and is entitled to any related tax savings. The difference between REMA's current federal income tax expense or benefit, as calculated on a separate return basis, and related amounts paid or received to/from Reliant Energy, if any, are recorded in REMA's financial statements as adjustments to additional paid-in capital on its consolidated balance sheets. Deferred income taxes reflected on REMA's consolidated balance sheet will ultimately be settled with Reliant Energy through additional paid-in capital. See notes 3 and 8.

(j) Cash and Cash Equivalents.

REMA records all highly liquid short-term investments with maturities of three months or less as cash equivalents.

(k) Restricted Cash.

Restricted cash includes cash at certain subsidiaries, the distribution or transfer of which is restricted by financing and other agreements. In the consolidated statements of cash flows for 2004 and 2003, REMA reclassified $14 million and $(42) million, respectively, from operating cash flows to investing cash flows relating to changes in restricted cash.

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(l) Inventory.

REMA values inventories used in the production of electricity at the lower of average cost or market.

		December 31,
		2005		2004
		(in millions)
Materials and supplies, including spare parts		$	44	$	43
Coal			17		14
Heating oil			20		15

	Total inventory	$	81	$	72

(m) Environmental Costs.

REMA expenses environmental expenditures related to existing conditions that do not have future economic benefit. REMA capitalizes environmental expenditures for which there is a future economic benefit. REMA records liabilities for expected future costs, on an undiscounted basis, related to environmental assessments and/or remediation when they are probable and can be reasonably estimated. See note 10.

(n) Asset Retirement Obligations.

REMA's asset retirement obligations relate to future costs primarily associated with ash disposal site closures. REMA's asset retirement obligation was $7 million and $6 million as of December 31, 2005 and 2004, respectively.

During 2005, REMA adopted an accounting interpretation relating to asset retirement obligations. This interpretation clarifies that an asset retirement obligation is unconditional even though uncertainty exists about the timing and/or method of settlement and requires that a liability be recognized if it can be reasonably estimated. Based on this, REMA (a) recorded a cumulative effect of an accounting change, net of tax, of $225,000, (b) increased other long-term liabilities by $447,000, (c) increased property, plant and equipment by $77,000 and (d) decreased deferred income tax liabilities by $145,000.

The adoption of SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003, resulted in a gain of $4 million, $2 million net of tax, as a cumulative effect on an accounting change in the consolidated results of operations for 2003.

(o) Repair and Maintenance Costs for Power Generation Assets.

REMA recognizes repair and maintenance costs as incurred.

(p) Deferred Lease Costs.

REMA incurred costs in connection with its sale-leaseback transactions in 2000 (see note 9(a)). These costs are deferred and amortized, using the straight-line method, over the life of the individual sale-leaseback transactions. REMA amortized $1 million to facilities lease expense during 2005, 2004 and 2003. As of December 31, 2005 and 2004, REMA had $20 million and $21 million, respectively, of net deferred lease costs classified in other long-term assets in its consolidated balance sheets.

(3) Related Party Transactions

These financial statements include significant transactions between REMA and Reliant Energy. The majority of these transactions involve the purchase or sale of energy, capacity, fuel, coal, emission

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allowances or related services (including transportation, transmission and storage services) from or to REMA and allocations of costs to REMA for certain support services. The following describes the impacts on the financial statements for the particular transactions:

Support Services Agreement. REMA is a party to a support services agreement with Reliant Energy under which Reliant Energy provides commercial support and other corporate services to REMA. During 2004 and 2003, Reliant Energy allocated certain support services costs to REMA based on REMA's direct labor costs relative to the direct labor costs of other entities to which Reliant Energy provides similar services and also charged REMA for certain services based on usage. Effective January 2005, Reliant Energy began allocating certain support services costs to REMA based on REMA's underlying planned operating expenses relative to the underlying planned operating expenses of other entities to which Reliant Energy provides similar services and also began charging REMA for certain services based on usage. Management believes these methods of allocation are reasonable and do not yield significantly different results between the two methodologies. These allocations and charges were not necessarily indicative of what would have been incurred had REMA been an unaffiliated entity. Amounts charged and allocated to REMA for these services were $86 million, $82 million and $92 million during 2005, 2004 and 2003, respectively. These amounts are classified in general and administrative expense—affiliates and operation and maintenance expense—affiliates. Payments to Reliant Energy for services under the support services agreement are subordinated to certain obligations, including the lease obligations, pursuant to the lease documents.

Procurement and Marketing Agreements. REMA has a procurement and marketing agreement with Reliant Energy under which Reliant Energy is entitled to certain procurement and marketing fees. Under this agreement, Reliant Energy, among other things:

•: Procures coal, fuel oil and emission allowances on REMA's behalf at a pass-through price;
•: Procures gas on REMA's behalf at a pass-through price or for an index price plus costs of delivery, depending on when and how the gas is procured;
•: Markets surplus gas, fuel oil and emission allowances on REMA's behalf at a pass-through price; and
•: Markets power on REMA's behalf at a pass-through price.

The amount charged to REMA for these services was $7 million, $6 million and $7 million during 2005, 2004 and 2003, respectively. Of these amounts, $5 million is classified in operation and maintenance—affiliates for 2005, 2004 and 2003 and $2 million, $1 million and $2 million is classified in fuel and purchased power—affiliates for 2005, 2004 and 2003, respectively. Payments of procurement and marketing fees are subordinated to certain obligations, including the lease obligations, pursuant to the lease documents. Sales to Reliant Energy, recorded in revenue—affiliates, were $587 million, $(31) million and $48 million during 2005, 2004 and 2003, respectively. Purchases from Reliant Energy, recorded in fuel and purchased power—affiliates, were $18 million, $8 million and $15 million during 2005, 2004 and 2003, respectively. During 2005 and 2004, REMA purchased $12 million and $9 million, respectively, of coal at market prices from Reliant Energy. These purchases are added to inventory along with other coal purchases. See note 2(l). Purchases from Reliant Energy are not subordinated. During 2005, 2004 and 2003, REMA sold emission allowances to Reliant Energy for $100 million, $1 million and $1 million, respectively, at market prices and recognized gains of $92 million, $1 million and $0 during 2005, 2004 and 2003, respectively, (recorded in gains on sales of assets and emission allowances, net). Reliant Energy purchased the emission allowances from REMA at the same price for which it sold them to third parties. See notes 4(b) and 13.

Subordinated Long-term Note Payable to Affiliate. REMA has a note payable to Reliant Energy. The note is due January 1, 2029 and accrues interest at a fixed rate of 9.4% per year. As of

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December 31, 2005, REMA classified the related accrued interest as a current liability since REMA intends to pay the entire amount within the next 12 months. As of December 31, 2004, REMA classified the related interest as a long-term liability since Reliant Energy indicated it would not require payment of the interest payable on this note within the next 12 months from that date. As of December 31, 2005 and 2004, REMA had $619 million outstanding under the note. Payments under this indebtedness are subordinated to certain obligations, including the lease obligations, pursuant to the lease documents.

Working Capital Note. REMA has a revolving note payable to Reliant Energy under which REMA may borrow, and Reliant Energy is committed to lend, up to $30 million for working capital needs. Borrowings under the note will be unsecured and will rank equal in priority with REMA's lease obligations. REMA may replace this note with a working capital facility from an unaffiliated lender if then permitted under Reliant Energy's debt agreements. Borrowings under the working capital note bear interest based on the London Inter Bank Offering Rate (LIBOR) or a base rate. This note expires in May 2006. As of December 31, 2005 and 2004, there were no borrowings outstanding under this note.

Subordinated Working Capital Facility. REMA has an irrevocably committed subordinated working capital facility with Reliant Energy. REMA may borrow under this facility to pay operating expenditures, senior indebtedness and rent, but excluding capital expenditures and subordinated obligations. In addition, Reliant Energy must make advances to REMA and REMA must obtain such advances under such facility up to the maximum available commitment under such facility from time to time if REMA's pro forma coverage ratio does not equal or exceed 1.1 to 1.0, measured at the time rent under the leases is due. Subject to the maximum available commitment, drawings will be made in amounts necessary to permit REMA to achieve a pro forma coverage ratio of at least 1.1 to 1.0. The amount available under the subordinated working capital facility is $120 million through January 1, 2007. Thereafter, the available amount decreases by $24 million on January 2, 2007 and by $24 million each subsequent year through its expiration in 2011. As of December 31, 2005 and 2004, there were no borrowings outstanding under this facility.

Income Taxes. During 2005, 2004 and 2003, REMA recorded non-cash equity contributions from (distributions to) Reliant Energy related to income taxes of $18 million (of which $13 million related to changes in estimates of deferred tax assets and liabilities), $(8) million and $(18) million, respectively. See note 8.

Sales of Power Generation Site Permits and Water Rights to Affiliate. During 2004 and 2003, REMA sold certain power generation site permits and water rights to Reliant Energy for $20 million and $19 million, respectively, in cash. The permits and water rights were no longer needed for REMA's business. There was no gain or loss recorded on the sales.

Letters of Credit. Reliant Energy has posted letters of credit on behalf of REMA related to its lease obligations. See notes 6 and 9(a).

(4) Intangible Assets

(a) Goodwill.

During 2005, REMA reduced goodwill $218,000 related to assets sold. See note 13. During 2004, goodwill did not change. As of December 31, 2005 and 2004, REMA had no goodwill that is deductible for United States income tax purposes for future periods.

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(b) Other Intangibles

As part of REMA's effort to operate its business efficiently, REMA concluded that since its generating assets dispatch based on market prices, it should maintain an emission allowances inventory that corresponds with forward power sales. REMA plans to sell some excess emission allowances inventory if the price is equal to or above its fundamental view.

				December 31,
		Remaining Weighted Average Amortization Period (Years)		2005					2004
		Remaining Weighted Average Amortization Period (Years)		Carrying Amount		Accumulated Amortization			Carrying Amount		Accumulated Amortization
				(in millions)
SO₂ emission allowances⁽¹⁾⁽²⁾		—	⁽¹⁾	$	177	$	(106	)	$	148	$	(67	)
NO_x emission allowances⁽¹⁾⁽³⁾		—	⁽¹⁾		89		(42	)		94		(30	)

	Total			$	266	$	(148	)	$	242	$	(97	)

(1): SO₂ is sulfur dioxide and NO_x is nitrogen oxide. Amortized to amortization expense on a units-of-production basis. As of December 31, 2005, we have recorded (a) SO₂ emission allowances through the 2030 vintage year and (b) NO_x emission allowances through the 2030 vintage year.
(2): During 2005, 2004 and 2003, we purchased $35 million, $51 million and $22 million, respectively, of SO₂ emission allowances, including purchases from affiliates of $35 million, $0 and $1 million, respectively. See note 13 for sales.
(3): During 2005, 2004 and 2003, we purchased $0, $24 million and $8 million, respectively, of NO_x emission allowances. See note 13 for sales.

Amortization expense consists of:

		2005		2004		2003
		(in millions)
Emission allowances		$	51	$	39	$	28
Power generation site permits			—		—		1

	Total	$	51	$	39	$	29

Estimated amortization expense, based on REMA's intangibles as of December 31, 2005, for the next five years is (in millions):

2006	$	11
2007		4
2008		3
2009		3
2010		5

(5) Derivatives and Hedging Activities

REMA uses derivative instruments to manage operational or market constraints and to increase return on its generation assets. The instruments used are fixed-price derivative contracts to hedge the variability in future cash flows from forecasted sales of power and purchases of fuel and power. REMA's objective in entering into these fixed-price derivatives is to fix the price for a portion of these transactions. See note 2(d).

REMA' s derivative portfolio, excluding cash flow hedges, is $1 million (net asset) and $11 million (net asset) as of December 31, 2005 and 2004, respectively. REMA's cash flow hedges are valued at $230 million (net liability) and $105 million (net liability) as of December 31, 2005 and 2004, respectively.

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During 2005, 2004 and 2003, there was a $1 million gain, a $3 million loss and a $5 million loss, respectively, of hedge ineffectiveness recognized from derivatives that are designated and qualify as cash flow hedges. In addition, no component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness for these periods. If it becomes probable that an anticipated transaction will not occur, REMA realizes in net income (loss) the deferred gains and losses recognized in accumulated other comprehensive loss. During 2005, 2004 and 2003, there were no amounts recognized in the results of operations as a result of the discontinuance of cash flow hedges because it was probable that the forecasted transaction would not occur.

As of December 31, 2005 and 2004, the maximum length of time REMA is hedging its exposure to the variability in future cash flows that may result from changes in commodity prices is seven years and eight years, respectively. As of December 31, 2005, $41 million of accumulated other comprehensive income is expected to be reclassified into the results of operations during the next 12 months. However, the actual amount reclassified into earnings could vary from the amounts recorded as of December 31, 2005, due to future changes in market prices.

(6) Debt

REMA is obligated to provide credit support for its lease obligations (see note 9(a)) in the form of letters of credit and/or cash equal to an amount representing the greater of (a) the next six months' scheduled rental payments under the related lease or (b) 50% of the scheduled rental payments due in the next 12 months under the related lease. In 2003, proceeds from the REMA term loans were used to partially fulfill REMA's requirement to provide credit support for its obligations under these leases. During 2005, the term loans were paid in full and replacement credit support was provided in the form of letters of credit issued under Reliant Energy's credit facilities. As of December 31, 2005, the amount of credit support was $32 million. The term loans bore interest at LIBOR plus 3%. The term loans were non-recourse to Reliant Energy.

See note 3 for debt transactions with affiliates.

(7) Benefit Plans

(a) Pension and Postretirement Benefits.

Benefit Plans. REMA sponsors a defined benefit pension plan and provides subsidized postretirement benefits to some bargaining employees but generally does not provide them to non-bargaining employees.

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REMA uses a December 31 measurement date for its plans. The benefit obligations and funded status are:

			Pension						Postretirement Benefits
			2005			2004			2005			2004
			(in millions)
Change in Benefit Obligation
	Beginning of year		$	22		$	18		$	48		$	40
	Service cost			4			4			2			2
	Interest cost			1			1			3			2
	Actuarial (gain) loss			—			(1	)		(14	)		4

		End of year	$	27		$	22		$	39		$	48

Change in Plan Assets
	Beginning of year		$	15		$	8		$	—		$	—
	Employer contributions			3			5			—			—
	Actual investment return			—			2			—			—

		End of year	$	18		$	15		$	—		$	—

Reconciliation of Funded Status
	Funded status		$	(9	)	$	(7	)	$	(39	)	$	(48	)
	Unrecognized prior service cost			—			—			7			8
	Unrecognized actuarial loss			3			2			6			21

		Net amount recognized	$	(6	)	$	(5	)	$	(26	)	$	(19	)

Amounts recognized in the consolidated balance sheets are:

	Pension						Postretirement Benefits
	December 31,						December 31,
	2005			2004			2005			2004
	(in millions)
Accrued benefit cost	$	(6	)	$	(5	)	$	(26	)	$	(19	)

The accumulated benefit obligation for the pension plan was $23 million and $18 million as of December 31, 2005 and 2004, respectively.

Net benefit costs are:

		Pension								Postretirement Benefits
		2005			2004			2003		2005		2004		2003
		(in millions)
Service cost		$	4		$	4		$	4	$	2	$	2	$	1
Interest cost			1			1			1		3		2		2
Expected return on plan assets			(1	)		(1	)		—		—		—		—
Net amortization			—			—			—		2		2		2

	Net benefit cost	$	4		$	4		$	5	$	7	$	6	$	5

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Assumptions. The significant weighted average assumptions used to determine the benefit obligations are:

	Pension				Postretirement Benefits
	December 31,				December 31,
	2005		2004		2005		2004
Discount rate	5.75	%	5.75	%	5.75	%	5.75	%
Rate of increase in compensation levels	3.0	%	3.0	%	N/A		N/A

The significant weighted average assumptions used to determine the net benefit costs are:

	Pension						Postretirement Benefits
	2005		2004		2003		2005		2004		2003
Discount rate	5.75	%	6.25	%	6.75	%	5.75	%	6.25	%	6.75	%
Rate of increase in compensation levels	3.0	%	4.5	%	4.5	%	N/A		N/A		N/A
Expected long-term rate of return on assets	7.5	%	7.5	%	8.5	%	N/A		N/A		N/A

As of December 31, 2005 and 2004, REMA developed its expected long-term rate of return on pension plan assets based on third party models. These models consider expected inflation, current dividend yields, expected corporate earnings growth and risk premiums based on the expected volatility of each asset category. REMA weights the expected long-term rates of return for each asset category to determine its overall expected long-term rate of return on pension plan assets. In addition, REMA reviews peer data and historical returns.

REMA's assumed health care cost trend rates used to measure the expected cost of benefits covered by its postretirement plan are:

	2005		2004		2003
Health care cost trend rate assumed for next year	9.0	%	9.75	%	10.5	%
Rate to which the cost trend rate is assumed to gradually decline	5.5	%	5.5	%	5.5	%
Year that the rate reaches the rate to which it is assumed to decline	2011		2011		2011

Assumed health care cost trend rates can have a significant effect on the amounts reported for REMA's health care plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects as of December 31, 2005:

	One-Percentage Point
	Increase		Decrease
	(in millions)
Effect on service and interest cost	$	—	$	—
Effect on accumulated postretirement benefit obligation		5		(5	)

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Plan Assets. REMA's pension weighted average asset allocations and target allocation by asset category are:

		Percentage of Plan Assets as of December 31,				Target Allocation
		2005		2004		2006
Domestic equity securities		50	%	55	%	50	%
International equity securities		11		15		10
Global equity securities		10		—		10
Debt securities		29		30		30

	Total	100	%	100	%	100	%

In managing the investments associated with the pension plan, REMA's objective is to exceed, on a net-of-fee basis, the rate of return of a performance benchmark composed of the following indices:

Asset Class		Index	Weight
Domestic equity securities		Wilshire 5000 Index	50	%
International equity securities		MSCI All Country World Ex-U.S. Index	10
Global equity securities		MSCI All Country World Index	10
Debt securities		Lehman Brothers Aggregate Bond Index	30

	Total		100	%

As a secondary measure, REMA compares asset performance to the returns of a universe of comparable funds, where applicable, over a full market cycle. Reliant Energy's Benefits Committee reviews plan asset performance each quarter by comparing the actual quarterly returns of each asset class to its related benchmark. REMA's plan assets have generally performed in accordance with the benchmarks.

Cash Obligations. REMA expects pension cash contributions to approximate $1 million during 2006. Expected benefit payments for the next ten years, which reflect future service as appropriate, are (in millions):

	Pension		Postretirement Benefits
2006	$	—	$	—
2007		1		1
2008		1		1
2009		1		1
2010		1		2
2011-2015		11		17

(b) Savings Plan.

REMA's employees participate in Reliant Energy's employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code. Under the plans, participating employees may contribute a portion of their compensation generally up to a maximum of 50% pre-tax and 16% after-tax during 2005 and 16% pre-tax or after-tax during 2004 and 2003. Bargaining employees contribute based on their respective agreements. REMA's savings plan benefit expense, including matching and discretionary contributions, was $2 million, $4 million and $5 million during 2005, 2004 and 2003, respectively.

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(c) Other Employee Matters.

As of December 31, 2005, approximately 68% of REMA's employees are subject to collective bargaining arrangements. REMA's collective bargaining arrangements expire at various intervals beginning in 2006.

(8) Income Taxes

REMA's income tax expense (benefit) is:

			2005			2004			2003
			(in millions)
Current:
	Federal		$	3		$	(11	)	$	(18	)
	State			9			1			6

		Total current		12			(10	)		(12	)

Deferred:
	Federal			6			7			13
	State			(3	)		8			(17	)

		Total deferred		3			15			(4	)

Income tax expense (benefit)			$	15		$	5		$	(16	)

A reconciliation of the federal statutory income tax rate to the effective income tax rate is:

			2005			2004			2003
			(in millions)
Income (loss) before income taxes			$	117		$	(87	)	$	(31	)
Federal statutory rate				35	%		35	%		35	%

Income tax expense (benefit) at statutory rate				41			(30	)		(11	)

Net addition (reduction) in taxes resulting from:
	State income taxes, net of federal income taxes			4			6			(7	)
	Federal valuation allowances			(30	)		30			—
	Other, net			—			(1	)		2

		Total		26			35			(5	)

Income tax expense (benefit)			$	15		$	5		$	(16	)

Effective rate				12	%		NM	⁽¹⁾		51	%

(1): Not meaningful. The primary reason is that REMA had a pre-tax loss of $87 million and income tax expense of $5 million due to the establishment of a federal operating loss carryforward valuation allowance.

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Deferred tax assets and liabilities are:

			December 31,
			2005			2004
			(in millions)
Deferred tax assets:
Current:
	Derivative liabilities, net		$	28		$	10
	Employee benefits			—			2
	Other			4			—

		Total current deferred tax assets		32			12

Non-current:
	Employee benefits			12			11
	Net operating loss carryforwards			3			35
	Environmental reserves			7			16
	Derivative liabilities, net			67			28
	Other			—			2
	Valuation allowance			(3	)		(35	)

		Total non-current deferred tax assets		86			57

		Total deferred tax assets	$	118		$	69

Deferred tax liabilities:
Current:
	Other		$	—		$	2

		Total current deferred tax liabilities					2

Non-current:
	Depreciation and amortization			49			71
	Other			7

		Total non-current deferred tax liabilities		56			71

		Total deferred tax liabilities	$	56		$	73

		Accumulated deferred income taxes, net	$	62		$	(4	)

Tax Attribute Carryovers. Tax attribute carryovers are:

		December 31, 2005		Statutory Carryforward Period	Expiration Year(s)
		(in millions)		(in years)
Net Operating Loss Carryforwards:
	State	$	56	20	2008 through 2024

Valuation Allowances. REMA's valuation allowances decreased $32 million during 2005 and increased $35 million during 2004. These changes primarily result from actual transactions that either decrease the likelihood that REMA's tax assets will be realized to a level that is below "more likely than not" or that allow REMA to use a tax asset that was previously subject to a valuation allowance. Such changes also reflect an ongoing assessment of REMA's future ability to use federal and state tax net operating loss carryforwards and other tax assets. These assessments included an evaluation of REMA's recent history of earnings and losses (as adjusted), future reversals of temporary differences and identification of other sources of future taxable income, including the identification of tax planning strategies. REMA monitors these factors quarterly and there is no assurance that these factors will

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continue to support a conclusion that the ultimate realization of any particular deferred tax asset is more likely than not.

The changes are:

		2005			2004		2003
		(in millions)
Federal net operating loss carryforwards		$	(30	)⁽¹⁾	$	30	$	—
State net operating loss carryforwards			(2	)		5		—

	Net change	$	(32	)	$	35	$	—

⁽¹⁾: Decrease due to the release of valuation allowance as REMA does not have any federal net operating loss carryforwards as of December 31, 2005.

Tax Contingencies. Reliant Energy's income tax returns, including years when it was included in CenterPoint Energy Inc.'s consolidated tax group, for the 1997 to 2004 tax reporting periods are under audit by federal and state taxing authorities. These audits may result in additional taxes or revisions of the timing of tax payments. As REMA is a part of the consolidated income tax returns of Reliant Energy, it could be subject to additional taxes. REMA evaluates the need for contingent tax liabilities on a quarterly basis and records any estimable and probable tax exposures in its results of operations. In addition, REMA discloses any material tax contingencies as to which it believes there is a reasonable possibility of a future tax assessment.

(9) Commitments

(a) Lease Commitments.

REMA entered into sale-leaseback transactions, under operating leases, that are non-recourse to Reliant Energy. REMA leases 16.45% and 16.67% interests in the Conemaugh and Keystone facilities, respectively. The leases expire in 2034 and REMA expects to make payments through 2029. REMA also leases a 100% interest in the Shawville facility. This lease expires in 2026 and REMA expects to make payments through that date. At the expiration of these leases, there are several renewal options related to fair market value. REMA LLC's subsidiaries guarantee the lease obligations and REMA LLC has pledged the equity interests in these subsidiaries as collateral. Reliant Energy also provides credit support for these lease obligations in the form of letters of credit. See note 6. During 2005, 2004 and 2003, REMA made lease payments under these leases of $75 million, $85 million and $77 million, respectively. As of December 31, 2005 and 2004, REMA has recorded a prepaid lease of $59 million in other current assets and $259 million and $243 million, respectively, in long-term assets. REMA operates these facilities under agreements that could terminate annually with one year's notice and received fees of $9 million, $9 million and $8 million during 2005, 2004 and 2003, respectively, relating to the Conemaugh and Keystone facilities. These fees, which are recorded in operation and maintenance expense, are primarily to cover REMA's administrative support costs of providing these services.

REMA's ability to make distributions or pay subordinated obligations is restricted by conditions within the lease documents. As of December 31, 2005, all of these conditions were met.

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Cash Obligations Under Operating Leases. REMA's projected cash obligations under non-cancelable long-term operating leases as of December 31, 2005 are (in thousands):

2006		$	64
2007			65
2008			62
2009			63
2010			52
2011 and thereafter			882

	Total	$	1,188

Operating Lease Expense. Operating lease expense, including the amortization of deferred lease costs, was $60 million during 2005, 2004 and 2003.

(b) Guarantees.

Equity Pledged as Collateral to Reliant Energy. REMA LLC's equity is pledged as collateral under certain of Reliant Energy's credit and debt agreements, which have an outstanding balance from continuing operations of $3.6 billion as of December 31, 2005.

Other. REMA enters into contracts that include indemnification and guarantee provisions. In general, REMA enters into contracts with indemnities for matters such as breaches of representations and warranties and covenants contained in the contract and/or against certain specified liabilities. Examples of these contracts include asset sales agreements, service agreements and procurement agreements.

REMA is unable to estimate its maximum potential exposure under these provisions until an event triggering payment under these provisions occurs. Based on current information, REMA considers the likelihood of making any material payments under these provisions to be remote.

(c) Other Commitments.

Fuel Supply Commitments. REMA is a party to fuel supply contracts of various quantities and durations that are not classified as derivative assets and liabilities. These contracts are not included in the consolidated balance sheet as of December 31, 2005. Minimum purchase commitment obligations under these agreements are as follows as of December 31, 2005 (in millions):

2006		$	161
2007			86
2008			60
2009			54
2010			23
2011 and thereafter			165

	Total	$	549

As of December 31, 2005, the maximum remaining term under any individual fuel supply contract is 15 years.

F-111

(10) Contingencies

Legal and Environmental Matters.

REMA is party to a number of legal, environmental and other proceedings before courts and governmental agencies. Unless otherwise noted, REMA cannot predict the outcome of these proceedings.

New Source Review Matters. The United States Environmental Protection Agency (EPA) and various states are investigating compliance of coal-fueled electric generating stations with the "New Source Review" requirements of the Clean Air Act. The EPA has agreed to share information relating to its investigations with state environmental agencies. In November 2005, REMA received a notice of intent to sue pursuant to the Clean Air Act from the state of New Jersey relating to one of its power plants located in Pennsylvania. The allegations relate to conduct that occurred prior to Reliant Energy's ownership of the power plant. If the state of New Jersey sues REMA and is successful, REMA could incur significant capital expenditures associated with the implementation of emissions reductions on an accelerated basis and possible penalties.

Ash Disposal Site Closures. REMA is responsible for environmental costs related to the future closures of five ash disposal sites. Based on REMA's evaluations with assistance from third-party consultants and engineers, REMA recorded the estimated discounted costs associated with these environmental liabilities as part of its asset retirement obligations. See note 2(n).

Remediation Obligations. REMA is responsible for environmental costs related to site contamination investigations and remediation requirements at four power plants in New Jersey. Based on REMA's evaluations with assistance from third-party consultants and engineers, REMA recorded the estimated liability for the remediation costs of $7 million as of December 31, 2005 and 2004, respectively.

Environmental Class Action. REMA received notice of a class action lawsuit filed in Superior Court in Ontario, Canada in June 2005 against it and approximately 20 other utility and power generation companies alleging various claims relating to environmental emissions from coal-fired power plants in the United States and Canada. The lawsuit alleges damages of approximately $42.1 billion, with continuing damages in the amount of approximately $3.5 billion annually. The lawsuit also claims entitlement to punitive and exemplary damages in the amount of $860 million. REMA converted Canadian dollars to United States dollars using an exchange rate as of December 31, 2005. The complaint was not timely served under Canadian law, but the plaintiffs may ask the court to extend the time of service or they may commence a new lawsuit. REMA does not know whether the plaintiffs will proceed with the lawsuit and are not in a position at this time to assess what impact, if any, an adverse decision might have on its results of operations, financial condition and cash flows; however, REMA is confident that it has operated and continues to operate its coal-fired plants in material compliance with all applicable federal and state environmental regulations.

(11) Settlements and Other Charges

Gain on Sale of Counterparty Claim.

In June 2004, Reliant Energy entered into a settlement agreement with Enron. The settlement agreement provided for the dismissal of all pending litigation between Enron and Reliant Energy and provided for certain allowed bankruptcy claims against Enron. In August 2004, Reliant Energy sold and assigned its claim to a third party. As REMA had previously written off its net receivables and derivative assets from Enron, REMA recognized a $22 million gain upon the sale during the third quarter of 2004.

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(12) Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and payable, derivative assets and liabilities and third-party debt equal their carrying amounts.

(13) Sales of Assets and Emission Allowances

REMA included the following assets in its results of operations through the date of sale.

Two hydropower plants sold for $42 million in April 2005.

Emission Allowances. The sales and purchases of emission allowances are classified as investing activities in the consolidated statements of cash flows. REMA reclassified net purchases of $32 million and $18 million for 2004 and 2003, respectively, from operating to investing cash flows. Net sales proceeds from emission allowances:

	2005			2004		2003
	(in millions)
SO₂⁽¹⁾	$	100	⁽²⁾	$	33	$	10
NO_x⁽³⁾		8	⁽⁴⁾		11		3

	$	108		$	44	$	13

(1): Includes sales to an affiliate during 2005, 2004 and 2003 of $97 million, $0 and $1 million, respectively.
(2): Sold 133,000 tons (which includes 130,000 tons to an affiliate) relating to 2005 through 2009 vintage years.
(3): Includes sales to an affiliate during 2005, 2004 and 2003 of $3 million, $1 million and $0, respectively.
(4): Sold 3,000 tons (which includes 1,000 tons to an affiliate) relating to 2005 vintage year.

During January and February 2006, REMA sold 49,000 tons of emission allowances relating to 2007 through 2009 vintage years for $66 million and recognized a gain of $64 million.

Summary of Gains and Losses.

		2005		2004		2003
		(in millions)
Hydropower plants		$	12	$	—	$	—
Emission allowances⁽¹⁾			97		14		2
Other, net			1		1		—

	Gains on sales of assets and emission allowances, net	$	110	$	15	$	2

(1): For 2004 and 2003, these amounts were previously classified in amortization expense; however, REMA reclassified them to gains on sales of assets and emission allowances, net.

F-113

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Orion Power Holdings, Inc. and Subsidiaries
Houston, Texas

We have audited the accompanying consolidated balance sheets of Orion Power Holdings, Inc. and subsidiaries (the "Company"), as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholder's equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Orion Power Holdings, Inc. and subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in note 2 to the consolidated financial statements, the Company changed its accounting for asset retirement obligations in 2003.

DELOITTE & TOUCHE LLP

Houston, Texas
March 14, 2006

F-114

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Thousands of Dollars, except per share amounts)

			2005			2004			2003
Revenues:
	Revenues		$	91,919		$	463,132		$	477,973
	Revenues—affiliates			548,533			22,924			33,042

		Total		640,452			486,056			511,015
Expenses:
	Fuel and purchased power			186,912			175,733			186,397
	Fuel and purchased power—affiliates			68,272			66,466			28,737
	Operation and maintenance			115,924			127,483			113,209
	Operation and maintenance—affiliates			43,500			29,001			27,620
	Taxes other than income taxes			3,709			17,376			12,539
	General and administrative—primarily affiliates			40,493			58,006			63,144
	Gains on sales of assets and emission allowances, net—primarily affiliates			(58,189	)		(2,355	)		(328	)
	Goodwill impairment			—			—			585,000
	Depreciation and amortization			126,416			114,289			94,723

		Total operating expense		527,037			585,999			1,111,041

Operating Income (Loss)				113,415			(99,943	)		(600,026	)

Other Income (Expense):
	Other, net			42			308			3,740
	Interest expense			(39,949	)		(40,781	)		(40,807	)
	Interest expense—affiliates			(908	)		(1,309	)		—
	Interest income			382			1,875			1,323

		Total other expense		(40,433	)		(39,907	)		(35,744	)

Income (Loss) from Continuing Operations Before Income Taxes				72,982			(139,850	)		(635,770	)
	Income tax expense (benefit)			24,385			(53,008	)		(22,720	)

Income (Loss) from Continuing Operations				48,597			(86,842	)		(613,050	)
	Income (loss) from discontinued operations			(86,096	)		89,299			55,244

Income (Loss) Before Cumulative Effect of Accounting Changes				(37,499	)		2,457			(557,806	)
	Cumulative effect of accounting changes, net of tax			(198	)		—			2,121

Net Income (Loss)			$	(37,697	)	$	2,457		$	(555,685	)

See Notes to the Consolidated Financial Statements

F-115

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, except per share amounts)

			December 31,
			2005			2004
ASSETS
Current Assets:
	Cash and cash equivalents		$	13,752		$	8,469
	Accounts and notes receivable, principally customer, net of allowance of $6 and $174			4,079			53,075
	Receivables from affiliates, net			40,234			—
	State income taxes receivable			18,570			39,365
	Inventory			56,464			51,330
	Derivative assets			22,118			59,610
	Prepayments and other current assets			4,062			1,659
	Current assets of discontinued operations			157,059			97,967

		Total current assets		316,338			311,475

Property, Plant and Equipment, net				1,613,264			1,809,940

Other Assets:
	Goodwill			180,520			291,079
	Other intangibles, net			209,802			248,949
	Derivative assets			6,701			26,090
	Other			64,888			37,895
	Long-term assets of discontinued operations			872,650			1,023,006

		Total other assets		1,334,561			1,627,019

Total Assets			$	3,264,163		$	3,748,434

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
	Current portion of long-term debt and short-term borrowings		$	9,703		$	8,092
	Accounts payable, principally trade			19,533			17,842
	Payables to affiliates, net			—			12,178
	Accrued interest payable			8,000			8,000
	Accumulated deferred income taxes			7,320			18,276
	Other taxes payable			10,679			16,531
	Other			8,110			15,875
	Current liabilities of discontinued operations			49,069			22,609

		Total current liabilities		112,414			119,403

Other Liabilities:
	Accumulated deferred income taxes			174,545			28,826
	Other			53,574			64,320
	Long-term liabilities of discontinued operations			853,997			1,026,925

		Total other liabilities		1,082,116			1,120,071

Revolving Credit Facility with Affiliate				—			7,300

Long-term Debt				439,057			449,589

Commitments and Contingencies
Stockholder's Equity:
	Common stock; par value $1.00 per share (1,000 shares authorized, issued and outstanding)			1			1
	Additional paid-in capital			2,460,551			2,821,552
	Retained deficit			(848,341	)		(810,644	)
	Accumulated other comprehensive income			18,700			44,900
	Accumulated other comprehensive loss of discontinued operations			(335	)		(3,738	)

		Total stockholder's equity		1,630,576			2,052,071

Total Liabilities and Stockholder's Equity			$	3,264,163		$	3,748,434

See Notes to the Consolidated Financial Statements

F-116

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

					2005			2004			2003
Cash Flows from Operating Activities:
	Net income (loss)				$	(37,697	)	$	2,457		$	(555,685	)
	(Income) loss from discontinued operations					86,096			(89,299	)		(55,244	)

	Net income (loss) from continuing operations and cumulative effect of accounting changes					48,399			(86,842	)		(610,929	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Cumulative effect of accounting changes				198			—			(2,121	)
		Goodwill impairment				—			—			585,000
		Depreciation and amortization				126,416			114,289			94,723
		Deferred income taxes				44,581			(196,491	)		82,470
		Non-cash equity contribution of operation and maintenance and general and administrative costs from Reliant Energy, Inc., net				56,890			66,835			69,631
		Net unrealized (gains) losses on energy derivatives				4,846			90			(4,935	)
		Net amortization of contractual rights and obligations				(8,177	)		(29,082	)		(27,001	)
		Amortization of revaluation of acquired debt				(8,921	)		(8,139	)		(7,506	)
		Gains on sales of assets and emission allowances, net — primarily affiliates				(58,189	)		(2,355	)		(328	)
		Federal income tax contributions from (distributions to) Reliant Energy, Inc., net				(26,361	)		150,511			(54,167	)
		Other, net				2,003			99			—
		Changes in other assets and liabilities:
			Accounts receivable, net			48,996			6,222			8,660
			Inventory			(1,853	)		(13,786	)		3,048
			Other current assets			(2,603	)		2,826			(4,782	)
			Other assets			422			(6,108	)		6,247
			Accounts payable			1,644			(6,399	)		(8,028	)
			Payable to/receivable from affiliates, net			(52,412	)		12,435			(8,137	)
			Taxes payable/receivable			1,768			10,210			23,453
			Other current liabilities			(9,881	)		5,648			(16,097	)
			Other liabilities			(5,014	)		10,519			(866	)

				Net cash provided by continuing operations from operating activities		162,752			30,482			128,335
				Net cash provided by discontinued operations from operating activities		171,800			72,440			144,823

				Net cash provided by operating activities		334,552			102,922			273,158

Cash Flows from Investing Activities:
	Capital expenditures					(16,334	)		(28,090	)		(37,444	)
	Proceeds from sales of assets, net					2,372			—			—
	Proceeds from sales of emission allowances					65,073			11,492			2,485
	Purchases of emission allowances					(1,998	)		(38,938	)		(51,009	)
	Restricted cash					—			130,473			27,590

				Net cash provided by (used in) continuing operations from investing activities		49,113			74,937			(58,378	)
				Net cash provided by (used in) discontinued operations from investing activities		79,101			911,227			(63,818	)

				Net cash provided by (used in) investing activities		128,214			986,164			(122,196	)

Cash Flows from Financing Activities:
	Contributions from (distributions to) Reliant Energy, Inc.					(340,000	)		(710,738	)		35,000
	Changes in revolving credit facility with Reliant Energy, Inc., net					(7,300	)		7,300			—

				Net cash provided by (used in) continuing operations from financing activities		(347,300	)		(703,438	)		35,000
				Net cash used in discontinued operations from financing activities		(110,183	)		(410,340	)		(160,166	)

				Net cash used in financing activities		(457,483	)		(1,113,778	)		(125,166	)

Net Change in Cash and Cash Equivalents						5,283			(24,692	)		25,796
Cash and Cash Equivalents at Beginning of Period						8,469			33,161			7,365

Cash and Cash Equivalents at End of Period					$	13,752		$	8,469		$	33,161

Supplemental Disclosure of Cash Flow Information:
	Cash Payments:
		Interest paid (net of amounts capitalized) to third parties for continuing operations			$	48,686		$	48,840		$	48,000
		Income taxes paid (net of income tax refunds received) for continuing operations				3,917			(14,478	)		(59,435	)
	Non-cash Disclosure:
		Contributions from (distributions to) Reliant Energy, Inc., net for continuing operations				(51,471	)		217,346			15,464
		Contributions from (distributions to) Reliant Energy, Inc., net for discontinued operations				30,468			81,603			30,129

See Notes to the Consolidated Financial Statements

F-117

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS)

(Thousands of Dollars)

														Discontinued Operations Accumulated Other Comprehensive Loss
		Common Stock									Accumulated Other Comprehensive Income (Loss)
		Common Stock			Additional Paid-In Capital			Retained Deficit									Total Stockholder's Equity			Comprehensive Income (Loss)
		Shares	Amount		Additional Paid-In Capital			Retained Deficit									Total Stockholder's Equity			Comprehensive Income (Loss)
Balance, December 31, 2002		1,000	$	1	$	3,152,701		$	(257,416	)	$	3,914		$	(27,367	)	$	2,871,833
Net loss									(555,685	)								(555,685	)	$	(555,685	)
Net contributions from stockholder						80,607												80,607
Deferred gain (loss) from cash flow hedges, net of tax of $11 million and $3 million												15,579			(4,814	)		10,765			15,579
Reclassification of net deferred (gain) loss from cash flow hedges, net of tax of $2 million and $8 million												(3,427	)		11,384			7,957			(3,427	)
Other comprehensive income from discontinued operations																					6,570

	Comprehensive loss																			$	(536,963	)

Balance, December 31, 2003		1,000		1		3,233,308			(813,101	)		16,066			(20,797	)		2,415,477
Net income									2,457									2,457		$	2,457
Net dividends to/contributions from stockholder						(411,756	)											(411,756	)
Changes in minimum pension liability, net of tax of $0												(147	)					(147	)		(147	)
Deferred gain from cash flow hedges, net of tax of $50 million and $1 million												69,845			992			70,837			69,845
Reclassification of net deferred (gain) loss from cash flow hedges, net of tax of $29 million and $11 million												(40,864	)		16,067			(24,797	)		(40,864	)
Other comprehensive income from discontinued operations																					17,059

	Comprehensive income																			$	48,350

Balance, December 31, 2004		1,000		1		2,821,552			(810,644	)		44,900			(3,738	)		2,052,071
Net loss									(37,697	)								(37,697	)	$	(37,697	)
Net dividends to/contributions from stockholder						(361,001	)											(361,001	)
Changes in minimum pension liability, net of tax of $0 million
Deferred gain from cash flow hedges, net of tax of $3 million												4,925						4,925			4,925
Reclassification of net deferred (gain) loss from cash flow hedges, net of tax of $22 million and $2 million												(31,125	)		3,403			(27,722	)		(31,125	)
Other comprehensive income from discontinued operations																					3,403

	Comprehensive loss																			$	(60,494	)

Balance, December 31, 2005		1,000	$	1	$	2,460,551		$	(848,341	)	$	18,700		$	(335	)	$	1,630,576

See Notes to the Consolidated Financial Statement

F-118

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Background and Basis of Presentation

Background. "Orion Power Holdings" refers to Orion Power Holdings, Inc., a Delaware corporation. "Orion Power" refers to Orion Power Holdings and its consolidated subsidiaries. "Reliant Energy" refers to Reliant Energy, Inc. and its consolidated subsidiaries. Orion Power owns and operates electric generation facilities in Ohio and Pennsylvania with an aggregate generating capacity of 2,707 megawatts (MW) as of December 31, 2005. Orion Power typically sells its wholesale products to independent system operators, regulated utilities, municipalities, energy supply companies (including Reliant Energy), cooperatives and retail "load" or customer aggregators.

On February 19, 2002, Reliant Energy acquired Orion Power through a merger.

Basis of Presentation. These consolidated statements include all revenues and costs directly attributable to Orion Power including costs for facilities and costs for functions and services performed by Reliant Energy subsequent to the merger and charged to Orion Power. All significant intercompany transactions have been eliminated. Orion Power has reclassified certain amounts from prior periods to conform to the 2005 presentation. These reclassifications had no impact on reported earnings/losses and are described in notes 2(l), 12 and 13.

(2) Summary of Significant Accounting Policies

(a) Use of Estimates and Market Risk and Uncertainties.

Management makes estimates and assumptions to prepare financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) that affect:

•: the reported amount of assets and liabilities,
•: the reported amounts of revenues and expenses and
•: our disclosure of contingent assets and liabilities at the date of the financial statements.

Orion Power's critical accounting estimates include: (a) goodwill, (b) property, plant and equipment, (c) derivative assets and liabilities and (d) deferred tax assets, valuation allowances and tax liabilities. Actual results could differ from the estimates.

Orion Power is subject to various risks inherent in doing business. See notes 2(d), 2(e), 2(h), 2(o), 4, 5, 6, 7, 8, 9 and 10.

(b) Principles of Consolidation.

Orion Power Holdings includes its accounts and those of its wholly-owned subsidiaries in the consolidated financial statements.

(c) Revenues.

Orion Power records gross revenues from the sale of electricity and other energy services under the accrual method. Electric power and other energy services are sold at market-based prices through existing power exchanges, related party affiliates or through third party contracts. Energy sales and services that have been delivered but not billed by period-end are estimated.

F-119

(d) Derivatives and Hedging Activities.

Orion Power accounts for its derivatives instruments and hedging activities in accordance with SFAS No. 133, "Accounting for Derivatives Instruments and Hedging Activities," as amended (SFAS No. 133).

For Orion Power's hedging activities, it uses both derivative and non-derivative contracts that provide for settlement in cash or by delivery of a commodity. The primary types of derivative instruments Orion Power uses are forwards, futures, swaps and options. Orion Power elects one of three accounting methods (cash flow hedge, mark-to-market or accrual accounting) for derivatives based on facts and circumstances. The fair values of derivative activities are determined by (a) prices actively quoted, (b) prices provided by other external sources or (c) prices based on models and other valuation methods.

If certain conditions are met, a derivative instrument may be designated as a cash flow hedge. A derivative is recognized at fair value in the balance sheet whether or not it is designated as a hedge, except for derivative contracts designated as "normal purchases and sales exceptions," which are not in its consolidated balance sheet or results of operations prior to settlement.

Derivatives designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive income (loss), net of tax, to the extent the contracts are effective as hedges, until the forecasted transactions affect earnings. At the time the forecasted transactions affect earnings, Orion Power reclassifies the amounts in other comprehensive income (loss) into earnings. Orion Power records the ineffective portion of changes in fair value of cash flow hedges immediately into earnings. For all other derivatives, changes in fair value are recorded as unrealized gains or losses in its results of operations.

If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in its results of operations. If it becomes probable that a forecasted transaction will not occur, Orion Power immediately recognizes the related deferred gains or losses in its results of operations. The associated hedging instrument is then marked to market through its results of operations for the remainder of the contract term unless a new hedging relationship is redesignated.

Prior to October 1, 2003, Orion Power generally recorded, on a gross basis in the period of delivery (a) sales in revenues and (b) purchases in fuel and purchased power. In July 2003, the EITF issued EITF No 03-11, which states that realized gains and losses on derivatives contracts not "held for trading purposes" should be reported either on a net or gross basis based on the relevant facts and circumstances. EITF No. 03-11 has no impact on margins or net income. Subsequent to October 1, 2003, due to the adoption of EITF No. 03-11, hedging transactions that do not physically flow are

F-120

included the same caption as the items being hedged. A summary of Orion Power's derivative activities and classification in its results of operations is:

Instrument		Purpose for Holding or Issuing Instrument⁽¹⁾		Transactions that Physically Flow		Transactions that Financially Settle⁽²⁾
Power futures, forward, swap and option contracts		Power sales Power purchases		Revenues Fuel and purchased power		Revenues Revenues
Natural gas and fuel futures, forward, swap and option contracts		Natural gas and fuel sales Natural gas and fuel purchases		Revenues Fuel and purchased power		Fuel and purchased power Fuel and purchased power

(1): The purpose for holding or issuing is not impacted by the accounting method elected for each instrument.
(2): Includes classification for mark-to-market derivatives and amounts reclassified from accumulated other comprehensive income (loss) related to cash flow hedges.

In addition to market risk, Orion Power is exposed to credit and operational risk. Reliant Energy has a control framework, to which Orion Power is subject, to manage these risks, which include: (a) measuring and monitoring these risks, (b) review and approval of new transactions relative to these risks, (c) transaction validation and (d) portfolio valuation and reporting. Orion Power uses mark-to-market valuation, value-at-risk and other metrics in monitoring and measuring risk. Reliant Energy's risk control framework includes a variety of separate but complementary processes, which involve commercial and senior management and Reliant Energy's Board of Directors. See note 2(e) for further discussion of Orion Power's credit policy.

Set-off of Derivative Assets and Liabilities. Where derivative instruments are subject to a master netting agreement and the accounting criteria to net are met, Orion Power presents its derivative assets and liabilities on a net basis. Derivative assets/liabilities and accounts receivable/payable are presented and set-off separately in the consolidated balance sheets although in most cases contracts permit the set-off of derivative assets/liabilities and accounts receivable/payable with a given counterparty.

(e) Credit Risk.

Orion Power has a credit policy that governs management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. Credit risk is monitored daily and the financial condition of counterparties is reviewed periodically. Orion Power tries to mitigate credit risk by entering into contracts that permit netting and allow it to terminate upon the occurrence of certain events of default. Orion Power measures credit risk as the replacement cost for its derivative positions plus amounts owed for settled transactions.

As of December 31, 2005, three non-investment grade counterparties represented 93% ($32 million) of Orion Power's credit exposure, net of collateral. As of December 31, 2004, four non-investment grade counterparties represented 81% ($112 million) of Orion Power's credit exposure, net of collateral. There were no other counterparties representing greater than 10% of Orion Power's credit exposure, net of collateral.

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(f) Customer Concentration.

The following table represents third party customers who contributed in excess of 10% of the consolidated revenues for 2005, 2004 or 2003 (in millions, except percentages):

		2005					2004					2003
Customer		Revenue			Percentage of Total Revenue		Revenue			Percentage of Total Revenue		Revenue			Percentage of Total Revenue
Duquesne Light Company		$	—		—	%	$	378		78	%	$	391		76	%

The following table represents accounts receivable balances from third party customers in excess of 10% of the total consolidated accounts receivable balance and the related percentages as of December 31, 2005 and 2004 (in millions, except percentages):

	December 31,
	2005				2004
Customer	Accounts Receivable Balance		Percentage of Total Accounts Receivable		Accounts Receivable Balance		Percentage of Total Accounts Receivable
Duquesne Light Company	$	1	23	%	$	47	89	%
Exelon Generating Company		1	33	%		—	—	%

See note 3 for transactions with affiliates.

(g) General and Administrative Expenses.

(h) Property, Plant and Equipment and Depreciation Expense.

Orion Power computes depreciation using the straight-line method based on estimated useful lives. Depreciation expense was $95 million, $78 million and $74 million during 2005, 2004 and 2003, respectively.

			December 31,
		Estimated Useful Lives (Years)	December 31,
		Estimated Useful Lives (Years)	2005			2004
			(in millions)
Electric generation facilities		10 - 35	$	1,757		$	1,895
Land improvements		20 - 35		96			101
Other		3 - 10		8			8
Land				12			11
Assets under construction				8			4

	Total			1,881			2,019
Accumulated depreciation				(268	)		(209	)

	Property, plant and equipment, net		$	1,613		$	1,810

Orion Power periodically evaluates property, plant and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. Orion Power recorded no material property, plant and equipment impairments during 2005, 2004 and 2003.

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In the future, Orion Power could recognize impairments if its wholesale energy market outlook changes negatively. In addition, Orion Power's ongoing evaluation of its business could result in decisions to mothball, retire or dispose of additional generation assets, any of which could result in impairment charges.

(i) Intangible Assets and Amortization Expense.

Goodwill. Orion Power performs its goodwill impairment test annually and when events or changes in circumstances indicate that the carrying value may not be recoverable. Orion Power previously selected November 1 as its annual goodwill impairment testing date since Reliant Energy had historically completed its annual strategic planning process by that date. Reliant Energy has since modified its strategic planning process, which provides key information used in the analysis of Orion Power's goodwill impairment test, and such information is no longer completed by November 1. In order to align Orion Power's annual goodwill impairment test with Reliant Energy's annual strategic planning process, to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in 2005, Orion Power changed the date on which it performs the annual goodwill impairment test to April 1. The change is not intended to delay, accelerate or avoid an impairment charge. Orion Power believes that this accounting change is to an alternative accounting principle that is preferable under the circumstances.

Other Intangibles. Orion Power recognizes specifically identifiable intangible assets, including emission allowances and contractual rights, when specific rights and contracts are acquired. Orion Power has no intangible assets with indefinite lives recorded as of December 31, 2005 and 2004.

(j) Income Taxes.

Orion Power is included in the consolidated income tax returns of Reliant Energy and calculates its income tax provision on a separate return basis, whereby Reliant Energy pays all federal income taxes on Orion Power's behalf and is entitled to any related tax savings. The difference between Orion Power's current federal income tax expense or benefit, as calculated on a separate return basis, and related amounts paid or received to/from Reliant Energy, if any, are recorded in Orion Power's financial statements as adjustments to additional paid-in capital on its consolidated balance sheets. Deferred income taxes reflected on Orion Power's consolidated balance sheet will ultimately be settled with Reliant Energy through additional paid-in capital. See notes 3 and 8.

(k) Cash and Cash Equivalents.

Orion Power records all highly liquid short-term investments with maturities of three months or less as cash equivalents.

(l) Restricted Cash.

Restricted cash included cash at certain subsidiaries, the distribution or transfer of which was restricted by financing and other agreements. In the consolidated statements of cash flows for 2004 and 2003, Orion Power reclassified $198 million and $2 million, respectively, from operating cash flows to investing cash flows relating to changes in restricted cash for continuing and discontinued operations.

(m) Allowance for Doubtful Accounts.

Orion Power accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings, historical collections, accounts receivable agings and other factors. Orion Power writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.

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(n) Inventory.

Orion Power values inventories used in the production of electricity at the lower of average cost or market.

		December 31,
		2005		2004
		(in millions)
Materials and supplies, including spare parts		$	17	$	17
Coal			38		33
Heating oil			1		1

	Total inventory	$	56	$	51

(o) Environmental Costs.

Orion Power expenses environmental expenditures related to existing conditions that do not have future economic benefit. Orion Power capitalizes environmental expenditures for which there is a future economic benefit. Orion Power records liabilities for expected future costs, on an undiscounted basis, related to environmental assessments and/or remediation when they are probable and can be reasonably estimated. See note 10.

(p) Asset Retirement Obligations.

Orion Power's asset retirement obligations relate to future costs associated primarily with ash disposal site closures. Orion Power's asset retirement obligation was $5 million and $3 million as of December 31, 2005 and 2004, respectively.

During 2005, Orion Power adopted an accounting interpretation relating to asset retirement obligations. This interpretation clarifies that an asset retirement obligation is unconditional even though uncertainty exists about the timing and/or method of settlement and requires that a liability be recognized if it can be reasonably estimated. Based on this, Orion Power (a) recorded a cumulative effect of an accounting change, net of tax, of $198,000, (b) increased other long-term liabilities by $624,000, (c) increased property, plant and equipment by $317,000 and (d) decreased deferred income tax liabilities by $109,000.

(q) Repair and Maintenance Costs for Power Generation Assets.

Orion Power recognizes repair and maintenance costs as incurred.

(3) Related Party Transactions

These financial statements include significant transactions between Orion Power and Reliant Energy. The majority of these transactions involve the purchase or sale of energy, capacity, fuel, emission allowances or related services (including transportation, transmission and storage services) from or to Orion Power and allocations of costs to Orion Power for certain support services. The following describes the impacts on the financial statements for the particular transactions:

Support and Technical Services. Reliant Energy provides commercial support, technical services and other corporate services to Orion Power. During 2003 and 2004, Reliant Energy allocated certain support services costs to Orion Power based on Orion Power's direct labor costs relative to the direct

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labor costs of other entities to which Reliant Energy provided similar services and charged for certain other services based on usage. Effective January 2005, Reliant Energy began allocating certain support services costs to Orion Power based on Orion Power's underlying planned operating expenses relative to the underlying planned operating expenses of other entities to which Reliant Energy provides similar services and also continued charging Orion Power for certain other services based on usage. Management believes these methods of allocation were reasonable and did not yield significantly different results between the two methodologies. These allocations and charges were not necessarily indicative of what would have been incurred had Orion Power been an unaffiliated entity. During 2003 and 2004, Orion Power Midwest, L.P. (Orion MidWest) and Orion Power New York, L.P. (Orion New York), subsidiaries of Orion Power Holdings, paid only a certain amount for these services due to contractual restrictions set forth in the then-existing credit agreements to which they were parties. During 2005, Orion Power only paid a certain amount for these services.

During 2005, 2004 and 2003, $84 million, $87 million and $90 million, respectively, was allocated or charged to Orion Power for these services and recorded as operation and maintenance—affiliates and general and administrative—affiliates. Of these amounts, unpaid allocations and charges of $57 million, $67 million and $70 million for 2005, 2004 and 2003, respectively, were recorded as non-cash equity contributions from Reliant Energy.

Commodity Procurement and Marketing. Reliant Energy provides support and commodity procurement and marketing services to Orion Power. Purchases from Reliant Energy under various commodity agreements, recorded in fuel and purchased power—affiliates, were $68 million, $66 million and $29 million during 2005, 2004 and 2003, respectively. Orion Power was party to a significant supply agreement with a third party that expired December 31, 2004. Thus, beginning in 2005, Orion Power began selling the majority of its power to Reliant Energy. Sales to Reliant Energy under various commodity agreements, recorded in revenue—affiliates, were $548 million, $23 million and $33 million during 2005, 2004 and 2003, respectively. During 2005 and 2004, Orion Power sold coal to Reliant Energy for $12 million and $9 million, respectively, which reflected the market price of coal at the sale dates. This resulted in gains during 2005 and 2004 of $6 million and $4 million, respectively, for Orion Power, which are recorded in fuel and purchased power—affiliates. During 2005, 2004 and 2003, Orion Power sold emission allowances to Reliant Energy for $56 million, $2 million and $0, respectively at market prices and recognized gains of $53 million and $0 during 2005 and 2004, respectively, (recorded in gains on sales of assets and emission allowances, net). Reliant Energy purchased the emission allowances from Orion Power at the same price for which it sold them to third parties. See notes 4(b) and 12.

Debt Obligations to Reliant Energy. In December 2004, Orion MidWest entered into the following with Reliant Energy: (a) two related-party notes for a total of $400 million and (b) a $75 million revolving credit facility. In December 2004, Orion New York entered into the following with Reliant Energy: (a) a related-party note for $400 million and (b) a $50 million revolving credit facility. The Orion MidWest and Orion New York related party notes bear interest at 6.5% per year and interest is payable monthly. The revolving credit facilities bear interest at London Inter Bank Offering Rate (LIBOR) plus 2.875%. Certain of these amounts have been classified as discontinued operations; see note 13. The Orion MidWest revolving credit facility matures in December 2006; however, Reliant Energy plans to extend the maturity each December for 12 months from that date.

Distributions to Reliant Energy. During 2005, Orion Power Holdings made $340 million in distributions to Reliant Energy related to cash from its business operations. In December 2004, Orion Power Holdings distributed $718 million of cash to Reliant Energy in connection with Reliant Energy's December 2004 refinancing. See above for discussion of the $800 million that Orion Power borrowed from Reliant Energy.

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Interest on Orion Power Holdings Senior Notes. In May 2003 and November 2003, Reliant Energy contributed $15 million and $20 million, respectively, to Orion Power Holdings, as a partial funding of interest payments of $24 million on the senior notes due at those dates.

Income Taxes. During 2005, 2004 and 2003, Orion Power recorded $(78) million (of which $82 million related to changes in estimates of deferred tax assets and liabilities), $155 million and $(24) million, respectively, in non-cash contributions from (distributions to) Reliant Energy related to federal income taxes for continuing and discontinued operations. In addition, during 2004, Orion Power Holdings distributed deferred income tax liabilities of $77 million to Reliant Energy due to the capital gain for federal income tax purposes recognized in connection with the sale of the hydropower plants.

(4) Intangible Assets

(a) Goodwill.

The following table shows goodwill and the changes (in millions):

As of January 1, 2004		$	395
	Transfer to discontinued operations⁽¹⁾		(104	)

As of December 31, 2004			291
	Transfer to discontinued operations⁽²⁾		(102	)
	Other⁽³⁾		(8	)

As of December 31, 2005		$	181

(1): Goodwill related to the hydropower plants. See note 13.
(2): Goodwill related to the Ceredo plant ($10 million) and New York plants ($92 million). See note 13.
(3): Goodwill related to revisions to the Orion Power purchase price allocation for tax matters.

As of December 31, 2005 and 2004, Orion Power had $44 million and $48 million, respectively, of goodwill that is deductible for United States income tax purposes for future periods.

July 2003 Goodwill Impairment Test. The July 2003 sale of Reliant Energy's Desert Basin plant required Orion Power to perform a goodwill impairment test.

As a result of this test, Orion Power recognized an impairment of $585 million (pre-tax and after-tax) in the third quarter of 2003. This impairment was due to a decrease in the estimated fair value primarily attributable to: (a) reduced projected commercialization opportunities related to its power generation assets; (b) lower projected regulatory capacity values due to the lack of development of appropriate market structures and a lower outlook for revenues from existing regulatory capacity markets; (c) reduced long-term margins from its existing portfolio as a result of lowering estimates of the margins required to induce new capacity to enter the markets; (d) lower market and comparable public company values data; and (e) the level of working capital; partially offset by reductions in projected commercial, operational and support groups costs and lower projected operations and maintenance expense.

Additional Goodwill Impairment Tests. In addition to the July 2003 goodwill impairment test, Orion Power performed impairment tests at the following dates: November 2003, May 2004, November 2004, April 2005, August 2005 and September 2005 due to either asset sales or the annual impairment tests. No impairments were indicated in these tests.

Estimation of Fair Value. Orion Power estimates the fair value based on a number of subjective factors, including: (a) appropriate weighting of valuation approaches (income approach, market approach and comparable public company approach), (b) projections about future power generation

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margins, (c) estimates of future cost structure, (d) discount rates for estimated cash flows, (e) selection of peer group companies for the public company approach, (f) required level of working capital, (g) assumed terminal value and (h) time horizon of cash flow forecasts.

Management has determined the fair value with the assistance of an independent appraiser. In determining the fair value, Orion Power made the following key assumptions: (a) the markets in which Orion Power operates will continue to be deregulated; (b) there will be a recovery in electricity margins over time such that companies building new generation facilities can earn a reasonable rate of return on their investment and (c) the economics of future construction of new generation facilities will likely be driven by integrated utilities. As part of the process, Orion Power modeled all of its power generation facilities and those of others in the regions in which Orion Power operates. The assumptions for each of the goodwill impairment tests during 2003, 2004 and 2005 were:

Number of years used in internal cash flow analysis	15
EBITDA⁽¹⁾ multiple for terminal values	7.5
Risk-adjusted discount rate for Orion Power's estimated cash flows	9.0	%
Approximate average anticipated growth rate for demand in power	2.0	%
Long-term after-tax return on investment for new investment	7.5	%

(1): Defined as earnings (loss) before interest expense, interest income, income taxes, depreciation and amortization expenses.

(b) Other Intangibles.

As part of Orion Power's effort to operate its business efficiently, Orion Power concluded that since its generating assets dispatch based on market prices, it should maintain an emission allowances inventory that corresponds with forward power sales. Orion Power plans to sell some excess emission allowances inventory if the price is equal to or above its fundamental view.

				December 31,
		Remaining Weighted Average Amortization Period (Years)		2005					2004
		Remaining Weighted Average Amortization Period (Years)		Carrying Amount		Accumulated Amortization			Carrying Amount		Accumulated Amortization
				(in millions)
SO₂ emission allowances⁽¹⁾⁽²⁾		—	⁽¹⁾	$	131	$	(62	)	$	133	$	(48	)
NO_x emission allowances⁽¹⁾⁽³⁾		—	⁽¹⁾		185		(45	)		190		(27	)
Contractual rights⁽⁴⁾		1			4		(3	)		4		(3	)

	Total			$	320	$	(110	)	$	327	$	(78	)

(1): SO₂ is sulfur dioxide and NO_x is nitrogen oxide. Amortized to amortization expense on a units-of-production basis. As of December 31, 2005, we have recorded (a) SO₂ emission allowances through the 2039 vintage year and (b) NO_x emission allowances through the 2039 vintage year.
(2): During 2005, 2004 and 2003, we purchased $0, $2 million and $24 million, respectively, of SO₂ emission allowances. See note13 for sales.
(3): During 2005, 2004 and 2003, we purchased $2 million, $37 million and $27 million, respectively, of NO_x emission allowances. See note13 for sales.
(4): Amortized to revenues and fuel expense, as applicable, based on the estimated realization of the fair value established on the acquisition date over the contractual lives.

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Amortization expense consists of:

		2005			2004			2003
		(in millions)
Emission allowances		$	31		$	36		$	21

Contractual rights		$	(1	)	$	(1	)	$	(1	)
Contractual obligations⁽¹⁾			9			30			28

	Net	$	8		$	29		$	27

(1): Contractual obligations are in other long-term liabilities.

Estimated amortization expense, based on Orion Power's intangibles as of December 31, 2005, excluding contractual rights and obligations, for the next five years is (in millions):

2006	$	24
2007		15
2008		5
2009		7
2010		7

(5) Derivatives and Hedging Activities

Orion Power uses derivative instruments to manage operational or market constraints and to increase return on its generation assets. The instruments used are fixed-price derivative contracts to hedge the variability in future cash flows from forecasted sales of power and purchases of fuel and power. Orion Power's objective in entering into these fixed-price derivatives is to fix the price for a portion of these transactions. See note 2(d).

Orion Power's derivative portfolio, excluding cash flow hedges, is $0 and $5 million (net asset) as of December 31, 2005 and 2004, respectively. Orion Power's cash flow hedges are valued at $29 million (net asset) and $77 million (net asset) as of December 31, 2005 and 2004, respectively.

During 2005, 2004 and 2003, there was no hedge ineffectiveness recognized from derivatives that are designated and qualify as cash flow hedges. In addition, no component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness for these periods. If it becomes probable that an anticipated transaction will not occur, Orion Power realizes in net income (loss) the deferred gains and losses recognized in accumulated other comprehensive loss. During 2005, 2004 and 2003, $0, $16 million gain and $0, respectively, were recognized in the results of continuing operations as a result of the discontinuance of cash flow hedges because it was probable that the forecasted transaction would not occur.

As of December 31, 2005 and 2004, the maximum length of time Orion Power is hedging its exposure to the variability in future cash flows that may result from changes in commodity prices is two years and three years, respectively. As of December 31, 2005, $15 million of accumulated other comprehensive loss is expected to be reclassified into the results of operations during the next 12 months. However, the actual amount reclassified into earnings could vary from the amounts recorded as of December 31, 2005, due to future changes in market prices.

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(6) Debt

As of December 31, 2005, Orion Power was in compliance with all of its debt covenants. Outstanding debt is:

		December 31,
		2005					2004
		Weighted Average Stated Interest Rate⁽¹⁾	Long-term		Current		Weighted Average Stated Interest Rate⁽¹⁾	Long-term		Current
		(in millions, except interest rates)
Orion Power Holdings senior notes due 2010 (unsecured)		12.00	$	400	$	—	12.00	$	400	$	—
Adjustment to fair value of debt⁽²⁾				39		9			49		8

	Total debt		$	439	$	9		$	449	$	8

(1): The weighted average stated interest rates are for borrowings outstanding as of December 31, 2005 or 2004.
(2): Debt and interest rate swaps acquired by Reliant Energy in the Orion Power acquisition were adjusted to fair market value as of the acquisition date. Included in interest expense is amortization of $9 million, $9 million and $8 million for valuation adjustments for debt for 2005, 2004 and 2003, respectively.

Debt maturities as of December 31, 2005 are (in millions):

2006	$	—
2007		—
2008		—
2009		—
2010		400
2011 and thereafter		—

	$	400

Orion Power Holdings Senior Notes. These notes were recorded at a fair value of $479 million upon the acquisition by Reliant Energy. The $79 million premium is being amortized to interest expense over the life of the notes. The senior notes are senior unsecured obligations of Orion Power Holdings, are not guaranteed by any of Orion Power Holdings' subsidiaries and are non-recourse to Reliant Energy. The senior notes have covenants that restrict (subject to certain exceptions) the ability of Orion Power Holdings and certain of its subsidiaries to, among other actions, (a) pay dividends, (b) incur indebtedness or issue preferred stock, (c) make investments, (d) divest assets, (e) encumber its assets, (f) enter into transactions with affiliates, (g) engage in unrelated businesses and (h) engage in sale and leaseback transactions. As of December 31, 2005, conditions under these covenants have been met that allow the payment of dividends. Orion Power expects that after the closing of the sale of the New York plants, which occurred in February 2006, Orion Power Holdings' dividends to Reliant Energy may be partially restricted.

See note 3 for debt transactions with affiliates.

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(7) Benefit Plans

(a) Pension and Postretirement Benefits.

Benefit Plans. Orion Power sponsors multiple defined benefit pension plans. Orion Power provides subsidized postretirement benefits to some bargaining employees but generally does not provide them to non-bargaining employees.

Orion Power uses a December 31 measurement date for its plans. The benefit obligations and funded status are:

			Pension						Postretirement Benefits
			2005			2004			2005			2004
			(in millions)
Change in Benefit Obligation
	Beginning of year		$	41		$	34		$	24		$	22
	Service cost			2			3			1			1
	Interest cost			2			2			1			1
	Curtailments and benefits enhancement			—			(4	)		—			—
	Benefits paid			(1	)		—			—			—
	Plan amendments			—			8			—			(2	)
	Actuarial (gain) loss			8			(2	)		2			2

		End of year	$	52		$	41		$	28		$	24

Change in Plan Assets
	Beginning of year		$	22		$	16		$	—		$	—
	Employer contributions			8			4			—			—
	Benefits paid			(1	)		—			—			—
	Actual investment return			1			2			—			—

		End of year	$	30		$	22		$	—		$	—

Reconciliation of Funded Status
	Funded status		$	(22	)	$	(19	)	$	(28	)	$	(24	)
	Unrecognized prior service cost			8			9			(2	)		(2	)
	Unrecognized actuarial loss			10			2			—			(3	)

		Net amount recognized	$	(4	)	$	(8	)	$	(30	)	$	(29	)

Effective January 2005, some bargaining and non-bargaining employees no longer accrue benefits under any defined benefit pension plan. This curtailment resulted in a $4 million decrease in the pension benefit obligation during 2004. In addition, during 2004, Orion Power made design changes in the benefit formula for some bargaining employees. Some non-bargaining employees whose pension benefits were frozen received an additional benefit. These plan amendments resulted in an $8 million increase in the pension benefit obligation during 2004.

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Amounts recognized in the consolidated balance sheets are:

		Pension						Postretirement Benefits
		December 31,						December 31,
		2005			2004			2005			2004
		(in millions)
Accrued benefit cost		$	(10	)	$	(14	)	$	(30	)	$	(29	)
Intangible asset			6			6			—			—

	Net amount recognized	$	(4	)	$	(8	)	$	(30	)	$	(29	)

The accumulated benefit obligation for all defined benefit pension plans was $47 million and $37 million as of December 31, 2005 and 2004, respectively. All pension plans have accumulated benefit obligations in excess of plan assets.

Net benefit costs are:

		Pension									Postretirement Benefits
		2005			2004			2003			2005		2004		2003
		(in millions)
Service cost		$	2		$	3		$	2		$	1	$	1	$	1
Interest cost			2			2			2			1		1		1
Expected return on plan assets			(1	)		(1	)		(1	)		—		—		—
Net amortization			1			1			1			—		—		—

	Net benefit cost	$	4		$	5		$	4		$	2	$	2	$	2

Assumptions. The significant weighted average assumptions used to determine the benefit obligations are:

	Pension				Postretirement Benefits
	December 31,				December 31,
	2005		2004		2005		2004
Discount rate	5.75	%	5.75	%	5.75	%	5.75	%
Rate of increase in compensation levels	3.0	%	3.0	%	3.0	%	3.0	%

The significant weighted average assumptions used to determine the net benefit costs are:

	Pension						Postretirement Benefits
	2005		2004		2003		2005		2004		2003
Discount rate	5.75	%	6.25	%	6.75	%	5.75	%	6.25	%	6.75	%
Rate of increase in compensation levels	3.0	%	4.5	%	4.5	%	3.0	%	4.5	%	4.5	%
Expected long-term rate of return on assets	7.5	%	7.5	%	8.5	%	N/A		N/A		N/A

As of December 31, 2005 and 2004, Orion Power developed its expected long-term rate of return on pension plan assets based on third party models. These models consider expected inflation, current dividend yields, expected corporate earnings growth and risk premiums based on the expected volatility of each asset category. Orion Power weights the expected long-term rates of return for each asset category to determine its overall expected long-term rate of return on pension plan assets. In addition, Orion Power reviews peer data and historical returns.

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Orion Power's assumed health care cost trend rates used to measure the expected cost of benefits covered by its postretirement plan are:

	2005		2004		2003
Health care cost trend rate assumed for next year	9.0	%	9.75	%	10.5	%
Rate to which the cost trend rate is assumed to gradually decline	5.5	%	5.5	%	5.5	%
Year that the rate reaches the rate to which it is assumed to decline	2011		2011		2011

Assumed health care cost trend rates can have a significant effect on the amounts reported for Orion Power's health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects as of December 31, 2005:

	One-Percentage Point
	Increase		Decrease
	(in millions)
Effect on service and interest cost	$	—	$	—
Effect on accumulated postretirement benefit obligation		3		(3	)

Plan Assets. Orion Power's pension weighted average asset allocations and target allocation by asset category are:

		Percentage of Plan Assets as of December 31,				Target Allocation
		2005		2004		2006
Domestic equity securities		50	%	55	%	50	%
International equity securities		11		15		10
Global equity securities		10		—		10
Debt securities		29		30		30

	Total	100	%	100	%	100	%

In managing the investments associated with the pension plans, Orion Power's objective is to exceed, on a net-of-fee basis, the rate of return of a performance benchmark composed of the following indices:

Asset Class		Index	Weight
Domestic equity securities		Wilshire 5000 Index	50	%
International equity securities		MSCI All Country World Ex-U.S. Index	10
Global equity securities		MSCI All Country World Index	10
Debt securities		Lehman Brothers Aggregate Bond Index	30

	Total		100	%

As a secondary measure, Orion Power compares asset performance to the returns of a universe of comparable funds, where applicable, over a full market cycle. Reliant Energy's Benefits Committee reviews plan asset performance each quarter by comparing the actual quarterly returns of each asset class to its related benchmark. Orion Power's plan assets have generally performed in accordance with the benchmarks.

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Cash Obligations. Orion Power expects pension cash contributions to approximate $1 million during 2006. Expected benefit payments for the next ten years, which reflect future service as appropriate, are (in millions):

	Pension		Postretirement Benefits
2006	$	1	$	—
2007		1		1
2008		1		1
2009		2		1
2010		2		2
2011-2015		16		10

(b) Savings Plan.

Orion Power has an employee savings plan under Section 401(a) of the Internal Revenue Code. Under the plan, participating employees may contribute a portion of their compensation generally up to a maximum of 18% pre-tax or after-tax. Bargaining employees contribute based on their respective agreements. Orion Power's savings plan benefit expense, including matching and discretionary contributions, was $1 million during 2005, 2004 and 2003.

(c) Other Employee Matters.

As of December 31, 2005, approximately 70% of Orion Power's employees are subject to collective bargaining arrangements. Orion Power's collective bargaining arrangements expire at various intervals beginning in 2008.

(8) Income Taxes

Orion Power's income tax expense (benefit) is:

			2005			2004			2003
			(in millions)
Current:
	Federal		$	(26	)	$	150		$	(99	)
	State			6			(7	)		(6	)

		Total current		(20	)		143			(105	)

Deferred:
	Federal			57			(202	)		82
	State			(13	)		6			—

		Total deferred		44			(196	)		82

Income tax expense (benefit) from continuing operations			$	24		$	(53	)	$	(23	)

Income tax expense from discontinued operations			$	6		$	67		$	25

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A reconciliation of the federal statutory income tax rate to the effective income tax rate is:

			2005			2004			2003
			(in millions)
Income (loss) from continuing operations before income taxes			$	73		$	(140	)	$	(636	)
Federal statutory rate				35	%		35	%		35	%

Income tax expense (benefit) at statutory rate				26			(49	)		(223	)

Net addition (reduction) in taxes resulting from:
	State income taxes, net of federal income taxes			(4	)		(1	)		(4	)
	Goodwill impairment			—			—			205
	Other, net			2			(3	)		(1	)

		Total		(2	)		(4	)		200

Income tax expense (benefit) from continuing operations			$	24		$	(53	)	$	(23	)

Effective rate				33	%		38	%		NM	⁽¹⁾

(1): Not meaningful. The primary reason is due to the goodwill impairment of $585 million, for which no tax benefit can be recognized as the goodwill is non-deductible.

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Deferred tax assets and liabilities are:

			December 31,
			2005			2004
			(in millions)
Deferred tax assets:
Current:
	Employee benefits		$	—		$	1
	Other			5			4

		Total current deferred tax assets		5			5

Non-current:
	Employee benefits			17			15
	State tax credit carryforwards			17			12
	Net operating loss carryforwards			8			30
	Environmental reserves			2			3
	Other			19			14
	Valuation allowance			(24	)		(25	)

		Total non-current deferred tax assets		39			49

		Total deferred tax assets	$	44		$	54

Deferred tax liabilities:
Current:
	Derivative assets, net		$	10		$	22
	Other			2			—

		Total current deferred tax liabilities		12			22
Non-current:
	Depreciation and amortization			187			42
	Derivative assets, net			4			7

		Total non-current deferred tax liabilities		191			49

		Total deferred tax liabilities	$	203		$	71

		Accumulated deferred income taxes, net	$	(159	)	$	(17	)

Tax Attribute Carryovers. Tax attribute carryovers are:

		December 31, 2005		Statutory Carryforward Period	Expiration Year(s)
		(in millions)		(in years)
Net Operating Loss Carryforwards:
	State	$	129	5 to 20	2007 through 2025
State Tax Credit Carryforwards:		$	26	5	2006 through 2010

Valuation Allowances. Orion Power's valuation allowances decreased $1 million during 2005, decreased $16 million during 2004 and increased $6 million during 2003. These changes primarily result from actual transactions that either decrease the likelihood that Orion Power's tax assets will be realized to a level that is below "more likely than not" or that allow Orion Power to use a tax asset that was previously subject to a valuation allowance. Such changes also reflect an ongoing assessment of Orion Power's future ability to use state tax net operating losses and other tax assets. These assessments included an evaluation of Orion Power's recent history of earnings and losses (as adjusted),

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future reversals of temporary differences and identification of other sources of future taxable income, including the identification of tax planning strategies. Orion Power monitors these factors quarterly and there is no assurance that these factors will continue to support a conclusion that the ultimate realization of any particular deferred tax asset is more likely than not.

The changes are:

		2005			2004			2003
		(in millions)
State net operating loss carryforwards		$	(6	)	$	(21	)	$	4
Other, net			5			5			2

	Net change	$	(1	)	$	(16	)	$	6

Tax Contingencies. Reliant Energy's income tax returns, including years when it was included in CenterPoint Energy Inc.'s consolidated tax group, for the 1997 to 2004 tax reporting periods are under audit by federal and state taxing authorities. These audits may result in additional taxes or revisions of the timing of tax payments. As Orion Power is a part of the consolidated income tax returns of Reliant Energy, it could be subject to additional taxes. Orion Power evaluates the need for contingent tax liabilities on a quarterly basis and records any estimable and probable tax exposures in its results of operations. In addition, Orion Power discloses any material tax contingencies as to which it believes there is a reasonable possibility of a future tax assessment.

As of December 31, 2005 and 2004, Orion Power has accrued contingent state tax reserves related to its continuing operations of $3 million and $8 million, respectively. These reserve balances are primarily classified in other long-term liabilities. Orion Power does not believe these contingencies will be resolved within the next 12 months.

Empire Zone Tax Credits. Certain of Orion Power's New York operations qualify for the Empire Zone program. The benefits under the program include a New York state income tax reduction credit, a wage tax credit, a sales tax credit and a real property tax credit. All credits are used to offset New York state income tax with any excess credits being refundable. Under current law, Orion Power is entitled to program benefits for a 14-year period, which began in 2001 and ends in 2014. The impacts to income tax expense relating to empire zone tax credits have been included in discontinued operations. However, as of December 31, 2005 and 2004, Orion Power has $52 million and $39 million, respectively, included in state income taxes receivable and other long-term assets from continuing operations as Orion Power expects to receive the related refunds.

(9) Commitments

(a) Leases.

Operating Lease Expense. Total lease expense for all operating leases was $1 million, $2 million and $2 million during 2005, 2004 and 2003, respectively.

(b) Guarantees.

Equity Pledged as Collateral to Reliant Energy. Orion Power Holdings' equity is pledged as collateral under certain of Reliant Energy's credit and debt agreements, which have an outstanding balance from continuing operations of $3.6 billion as of December 31, 2005.

Interests Pledged as Collateral to Reliant Energy. In connection with Orion Power borrowing debt from Reliant Energy (as discussed in note 3), Orion Power Holdings has pledged its interests in Orion Power Capital, LLC, and its subsidiaries, including Orion New York and Orion MidWest, to Reliant Energy under these notes. In connection with the sale of the New York plants, certain of these interests have been released.

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Other. Orion Power enters into contracts that include indemnification and guarantee provisions. In general, Orion Power enters into contracts with indemnities for matters such as breaches of representations and warranties and covenants contained in the contract and/or against certain specified liabilities. Examples of these contracts include asset sales agreements, service agreements and procurement agreements.

Orion Power is unable to estimate its maximum potential exposure under these provisions until an event triggering payment under these provisions occurs. Based on current information, Orion Power considers the likelihood of making any material payments under these provisions to be remote.

(c) Collateral Posting Provided by Reliant Energy.

As a result of credit rating downgrades, collateral requirements, which are based on a contractual provision relating to creditworthiness and market exposure, were triggered pursuant to a provision in a power contract between Orion MidWest and one of its customers, which required Orion Power to provide collateral of approximately $16 million. In July 2003, Reliant Energy posted this collateral, which is not outstanding as of December 31, 2005, on Orion MidWest's behalf. In connection with Reliant Energy's refinancing in December 2004, Orion MidWest terminated its existing revolving credit facility and transferred the letters of credit outstanding under that facility to Reliant Energy. As of December 31, 2005 and 2004, Reliant Energy had posted $3 million and $22 million, respectively, in collateral on behalf of Orion MidWest. There is no obligation by Orion MidWest to repay this collateral to Reliant Energy.

(d) Other Commitments.

Fuel Supply Commitments. Orion Power is a party to fuel supply contracts of various quantities and durations that are not classified as derivative assets and liabilities. These contracts are not included in the consolidated balance sheet as of December 31, 2005. Minimum purchase commitment obligations under these agreements are as follows as of December 31, 2005 (in millions):

2006		$	112
2007			57
2008			—
2009			—
2010			—
2011 and thereafter			—

	Total	$	169

As of December 31, 2005, the maximum remaining term under any individual fuel supply contract is two years.

(10) Contingencies

Legal and Environmental Matters.

Orion Power is a party to a number of legal, environmental and other proceedings before courts and governmental agencies. Unless otherwise noted, Orion Power cannot predict the outcome of these proceedings.

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Ash Disposal Site Closures. Orion Power is responsible for environmental costs related to the future closures of two ash disposal sites owned by Orion MidWest. Based on Orion Power's evaluations with assistance from third-party consultants and engineers, Orion Power recorded the estimated discounted costs associated with these environmental liabilities as part of its asset retirement obligations. See note 2(o).

(11) Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and payable and derivative assets and liabilities equal their carrying amounts. Values of Orion Power's debt (see note 6) are:

		December 31,
		2005				2004
		Carrying Value		Fair Market Value(1)		Carrying Value		Fair Market Value(1)
		(in millions)
Fixed rate debt		$	448	$	453	$	457	$	508

	Total debt	$	448	$	453	$	457	$	508

(1): Orion Power based the fair market values of its fixed rate debt on information from market participants.

(12) Sales of Assets and Emission Allowances

Orion Power included the following assets in its results of operations through the date of sale.

Emission Allowances. The sales and purchases of emission allowances are classified as investing activities in the consolidated statements of cash flows. Orion Power reclassified net purchases of $27 million and $49 million for 2004 and 2003, respectively, from operating to investing cash flows. Net sales proceeds from emission allowances:

	2005			2004		2003
	(in millions)
SO₂⁽¹⁾	$	54	⁽²⁾	$	1	$	2
NO_x⁽³⁾		11	⁽⁴⁾		10		—

	$	65		$	11	$	2

(1): Includes sales to an affiliate during 2005, 2004 and 2003 of $54 million, $0 and $0, respectively.
(2): Sold 45,000 tons to an affiliate relating to 2008 vintage year.
(3): Includes sales to an affiliate during 2005, 2004 and 2003 of $2 million, $2 million and $0, respectively.
(4): Sold 4,000 tons (which includes 1,000 tons to an affiliate) relating to 2005 through 2006 vintage years.

During January and February 2006, Orion Power sold 45,000 tons of emission allowances relating to 2007 through 2009 vintage years for $60 million and recognized a gain of $58 million.

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Summary of Gains and Losses.

		2005		2004		2003
		(in millions)
Emission allowances⁽¹⁾		$	56	$	2	$	—
Other, net			2		—		—

	Gains on sales of assets and emission allowances, net	$	58	$	2	$	—

(1): For 2004, this amount was previously classified in amortization expense; however, Orion Power reclassified it to gains on sales of assets and emission allowances, net.

(13) Discontinued Operations

(a) New York Plants.

General. On February 23, 2006, Orion Power closed on the sale of its three remaining New York plants with an aggregate net generating capacity of approximately 2,100 MW for $979 million. During the third quarter of 2005, Orion Power began to report the results of the New York plants as discontinued operations.

Use of Proceeds. Under the terms of certain debt agreements, Orion Power is required to apply or offer to apply all net cash proceeds from the sale to pay off debt. Orion Power applied $704 million of cash proceeds, which is net of estimated city, state and transfer taxes and transaction costs, to pay down the Orion New York and Orion MidWest notes (including outstanding interest) owed to Reliant Energy. The remaining net cash proceeds of $249 million are currently subject to an asset sale offer to holders of the Orion Power Holdings senior notes, which expires on March 24, 2006. Orion Power does not expect the Orion Power Holdings bondholders to accept the offer. Upon expiration of the offer and to the extent permitted under the terms of the Orion Power Holdings senior notes, Orion Power plans to distribute the remaining net cash proceeds to Reliant Energy.

Assumptions Related to Debt, Deferred Financing Costs and Interest Expense on Discontinued Operations. Based on Orion Power's obligation to utilize the net proceeds from the sale to prepay debt, Orion Power has classified the related debt amounts for the Orion New York and Orion MidWest related party notes and the Orion New York related party revolver (and the related interest expense) as discontinued operations as shown below (see note 3):

		December 31,
		2005		2004
		(in millions)
Orion New York term notes		$	400	$	400
Orion MidWest term notes			300		400
Orion New York revolver			12		23

	Total	$	712	$	823

Prior to December 2004 (when the notes and revolver with Reliant Energy were issued), Orion Power had outstanding debt of $394 million, which was repaid with the proceeds of the notes from Reliant Energy. This debt (and its related interest expense) has also been classified as discontinued operations. Orion Power classified the related deferred financing costs (and associated interest expense) on all of these debt amounts as discontinued operations. Orion Power allocated $1 million, $31 million and $34 million of related third party interest expense during 2005, 2004 and 2003, respectively, to discontinued operations. Orion Power allocated $53 million of related interest expense—affiliates during 2005 to discontinued operations.

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(b) Ceredo Plant.

In 2005, Orion Power sold its 505 MW Ceredo power plant for $100 million. Orion Power used the net cash proceeds of $100 million to pay down the Orion MidWest term notes owed to Reliant Energy. During the third quarter of 2005, Orion Power began to report results of Ceredo's operations as discontinued operations effective January 1, 2005.

(c) Liberty.

In 2004, Orion Power transferred its ownership interests in Liberty, including its non-recourse debt, to Liberty's lenders. Liberty owned a 530 MW power generation facility and had been in default under its credit agreement. Orion Power has reported the results of its Liberty operations as discontinued operations since the fourth quarter of 2004. Orion Power did not provide or receive any cash consideration in connection with the transfer to Liberty's lenders. Orion Power allocated $21 million and $19 million of related interest expense during 2004 and 2003, respectively, to discontinued operations.

(d) Hydropower Plants.

In 2004, Orion Power sold 71 hydropower plants and a gas-fired generation plant with a total aggregate net generating capacity of 770 MW for $870 million. Orion Power has reported the results of its hydropower plant operations as discontinued operations since the second quarter of 2004. Orion Power's estimated net proceeds after transaction and related costs were $804 million. Orion Power used the net proceeds from the sale to repay debt, pay taxes and settle an interest rate swap termination.

Pursuant to the terms of certain credit agreements to apply all net cash proceeds from the sale to pay off indebtedness (including swap obligations), Orion Power reported the debt repaid through the sale, related interest rate swaps and related deferred financing costs, including associated interest, as discontinued operations. Orion Power allocated $47 million and $43 million of related interest expense during 2004 and 2003, respectively, to discontinued operations.

(e) All Discontinued Operations.

The following summarizes certain financial information of the businesses reported as discontinued operations:

	New York Plants			Ceredo Plant⁽¹⁾			Liberty			Hydropower Plants			Total
2005
Revenues	$	1,014		$	—		$	—		$	—		$	1,014
Loss before income tax expense/benefit		(48	)⁽²⁾		(32	)⁽³⁾		—			—			(80	)
2004
Revenues	$	626			N/A		$	86		$	95		$	807
Income (loss) before income tax expense/benefit		129			N/A			(98	)⁽⁴⁾		125	⁽⁵⁾		156
2003
Revenues	$	549			N/A		$	37		$	118		$	704
Income (loss) before income tax expense/benefit		111			N/A			(24	)		(7	)		80

(1): Prior to January 1, 2005, Ceredo did not qualify for discontinued operations.
(2): Includes $292 million estimated loss on disposal.

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(3): Includes $32 million loss on disposal.
(4): Includes $70 million loss on disposal.
(5): Includes $146 million gain on disposal.

The following summarizes the assets and liabilities related to the New York discontinued operations:

				December 31,
				2005		2004
				(in millions)
Current Assets:
	Accounts receivable, net			$	51	$	46
	Derivative assets				41		—
	Other current assets				65		52

		Total current assets			157		98
Property, Plant and Equipment, net					761		952
Other Assets:
	Other intangibles, net				69		71
	Derivative assets				43		—

		Total long-term assets			873		1,023

			Total Assets	$	1,030	$	1,121

Current Liabilities:
	Accounts payable, principally trade			$	30	$	16
	Other current liabilities				19		7

		Total current liabilities			49		23
Other Liabilities:
	Accumulated deferred income taxes				120		185
	Other liabilities				22		19

		Total other liabilities			142		204
Long-term Debt					712		823

	Total long-term liabilities				854		1,027

		Total Liabilities		$	903	$	1,050

Accumulated other comprehensive loss				$	—	$	(4	)

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