UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-16455

RRI Energy, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware		76-0655566
(State or Other Jurisdiction of Incorporation or		(I.R.S. Employer Identification No.)
Organization)

Houston, Texas 77002
(Address of Principal Executive Offices) (Zip Code)

(832) 357-3000
(Registrant’s Telephone Number, Including Area Code)

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 þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

As of April 27, 2010, the latest practicable date for determination, RRI Energy, Inc. had 353,413,315 shares of common stock outstanding and no shares of treasury stock.

 

 

TABLE OF CONTENTS

Safe Harbor-Forward-Looking Information			ii
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS			1
Consolidated Statements of Operations (unaudited) Three Months Ended March 31, 2010 and 2009			1
Consolidated Balance Sheets March 31, 2010 (unaudited) and December 31, 2009			2
Consolidated Statements of Cash Flows (unaudited) Three Months Ended March 31, 2010 and 2009			3
Notes to Unaudited Consolidated Interim Financial Statements			4
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			31
Business Overview			31
Consolidated Results of Operations			34
Liquidity and Capital Resources			41
Off-Balance Sheet Arrangements			42
New Accounting Pronouncements, Significant Accounting Policies and Critical Accounting Estimates			43
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			45
Market Risks and Risk Management			45
Non-Trading Market Risks			45
Trading Market Risks			46
Fair Value Measurements			47
ITEM 4. CONTROLS AND PROCEDURES			48
Evaluation of Disclosure Controls and Procedures			48
Changes in Internal Control Over Financial Reporting			48
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS			48
ITEM 1A. RISK FACTORS			48
ITEM 6. EXHIBITS			49
Exhibit 10.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

SAFE HARBOR-FORWARD-LOOKING INFORMATION

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are statements that contain projections, assumptions or estimates about our revenues, income, capital structure and other financial items, our plans and objectives for future operations or about our future economic performance, possible transactions, dispositions, financings or offerings, and overview of economic and market conditions. In many cases, you can identify forward-looking statements by terminology such as “anticipate,” “estimate,” “believe,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “will,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and other similar words. However, the absence of these words does not mean that the statements are not forward-looking.

Actual results may differ materially from those expressed or implied by the forward-looking statements as a result of many factors or events, including, but not limited to, the following:

•

Demand and market prices for electricity, capacity, fuel and emission allowances

•

The timing and extent of changes in commodity prices

•

Limitations on our ability to set rates at market prices

•

Legislative, regulatory and/or market developments

•

Changes in environmental regulations that constrain our operations or increase our compliance costs

•

Competition in the wholesale power markets

•

Operating without long-term power sales agreements

•

Ineffective hedging activities

•

Our ability to obtain adequate fuel supply and/or transmission services

•

Interruption or breakdown of our plants

•

Failure of third parties to perform contractual obligations

•

Failure to meet our debt service obligations or restrictive covenants

•

Changes in the wholesale power market or in our evaluation of our plants

•

The outcome of pending or threatened lawsuits, regulatory proceedings, tax proceedings and investigations

•

Weather-related events or other events beyond our control

•

Financial and economic market conditions and our access to capital and

•

The successful and timely completion of the proposed merger with Mirant Corporation, which could be materially and adversely affected by, among other things, the following:

	•		obtaining mutually acceptable debt financing
	•		resolving any litigation brought in connection with the proposed merger
	•		the timing and terms and conditions of required governmental and regulatory approvals
	•		the ability to maintain relationships with employees, suppliers or customers as well as the ability to integrate the businesses and realize cost savings

Other factors that could cause our actual results to differ from our projected results are discussed or referred to in the “Risk Factors” sections of this report and of our most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission. Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Our filings and other important information are also available on our investor page at www.rrienergy.com.

ii

PART I.
FINANCIAL INFORMATION

ITEM 1.		FINANCIAL STATEMENTS

RRI ENERGY, INC. AND SUBSIDIARIES

		Three Months Ended March 31,
		2010				2009
		(thousands of dollars,
		except per share amounts)
Revenues:
Revenues (including $105,840 and $(4,288) unrealized gains (losses))		$	604,710			$	466,184
Expenses:
Cost of sales (including $21,263 and $(39,455) unrealized gains (losses))			266,801				324,674
Operation and maintenance			160,415				157,146
General and administrative			20,718				29,014
Western states litigation and similar settlements			17,000				—
Gains on sales of assets and emission and exchange allowances, net			(417	)			(18,930	)
Long-lived assets impairments			247,715				—
Depreciation and amortization			62,320				67,858
Total operating expense			774,552				559,762
Operating Loss			(169,842	)			(93,578	)
Other Income (Expense):
Interest expense			(46,041	)			(46,919	)
Interest income			216				248
Other, net			1,560				592
Total other expense			(44,265	)			(46,079	)
Loss from Continuing Operations Before Income Taxes			(214,107	)			(139,657	)
Income tax expense (benefit)			62,084				(33,876	)
Loss from Continuing Operations			(276,191	)			(105,781	)
Loss from discontinued operations			(515	)			(45,632	)
Net Loss		$	(276,706	)		$	(151,413	)
Basic/Diluted Loss per Share:
Loss from continuing operations		$	(0.78	)		$	(0.30	)
Loss from discontinued operations			—				(0.13	)
Net loss		$	(0.78	)		$	(0.43	)

See Notes to our Unaudited Consolidated Interim Financial Statements

RRI ENERGY, INC. AND SUBSIDIARIES

		March 31, 2010				December 31, 2009
		(thousands of dollars, except per share amounts)
		(unaudited)
ASSETS
Current Assets:
Cash and cash equivalents		$	1,124,069			$	943,440
Restricted cash			28,835				24,093
Accounts and notes receivable, principally customer, net			114,453				152,569
Inventory			293,066				331,584
Derivative assets			201,626				132,062
Margin deposits			166,364				198,582
Prepayments and other current assets			90,914				86,844
Current assets of discontinued operations ($40,530 and $55,855 of margin deposits)			88,748				108,476
Total current assets			2,108,075				1,977,650
Property, plant and equipment, gross			5,924,765				6,330,879
Accumulated depreciation			(1,611,547	)			(1,728,566	)
Property, Plant and Equipment, net			4,313,218				4,602,313
Other Assets:
Other intangibles, net			300,390				305,913
Derivative assets			91,656				53,138
Prepaid lease			282,700				277,370
Other ($29,212 and $33,793 accounted for at fair value)			190,673				239,078
Long-term assets of discontinued operations			5,224				5,232
Total other assets			870,643				880,731
Total Assets		$	7,291,936			$	7,460,694
LIABILITIES AND EQUITY
Current Liabilities:
Current portion of long-term debt and short-term borrowings		$	401,090			$	404,505
Accounts payable, principally trade			118,251				142,787
Derivative liabilities			132,441				151,461
Margin deposits			67,590				2,860
Other			253,673				169,898
Current liabilities of discontinued operations ($13,309 and $11,000 of margin deposits)			62,494				58,452
Total current liabilities			1,035,539				929,963
Other Liabilities:
Derivative liabilities			56,229				61,436
Other			259,931				260,547
Long-term liabilities of discontinued operations			13,556				13,700
Total other liabilities			329,716				335,683
Long-term Debt			1,949,744				1,949,771
Commitments and Contingencies
Temporary Equity Stock-based Compensation			5,132				6,890
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; 353,413,315 and 352,785,985 issued)			114				114
Additional paid-in capital			6,264,565				6,259,248
Accumulated deficit			(2,249,342	)			(1,972,389	)
Accumulated other comprehensive loss			(43,532	)			(48,586	)
Total stockholders’ equity			3,971,805				4,238,387
Total Liabilities and Equity		$	7,291,936			$	7,460,694

See Notes to our Unaudited Consolidated Interim Financial Statements

RRI ENERGY, INC. AND SUBSIDIARIES

		Three Months Ended March 31,
		2010				2009
		(thousands of dollars)
Cash Flows from Operating Activities:
Net loss		$	(276,706	)		$	(151,413	)
Loss from discontinued operations			515				45,632
Loss from continuing operations			(276,191	)			(105,781	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization			62,320				67,858
Deferred income taxes			62,134				(33,771	)
Net changes in energy derivatives			(125,805	)			43,743
Gains on sales of assets and emission and exchange allowances, net			(417	)			(18,930	)
Western states litigation and similar settlements			17,000				—
Long-lived assets impairments			247,715				—
Other, net			(1,850	)			4,800
Changes in other assets and liabilities:
Accounts and notes receivable, net			37,219				86,831
Inventory			38,518				21,219
Margin deposits, net			96,948				105,783
Net derivative assets and liabilities			875				(10,298	)
Accounts payable			(22,217	)			2,287
Other current assets			(536	)			(5,102	)
Other assets			(8,486	)			(4,221	)
Taxes payable/receivable			1,190				(2,689	)
Other current liabilities			43,757				40,076
Other liabilities			3,412				7,271
Net cash provided by continuing operations from operating activities			175,586				199,076
Net cash provided by discontinued operations from operating activities			25,922				289,161
Net cash provided by operating activities			201,508				488,237
Cash Flows from Investing Activities:
Capital expenditures			(17,997	)			(55,472	)
Proceeds from sales of emission and exchange allowances			7				12,798
Purchases of emission allowances			—				(5,358	)
Restricted cash			(4,742	)			(3,801	)
Other, net			1,400				—
Net cash used in continuing operations from investing activities			(21,332	)			(51,833	)
Net cash used in discontinued operations from investing activities			(803	)			(15,728	)
Net cash used in investing activities			(22,135	)			(67,561	)
Cash Flows from Financing Activities:
Proceeds from issuances of stock			1,881				2,163
Net cash provided by financing activities			1,881				2,163
Net Change in Cash and Cash Equivalents, Total Operations			181,254				422,839
Less: Net Change in Cash and Cash Equivalents, Discontinued Operations			625				16,891
Cash and Cash Equivalents at Beginning of Period, Continuing Operations			943,440				1,004,367
Cash and Cash Equivalents at End of Period, Continuing Operations		$	1,124,069			$	1,410,315
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest paid (net of amounts capitalized) for continuing operations		$	(504	)		$	(4,745	)
Income taxes paid (net of income tax refunds received) for continuing operations			(20	)			3,762

See Notes to our Unaudited Consolidated Interim Financial Statements

RRI ENERGY, INC. AND SUBSIDIARIES

(1) Background and Basis of Presentation

(a) Background.

“RRI Energy” refers to RRI Energy, Inc. and “we,” “us” and “our” refer to RRI Energy, Inc. and its consolidated subsidiaries. We provide energy, capacity, ancillary and other energy services to wholesale customers in competitive energy markets in the United States through our ownership and operation of and contracting for power generation capacity. Our business consists of four reportable segments. See note 16. Our consolidated interim financial statements and notes (interim financial statements) are unaudited, omit certain disclosures and should be read in conjunction with our audited consolidated financial statements and notes in our Form 10-K.

See note 18 for discussion of our proposed merger with Mirant Corporation (Mirant).

(b) Basis of Presentation.

Estimates. 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 amounts of assets, liabilities and equity

•

the reported amounts of revenues and expenses

•

our disclosure of contingent assets and liabilities at the date of the financial statements

Actual results could differ from those estimates.

We evaluate our estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which we believe to be reasonable under the circumstances. We adjust such estimates and assumptions when facts and circumstances dictate.

Adjustments and Reclassifications. The interim financial statements reflect all normal recurring adjustments necessary, in management’s opinion, to present fairly our financial position and results of operations for the reported periods. Amounts reported for interim periods, however, may not be indicative of a full year period due to seasonal fluctuations in demand for electricity and energy services, changes in commodity prices, and changes in regulations, timing of maintenance and other expenditures, dispositions, changes in interest expense and other factors.

Inventory. We value fuel inventories at the lower of average cost or market. We reduce these inventories as they are used in the production of electricity or sold. During the three months ended March 31, 2010 and 2009, we recorded $2 million and $24 million, respectively, for lower of average cost or market valuation adjustments in cost of sales.

New Accounting Pronouncement — Improving Disclosures about Fair Value Measurements. Effective for the first quarter of 2010, this guidance requires disclosures of significant transfers in and out of Levels 1 and 2. In addition, it clarifies existing disclosure requirements regarding inputs and valuation techniques as well as the appropriate level of disaggregation for fair value measurements disclosures. See note 3. Effective for the first quarter of 2011 financial statements, this guidance requires separate presentation of purchases, sales, issuances and settlements within the Level 3 reconciliation.

(2) Stock-based Compensation

Our compensation expense for our stock-based incentive plans was:

		Three Months Ended March 31,
		2010				2009
		(in millions)
Stock-based incentive plans compensation expense (pre-tax) (1)		$	2			$	3

During March 2010, the compensation committee of our board of directors granted (a) 917,746 time-based restricted stock options (exercise price of $4.28 per share which vest in three equal installments during March 2011, 2012 and 2013), (b) 462,500 time-based restricted stock options (exercise price of $4.20 per share which vest in three equal installments during March 2011, 2012 and 2013), (c) 909,423 time-based restricted stock units (which vest during March 2013), (d) 317,890 time-based cash units (which vest during March 2013) and (e) 690,123 performance-based cash units (which vest during March 2013) to employees under our stock and incentive plans. The performance-based cash units, which are liability-classified awards, are each payable into a cash amount equal to the market value of one share of our common stock based on the three-year average total shareholder return for the period beginning March 3, 2010 and ending March 3, 2013 compared to the relative three-year average total shareholder return for the same period of a group of our peer companies. The Monte Carlo simulation valuation model is used, on each reporting measurement date, to estimate the fair value of these performance-based cash awards.

No tax benefits related to stock-based compensation were realized during the three months ended March 31, 2010 and 2009 due to our net operating loss carryforwards.

(3) Fair Value Measurements

Fair Value Hierarchy and Valuation Techniques. We apply recurring fair value measurements to our financial assets and liabilities. In determining fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable internally developed inputs. Based on the observability of the inputs used in our valuation techniques, our financial assets and liabilities are classified as follows:

Level 1:		Level 1 represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes our energy derivative instruments that are exchange-traded or that are cleared and settled through the exchange. Our cash equivalents and available-for-sale and trading securities are also valued using Level 1 inputs.
Level 2:		Level 2 represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category includes emission allowances futures that are exchange-traded and over-the-counter (OTC) derivative instruments such as generic swaps, forwards and options.
Level 3:		This category includes our energy derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from objective sources (such as implied volatilities and correlations). Our OTC, complex or structured derivative instruments that are transacted in less liquid markets with limited pricing information are included in Level 3. Examples are coal contracts, longer term natural gas contracts and options valued using implied or internally developed inputs.

The fair value measurements of these derivative assets and liabilities are based largely on unadjusted indicative quoted prices from independent brokers in active markets who regularly facilitate our transactions. An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis. Derivative instruments for which fair value is calculated using quoted prices that are deemed not active or that have been extrapolated from quoted prices in active markets are classified as Level 3. For certain natural gas and power contracts, we adjust seasonal or calendar year quoted prices based on historical observations to represent fair value for each month in the season or calendar year, such that the average of all months is equal to the quoted price. A derivative instrument that has a tenor that does not span the quoted period is considered an unobservable Level 3 measurement.

We evaluate and validate the inputs we use to estimate fair value by a number of methods, including validating against market published prices and daily broker quotes obtainable from multiple pricing services. For OTC derivative instruments classified as Level 2, indicative quotes obtained from brokers in liquid markets generally represent fair value of these instruments. We believe these price quotes are executable. Adjustments to the quotes are adjustments to the bid or ask price depending on the nature of the position to appropriately reflect exit pricing and are considered a Level 3 input to the fair value measurement. In less liquid markets such as coal, in which a single broker’s view of the market is used to estimate fair value, we consider such inputs to be unobservable Level 3 inputs. We do not use third party sources that determine price based on market surveys or proprietary models.

We value some of our OTC, complex or structured derivative instruments using a variety of valuation models, which utilize inputs that may not be corroborated by market data and vary in complexity depending on the contractual terms of, and inherent risks in, the instrument being valued. We use both industry-standard models as well as internally developed proprietary valuation models that consider various assumptions, such as market prices for power and fuel, price shapes, volatilities and correlations as well as other relevant factors. When such inputs are significant to the fair value measurement, the derivative assets or liabilities are classified as Level 3 when we do not have corroborating market evidence to support significant valuation model inputs and cannot verify the model to market transactions. We believe the transaction price is the best estimate of fair value at inception under the exit price methodology. Accordingly, when a pricing model is used to value such an instrument, the resulting value is adjusted so the model value at inception equals the transaction price. Valuation models are typically impacted by Level 1 or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Subsequent to initial recognition, we update Level 1 and Level 2 inputs to reflect observable market changes. Level 3 inputs are updated when corroborated by available market evidence. In the absence of such evidence, management’s best estimate is used.

See note 6 for discussion of our fair value measurements for some non-financial assets.

Fair Value of Derivative Instruments and Certain Other Assets. We apply recurring fair value measurements to our financial assets and liabilities. Fair value measurements of our financial assets and liabilities by class are as follows:

		March 31, 2010
																		Total
		Level 1(1)				Level 2(1)				Level 3				Reclassifications(2)				Fair Value
		(in millions)
Derivative assets:
Power		$	83			$	57			$	10			$	—			$	150
Power basis			—				3				7				—				10
Capacity energy			—				—				3				—				3
Natural gas			66				—				1				—				67
Natural gas basis			47				—				—				—				47
Coal			—				—				14				—				14
Other			—				—				—				2				2
Total derivative assets		$	196			$	60			$	35			$	2			$	293
Derivative liabilities:
Power		$	10			$	117			$	7			$	—			$	134
Power basis			—				9				—				—				9
Natural gas			—				—				5				—				5
Natural gas basis			30				—				—				—				30
Coal			—				—				7				—				7
Emissions			—				1				—				—				1
Other			—				—				—				2				2
Total derivative liabilities		$	40			$	127			$	19			$	2			$	188
Cash equivalents(3)		$	1,141			$	—			$	—			$	—			$	1,141
Other assets(4)		$	29			$	—			$	—			$	—			$	29

		December 31, 2009
																		Total
		Level 1				Level 2				Level 3				Reclassifications(1)				Fair Value
		(in millions)
Total derivative assets		$	137			$	46			$	4			$	(2	)		$	185
Total derivative liabilities			49				134				32				(2	)			213
Cash equivalents(2)			965				—				—				—				965
Other assets(3)			34				—				—				—				34

The following is a reconciliation of changes in fair value of net commodity derivative assets and liabilities classified as Level 3:

		Three Months Ended March 31,
		2010				2009
		Net Derivatives (Level 3)
		(in millions)
Balance, beginning of period (net asset (liability))		$	(28	)		$	(114	)
Total gains (losses) realized/unrealized:
Included in earnings (1)			44				(74	)
Purchases, issuances and settlements (net)			—				35
Transfers into Level 3(2)			—				—
Transfers out of Level 3(2)			—				—
Balance, end of period (net asset (liability))		$	16			$	(153	)
Changes in unrealized gains (losses) relating to derivative assets and liabilities still held as of March 31, 2010 and 2009:
Revenues		$	12			$	—
Cost of sales			24				(68	)
Total		$	36			$	(68	)

Nonperformance Risk. Derivative assets are discounted for credit risk using a yield curve representative of the counterparty’s probability of default. The counterparty’s default probability is based on a modified version of published default rates, taking 20-year historical default rates from Standard & Poor’s and Moody’s and adjusting them to reflect a rolling five-year average. Fair value measurement of our derivative liabilities reflects the nonperformance risk related to that liability, which is our own credit risk. We derive our nonperformance risk by applying our credit default swap spread against the respective derivative liability.

Fair Value of Other Financial Instruments. The fair values of cash, accounts receivable and payable and margin deposits approximate their carrying amounts. Values of our debt for continuing operations (see note 8) are:

		March 31, 2010								December 31, 2009
		Carrying Value				Fair Value(1)				Carrying Value				Fair Value(1)
		(in millions)
Fixed rate debt		$	2,351			$	2,237			$	2,355			$	2,333
Total debt		$	2,351			$	2,237			$	2,355			$	2,333

See note 4.

(4) Derivative Instruments and Hedging Activities

Changes in commodity prices prior to the energy delivery period are inherent in our business. Accordingly, we may enter selective hedges, including originated transactions, to (a) seek potential value greater than what is available in the spot or day-ahead markets, (b) address operational requirements or (c) seek a specific financial objective. For our risk management activities, we use derivative and non-derivative contracts that provide for settlement in cash or by delivery of a commodity. We use derivative instruments such as futures, forwards, swaps and options to execute our hedge strategy. We may also enter into derivatives to manage our exposure to changes in prices of emission and exchange allowances.

We account for our derivatives under one of three accounting methods (mark-to-market, accrual (under the normal purchase/normal sale exception to fair value accounting) or cash flow hedge accounting) based on facts and circumstances. See note 3 for discussion on fair value measurements.

A derivative is recognized at fair value in the balance sheet whether or not it is designated as an accounting hedge, except for derivative contracts designated as normal purchase/normal sale exceptions, which are not in our consolidated balance sheet or results of operations prior to settlement resulting in accrual accounting treatment.

Realized gains and losses on derivative contracts used for risk management purposes and not held for trading purposes are reported either on a net or gross basis based on the relevant facts and circumstances. 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:

		Primary
		Risk		Purpose for Holding or		Transactions that		Transactions that
Instrument		Exposure		Issuing Instrument(1)		Physically Flow/Settle(2)		Financially Settle(3)
Power futures, forward, swap and option contracts		Price risk		Power sales to customers		Revenues		Revenues
				Power purchases related to operations		Cost of sales		Revenues
				Power purchases/sales related to legacy trading and non-core asset management positions(4)		Revenues		Revenues
Natural gas and fuel futures, forward, swap and option contracts		Price risk		Natural gas and fuel sales related to operations		Revenues/Cost of sales		Cost of sales
				Natural gas sales related to power generation(5)		N/A(6)		Revenues
				Natural gas and fuel purchases related to operations		Cost of sales		Cost of sales
				Natural gas and fuel purchases/sales related to legacy trading and non-core asset management positions(4)		Cost of sales		Cost of sales
Emission and exchange allowances futures(7)		Price risk		Purchases/sales of emission and exchange allowances		N/A(6)		Revenues/Cost of sales

In addition to price risk, we are exposed to credit and operational risk. We have a risk 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 5 for further discussion of our credit policy.

Earnings Volatility from Derivative Instruments. We procure power, natural gas, coal, oil, natural gas transportation and storage capacity and other energy-related commodities to support our business. We may experience volatility in our earnings resulting from contracts receiving accrual accounting treatment while related derivative instruments are marked to market through earnings. As discussed in note 1(b), our financial statements include estimates and assumptions made by management throughout the reporting periods and as of the balance sheet dates. It is reasonable that subsequent to the balance sheet date of March 31, 2010, changes, some of which could be significant, have occurred in the inputs to our various fair value measures, particularly relating to commodity price movements.

Unrealized gains and losses on energy derivatives consist of both gains and losses on energy derivatives during the current reporting period for derivative assets or liabilities that have not settled as of the balance sheet date and the reversal of unrealized gains and losses from prior periods for derivative assets or liabilities that settled prior to the balance sheet date during the current reporting period.

Cash Flow Hedges. During the first quarter of 2007, we de-designated our remaining cash flow hedges; therefore, as of March 31, 2010 and December 31, 2009, we do not have any designated cash flow hedges. The fair value of our de-designated cash flow hedges are deferred in accumulated other comprehensive loss, net of tax, to the extent the contracts have been effective as hedges, until the forecasted transactions affect earnings. At the time the forecasted transactions affect earnings, we reclassify the amounts in accumulated other comprehensive loss into earnings.

Amounts included in accumulated other comprehensive loss are:

		March 31, 2010
						Expected to be
						Reclassified into
						Results of
		At the End of the				Operations
		Period				in Next 12 Months
		(in millions)
De-designated cash flow hedges, net of tax(1)(2)		$	29			$	14

Presentation of Derivative Assets and Liabilities. We present our derivative assets and liabilities on a gross basis (regardless of master netting arrangements with the same counterparty). Cash collateral amounts are also presented on a gross basis.

As of March 31, 2010, our commodity derivative assets and liabilities include amounts for non-trading and trading activities as follows:

		Derivative Assets								Derivative Liabilities								Net Derivative
		Current				Long-Term				Current				Long-Term				Assets (Liabilities)
		(in millions)
Non-trading		$	154			$	91			$	(98	)		$	(56	)		$	91
Trading			48				—				(34	)			—				14
Total derivatives		$	202			$	91			$	(132	)		$	(56	)		$	105

We have the following derivative commodity contracts outstanding as of March 31, 2010:

				Notional Volumes(2)
Commodity		Unit(1)		Current				Long-term
				(in millions)
Power		MWh			(6	)			(4	)
Capacity energy		MWh			(1	)			(1	)
Natural gas (3)		MMBTU			9				18
Coal		MMBTU			106				148

The income (loss) associated with our energy derivatives during the three months ended March 31, 2010 and 2009 is:

		Three Months Ended March 31,
		2010								2009
Derivatives Not Designated as Hedging Instruments		Revenues				Cost of Sales				Revenues				Cost of Sales
		(in millions)
Non-Trading Commodity Contracts:
Unrealized(1)		$	106			$	26			$	(4	)		$	(40	)
Realized(2)(3)(4)			87				(68	)			106				(8	)
Total non-trading		$	193			$	(42	)		$	102			$	(48	)
Trading Commodity Contracts:
Unrealized(1)		$	—			$	(5	)		$	—			$	—
Realized(2)			—				5				—				19
Total trading		$	—			$	—			$	—			$	19

Trading Activities. Prior to March 2003, we engaged in proprietary trading activities. 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. In addition, we have current transactions relating to non-core asset management, such as gas storage and transportation contracts not tied to generation assets, which are classified as trading activities. The income (loss) associated with these transactions is:

		Three Months Ended March 31,
		2010				2009
		(in millions)
Revenues		$	—			$	—
Cost of sales			1				11
Total(1)		$	1			$	11

(5) 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.

Our credit exposure is based on (a) derivative assets and accounts receivable from our counterparties (each included in our consolidated balance sheet) and (b) contracts classified as normal purchase/normal sale and non-derivative contractual commitments (each not included in our consolidated balance sheet except for any related accounts receivable), all after taking into consideration netting within each contract and any master netting contracts with counterparties. We believe this represents the maximum potential loss we could incur if our counterparties to the contracts discussed above failed to perform according to their contract terms.

As of March 31, 2010, our credit exposure is summarized as follows:

		Exposure				Credit								Number of				Net Exposure of
		Before				Collateral				Exposure				Counterparties				Counterparties
Credit Rating Equivalent		Collateral(1)				Held(2)				Net of Collateral				>10%				>10%
		(dollars in millions)
Investment grade		$	179			$	23			$	156				3	(3)		$	107
Non-investment grade			13				1				12				—				—
No external ratings:
Internally rated — Investment grade			45				—				45				1	(4)			41
Internally rated — Non-investment grade			26				22				4				—				—
Total		$	263			$	46			$	217				4			$	148

As of December 31, 2009, three investment grade counterparties (a power grid operator, a utility company and a financial institution) represented 56% ($138 million) of our credit exposure net of collateral held.

Based on our current credit ratings, any additional collateral postings that would be required from us due to a credit downgrade would be immaterial.

We have cash collateral posted and letters of credit issued as follows:

		March 31, 2010								December 31, 2009
		Cash				Letters of Credit(1)				Cash				Letters of Credit(1)
		(in millions)
Commodity contracts(2)		$	132			$	57			$	207			$	52
Derivative contracts receiving mark-to-market accounting treatment(2)(3)		$	58			$	8			$	97			$	5
Other(4)		$	47			$	—			$	47			$	—

We periodically evaluate the recoverability of our long-lived assets (property, plant and equipment and intangible assets), which involves significant judgment and estimates, when there are certain indicators that the carrying value of these assets may not be recoverable. As of March 31, 2010, we had $4.6 billion of long-lived assets. This estimate affects all segments, which hold 99% of our total net property, plant and equipment and net intangible assets. Our East Coal segment holds the largest portion of our net property, plant and equipment and net intangible assets at 57% of our consolidated total. See notes 2(g), 4 and 5 to our consolidated financial statements in our Form 10-K for further discussion.

Based on the further decline of commodity prices, our asset recoverability review was updated from December 31, 2009 to March 31, 2010. Our asset recoverability review indicated that two plants, our Elrama plant and our Niles plant (each in our East Coal segment), needed to be measured at fair value to determine if impairments existed.

Following our current methodology (as described below), we had three additional plants and related intangible assets with a combined carrying value of $344 million, where the undiscounted cash flows were close to the carrying values. If market conditions or environmental and regulatory assumptions change negatively in the future, it is likely that these three plants (and possibly others) could be impaired.

Key Assumptions. The following summarizes some of the most significant estimates and assumptions used in evaluating our plant level undiscounted cash flows. The ranges for the fundamental view assumptions are to account for variability by year and region.

		March 31, 2010
Undiscounted Cash Flow Scenarios Weightings:
5-year market forecast with escalation(1)(2)		50%
5-year market forecast with fundamental view(1)		50%
Range of Assumptions in Fundamental View:
Demand for power growth per year		1%-2%
After-tax rate of return on new construction(3)		6.5%-9.5%
Spread between natural gas and coal prices, $/MMBTU(4)		$3-$5

We estimate the undiscounted cash flows of our plants based on a number of subjective factors, including: (a) appropriate weighting of undiscounted cash flow scenarios, as shown in the table above, (b) forecasts of future power generation margins, (c) estimates of our future cost structure, (d) environmental assumptions, (e) time horizon of cash flow forecasts and (f) estimates of terminal values of plants, if necessary, from the eventual disposition of the assets. We did not include the cash flows associated with our economic hedges in our PJM region (East Coal and East Gas segments) as these cash flows are not specific to any one plant.

Under the 5-year market forecast with escalation scenario, we use the following data: (a) forward market curves for commodity prices as of March 16, 2010 for the first five years, (b) cash flow projections through the plant’s estimated remaining useful life and (c) escalation factor of cash flows of 2.5% per year after year five.

Under the 5-year market forecast with fundamental view scenario, we model all of our plants and those of others in the regions in which we operate using these assumptions: (a) forward market curves for commodity prices as of March 16, 2010 for the first five years; (b) ranges shown in the table above used in developing our fundamental view beyond five years; (c) the markets in which we operate will continue to be deregulated and earn margins based on forward or projected market prices; (d) projected market prices for energy and capacity will be set by the forecasted available supply and level of forecasted demand—new supply will enter markets when market prices and associated returns, including any assumed subsidies for renewable energy, are sufficient to achieve minimum return requirements; (e) minimum return requirements on future construction of new generation facilities, as shown in the table above, will likely be driven or influenced by utilities, which we expect will have a lower cost of capital than merchant generators; (f) various ranges of environmental regulations, including those for SO₂, NO_x and greenhouse gas emissions; and (g) cash flow projections through the plant’s estimated remaining useful life.

Fair Value. Generally, fair value will be determined using an income approach or a market-based approach. Under the income approach, the future cash flows are estimated as described above and then discounted using a risk-adjusted rate. Under a market-based approach, we may also consider prices of similar assets, consult with brokers or employ other valuation techniques.

The following are key assumptions used in our fair value analyses for our two plants for which the undiscounted cash flows did not exceed the net book value of the long-lived assets.

		Elrama				Niles
Valuation approach weightings:
Income approach			100	%			100	%
Market-based approach			0	%			0	%
Risk-adjusted discount rate for the estimated cash flows			15	%			15	%

We only used the income approach as we believe no relevant market data exists for these two plants for which we were required to estimate fair value. The discount rates reflect the uncertainty of the plants’ cash flows and their inability to support meaningful amounts of debt, and was determined considering factors such as the potential for future capacity revenues and regulatory, commodity and macroeconomic conditions.

We determined that our Elrama plant, which consists of property, plant and equipment, was impaired by $193 million as of March 31, 2010. We determined that our Niles plant, which consists of property, plant and equipment, was impaired by $55 million as of March 31, 2010. These impairments were primarily due to the further decline in commodity prices. We believe the remaining net book values of $68 million for Elrama and $26 million for Niles represent our best estimates of fair values as of March 31, 2010.

Certain disclosures are required about nonfinancial assets and liabilities measured at fair value on a nonrecurring basis. This applies to our long-lived assets for which we were required to determine fair value. A fair value hierarchy exists for inputs used in measuring fair value that maximizes the use of observable inputs (Level 1 or Level 2) and minimizes the use of unobservable inputs (Level 3) by requiring that the observable inputs be used when available. See note 3 for further discussion about the three levels. These assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and affects the valuation of fair value and the assets’ placement within the fair value hierarchy levels.

														Q1 2010
		March 31, 2010												Impairment
		Level 1				Level 2				Level 3				Charges
		(in millions)
Elrama property, plant and equipment(1)		$	—			$	—			$	68			$	193
Niles property, plant and equipment(2)			—				—				26				55
Total		$	—			$	—			$	94			$	248

Effect if Different Assumptions Used. The estimates and assumptions used to determine whether long-lived assets are recoverable or whether impairment exists are subject to high degree of uncertainty. Different assumptions as to power prices, fuel costs, our future cost structure, environmental assumptions and remaining useful lives and ultimate disposition values of our plants would result in estimated future cash flows that could be materially different than those considered in the recoverability assessments as of March 31, 2010 and could result in having to estimate the fair value of other plants.

Use of a different risk-adjusted discount rate would result in fair value estimates for the two plants for which we recorded an impairment during the three months ended March 31, 2010 that could be materially greater than or less than the fair value estimates as of March 31, 2010. Any future fair value estimates for our Elrama and Niles long-lived assets that are greater than the fair value estimates as of March 31, 2010 will not result in reversal of the first quarter 2010 impairment charges.

(7) Comprehensive Income (Loss)

The components of total comprehensive income (loss) are:

		Three Months Ended March 31,
		2010				2009
		(in millions)
Net loss		$	(277	)		$	(151	)
Other comprehensive income (loss), net of tax:
Deferred benefits			1				—
Reclassification of net deferred loss from cash flow hedges into net income/loss			5				5
Unrealized gain (loss) on available-for-sale securities			(1	)			1
Comprehensive loss		$	(272	)		$	(145	)

(8) Debt

Outstanding debt:

		March 31, 2010												December 31, 2009
		Weighted												Weighted
		Average												Average
		Stated												Stated
		Interest												Interest
		Rate(1)				Long-term				Current				Rate(1)				Long-term				Current
		(in millions, except interest rates)
Facilities, Bonds and Notes:
RRI Energy:
Senior secured revolver due 2012			2.04	%		$	—			$	—				1.98	%		$	—			$	—
Senior secured notes due 2014			6.75				279				—				6.75				279				—
Senior unsecured notes due 2014			7.625				575				—				7.625				575				—
Senior unsecured notes due 2017			7.875				725				—				7.875				725				—
Subsidiary Obligations:
Orion Power Holdings, Inc. senior notes due 2010 (unsecured)			12.00				—				400	(2)			12.00				—				400
PEDFA(3) fixed-rate bonds due 2036			6.75				371				—				6.75				371				—
Total facilities, bonds and notes							1,950				400								1,950				400
Other:
Adjustment to fair value of debt(4)							—				1								—				5
Total other debt							—				1								—				5
Total debt						$	1,950			$	401							$	1,950			$	405

Amounts borrowed and available for borrowing under our revolving credit agreements as of March 31, 2010 are:

		Total Committed				Drawn				Letters				Unused
		Credit				Amount				of Credit				Amount
		(in millions)
RRI Energy senior secured revolver due 2012		$	500			$	—			$	—			$	500
RRI Energy letter of credit facility due 2014			250				—				92				158
Total		$	750			$	—			$	92			$	658

The amounts used in the basic and diluted earnings (loss) per common share computations are the same:

		Three Months Ended March 31,
		2010				2009
		(in millions)
Loss from continuing operations (basic and diluted)		$	(276	)		$	(106	)

		Three Months Ended March 31,
		2010				2009
		(shares in thousands)
Weighted average shares outstanding (basic and diluted)			353,307				350,487

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

		Three Months Ended March 31,
		2010				2009
		(shares in thousands)
Shares excluded from the calculation of diluted earnings/loss per share			350	(1)			446	(1)
Shares excluded from the calculation of diluted earnings/loss per share because the exercise price exceeded the average market price			4,853	(2)			7,851	(2)

(10) Income Taxes

(a) Tax Rate Reconciliation.

A reconciliation of the federal statutory income tax rate to the effective income tax rate for our continuing operations is:

		Three Months Ended March 31,
		2010				2009
Federal statutory rate			(35	)%			(35	)%
Additions (reductions) resulting from:
Federal valuation allowance			52	(1)			11	(2)
State income taxes, net of federal income taxes			10	(3)			(1	)(4)
Other			2				1
Effective rate			29	%			(24	)%

We assess our future ability to use federal, state and foreign net operating loss carryforwards, capital loss carryforwards and other deferred tax assets using the more-likely-than-not criteria. These assessments include an evaluation of our recent history of earnings and losses, future reversals of temporary differences and identification of other sources of future taxable income, including the identification of tax planning strategies in certain situations.

Our valuation allowances for deferred tax assets are:

		Federal				State
		(in millions)
As of December 31, 2009		$	129			$	135
Changes in valuation allowances			112				32
As of March 31, 2010		$	241			$	167

(c) Income Tax Uncertainties.

We may only recognize the tax benefit for financial reporting purposes from an uncertain tax position when it is more-likely-than-not that, based on the technical merits, the position will be sustained by taxing authorities or the courts. The recognized tax benefits are measured as the largest benefit having a greater than fifty percent likelihood of being realized upon settlement with a taxing authority. We classify accrued interest and penalties related to uncertain income tax positions in income tax expense/benefit.

Our unrecognized federal and state tax benefits changed during the three months ended March 31, 2010 as follows (in millions):

Balance, December 31, 2009		$	3
Increases related to prior years			10
Decreases related to prior years			(9	)
Increases related to current year			—
Settlements			—
Lapses in the statute of limitations			—
Balance, March 31, 2010		$	4

Our unrecognized federal and state tax benefits did not change significantly during the three months ended March 31, 2009.

We expect to continue discussions with taxing authorities regarding tax positions related to the following, and believe it is reasonably possible some of these matters could be resolved in the next 12 months; however, we cannot estimate the range of changes that might occur: (a) $351 million charge during 2005 to settle certain civil litigation and claims relating to the Western states energy crisis; and (b) the timing of tax deductions as a result of negotiations with respect to California-related revenue, depreciation and emission allowances.

We are in ongoing discussions with the Internal Revenue Service (IRS) regarding the timing of revenue recognition and tax deductions with respect to certain California-related items in our 2002 short taxable period return (subsequent to our separation from CenterPoint Energy, Inc (CenterPoint)). The IRS has informed us it expects to issue a notice of denial of our administrative claim for refund involving these California-related items and we expect to institute a refund litigation with respect to this claim in the U.S. District Court or U.S. Court of Federal Claims. In order to set a jurisdictional prerequisite to institute such a refund suit, we expect to make a payment of approximately $60 million to $65 million (which includes an asserted tax liability of $38 million plus interest) some time during 2010 and record a related receivable. If the IRS were to ultimately prevail in this matter, there would be an increase to our income tax expense. The payment will be refunded with interest if we are successful in the litigation.

(11) Guarantees and Indemnifications

We have guaranteed some non-qualified benefits of CenterPoint’s existing retirees at September 20, 2002. The estimated maximum potential amount of future payments under the guarantee is approximately $53 million as of March 31, 2010 and no liability is recorded in our consolidated balance sheet for this item.

We also guarantee the PEDFA fixed-rate bonds, which are included in our consolidated balance sheet as outstanding debt ($371 million are in our consolidated balance sheets as of March 31, 2010 and December 31, 2009). Our guarantees are secured by the same collateral as our senior secured 6.75% notes. The guarantees require us to comply with covenants similar to those in the senior secured 6.75% notes indenture. The PEDFA bonds will become secured by certain assets of our Seward power plant if the collateral supporting both the senior secured 6.75% notes and our guarantees are released. Our maximum potential obligation under the guarantees is for payment of the principal and related interest charges at a fixed rate of 6.75%. During 2009, we purchased $129 million ($92 million of which was classified as discontinued operations) of the PEDFA bonds and are the holder of these repurchased bonds. Therefore, the net amount payable by us would not exceed the amount of PEDFA bonds outstanding, excluding the PEDFA bonds we hold. See note 8.

We guaranteed payments to a third party relating to energy sales during December 2000 from El Dorado Energy, LLC, a former investment. In April 2010, the third party agreed to settle litigation arising from the 2000-2001 energy crises. Based on estimates from the third party and as a result, we recorded a $17 million charge during the three months ended March 31, 2010, which is included in Western states litigation and similar settlements in our statement of operations and other current liabilities in our consolidated balance sheet as of March 31, 2010. The third party’s settlement has not yet been filed with nor approved by the FERC. We currently expect to make this payment during 2010 or early 2011. This estimate is subject to change.

In connection with the sale of our Northeast C&I contracts in December 2008, we guaranteed some former customers’ performance to the buyer. We estimate the most probable maximum potential amount of future payments under the guarantee is $12 million as of March 31, 2010. As of March 31, 2010 and December 31, 2009, we have recorded an insignificant amount in our consolidated balance sheets associated with 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 purchase and sales 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.

Except as otherwise noted, we are unable to estimate our maximum potential exposure under these agreements until an event triggering payment occurs. We do not expect to make any material payments under these agreements.

(12) Contingencies

We are party to many legal proceedings, some of which may involve substantial amounts. Unless otherwise noted, we cannot predict the outcome of the matters described below.

(a) Pending Natural Gas Litigation.

We are party to seven lawsuits, several of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits relate to alleged conduct to increase natural gas prices in violation of antitrust and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name a number of unaffiliated energy companies as parties. In April 2010, in a related lawsuit, the Tennessee Supreme Court reversed the Court of Appeals and dismissed all claims.

(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 plants with the pre-construction permitting requirements of the Clean Air Act known as “New Source Review.” In 2000 and 2001, we responded to the EPA’s information requests related to five of our plants, and in December 2007, we received supplemental requests for two of those plants. In September 2008, we received an EPA request for information related to two additional plants and in October 2009, we received supplemental requests for those two plants. The EPA agreed to share information relating to its investigations with state environmental agencies. In January 2009, we received a Notice of Violation (NOV) from the EPA alleging that past work at our Shawville, Portland and Keystone plants violated the agency’s regulations regarding New Source Review.

In December 2007, the New Jersey Department of Environmental Protection (NJDEP) filed suit against us in the United States District Court in Pennsylvania, alleging that New Source Review violations occurred at one of our power plants located in Pennsylvania. The suit seeks installation of “best available” control technologies for each pollutant, to enjoin us from operating the plant if it is not in compliance with the Clean Air Act and civil penalties. The suit also names three past owners of the plant as defendants. In March 2009, the Connecticut Department of Environmental Protection became an intervening party to the suit.

We believe that the projects listed by the EPA and the projects subject to the NJDEP suit were conducted in compliance with applicable regulations. However, any final finding that we violated the New Source Review requirements could result in significant capital expenditures associated with the implementation of emissions reductions on an accelerated basis and possible penalties. Most of these work projects were undertaken before our ownership of those facilities. We believe we are indemnified by or have the right to seek indemnification from the prior owners for certain losses and expenses that we may incur from activities occurring prior to our ownership.

Ash Disposal Landfill Closures. We are responsible for environmental costs related to the future closures of seven ash disposal landfills. We recorded the estimated discounted costs ($18 million as of March 31, 2010 and December 31, 2009) associated with these environmental liabilities as part of our asset retirement obligations. See note 2(m) to our consolidated financial statements in our Form 10-K.

Remediation Obligations. We are responsible for environmental costs related to site contamination investigations and remediation requirements at four power plants in New Jersey. We recorded the estimated long-term liability for the remediation costs of $8 million as of March 31, 2010 and December 31, 2009.

Conemaugh Actions. In April 2007, PennEnvironment and the Sierra Club filed a citizens’ suit against us in the United States District Court, Western District of Pennsylvania to enforce provisions of the water discharge permit for the Conemaugh plant, of which we are the operator and have a 16.45% interest. PennEnvironment and the Sierra Club seek civil penalties, remediation and an injunction against further violations. We are confident that the Conemaugh plant has operated and will continue to operate in material compliance with its water discharge permit, its consent order agreement with the Pennsylvania Department of Environmental Protection, and related state and federal laws. In December 2009, the District Court ordered that the case be dismissed. PennEnvironment and the Sierra Club have requested that the court reconsider its ruling. If PennEnvironment and the Sierra Club are ultimately successful, we could incur additional capital expenditures associated with the implementation of discharge reductions and penalties, which we do not believe would be material.

Global Warming. In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a suit in the United States District Court for the Northern District of California against us and 23 other electric generating and oil and gas companies. The lawsuit seeks damages of up to $400 million for the cost of relocating the village allegedly because of global warming caused by the greenhouse gas emissions of the defendants. In late 2009, the District Court ordered that the case be dismissed and the plaintiffs appealed. We are also a party to Comer v. Murphy Oil, where a group of Mississippi residents and landowners allege the defendants’ greenhouse gas emissions contributed to the force of Hurricane Katrina. The plaintiffs have not specified the amount of damages they are seeking. In October 2009, the United States Court of Appeals for the Fifth Circuit ruled that the plaintiffs’ claims satisfied the threshold test for standing and did not present a non-justiciable political question and remanded the case to the United States District Court for the Southern District of Mississippi for further proceedings. While we believe claims such as these lack legal merit, it is possible that this trend of climate change litigation may continue.

(c) Other.

Excess Mitigation Credits. From January 2002 to April 2005, CenterPoint applied excess mitigation credits (EMCs) to its monthly charges to retail energy providers. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail energy providers’ monthly charges payable to CenterPoint. CenterPoint represents that the portion of those EMCs credited to our former Texas retail business totaled $385 million. In its stranded cost case, CenterPoint sought recovery of all EMCs credited to all retail electric providers, including our former Texas retail business, and the PUCT ordered that relief. On appeal, the Texas Third Court of Appeals ruled that CenterPoint’s stranded cost recovery should exclude EMCs credited to our former Texas retail business for price-to-beat customers. The case is now before the Texas Supreme Court. In November 2008, CenterPoint asked us to agree to suspend any limitations periods that might exist for possible claims against us or our former Texas retail business if it is ultimately not allowed to include in its stranded cost calculation EMCs credited to our former Texas retail business. We agreed to suspend only unexpired deadlines, if any, that may apply to a CenterPoint claim relating to EMCs credited to our former Texas retail business.

CenterPoint Indemnity. We have agreed to indemnify CenterPoint against certain losses relating to the lawsuits described in note 11(a) under “Pending Natural Gas Litigation.”

Texas Franchise Audit. The state of Texas has issued assessment orders indicating an estimated tax liability of approximately $59 million (including interest and penalties of $21 million) relating primarily to the sourcing of receipts for 2000 through 2006. We are contesting the audit assessments related to this issue.

Refund Contingency Related to Transportation Rates. In September 2008, Kern River Gas Transmission Company (Kern), a natural gas pipeline company, and certain of its shippers entered into a settlement agreement regarding Kern’s transportation rates to which we were a party. The agreement resulted in a refund to us of $30 million during 2008 (recorded as a current liability). In 2009, the Federal Energy Regulatory Commission (FERC) rejected the settlement agreement and directed Kern to recalculate the refunds. We do not expect any adjustments to be material. When the final FERC order is received (currently expected in 2010), we will recognize this liability in income from continuing operations as a reduction of cost of sales.

(d) Proposed Merger with Mirant.

In April 2010, RRI Energy together with Mirant and Mirant’s board of directors have been named defendants in four purported class action lawsuits filed in the Superior Court of Fulton County, Georgia, brought on behalf of proposed classes consisting of holders of Mirant common stock, excluding defendants and their affiliates. RRI Energy Holdings, Inc., a wholly-owned subsidiary of RRI Energy formed for the purpose of effecting the merger, was also named a defendant in three of the lawsuits. The complaints allege, among other things, that the merger agreement was the product of breaches of fiduciary duties by the individual defendants, in that it allegedly does not provide for the best value reasonable under the circumstances for Mirant’s public stockholders, and that the other defendants aided and abetted the individual defendants’ breaches of fiduciary duties. The complaints seek, among other things, (a) a declaration that the merger agreement was entered into in breach of the defendants’ duties, (b) to enjoin defendants from consummating the merger, (c) rescission of the merger if it is consummated and/or (d) granting the class members any profits or benefits allegedly improperly received by defendants. We believe that the allegations of the complaints are without merit and that we have substantial meritorious defenses to the claims made in these actions. See note 18.

(13) Pension and Postretirement Benefits

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. See note 11 to our consolidated financial statements in our 2009 Form 10-K for additional information about pension and postretirement benefits.

		Pension								Postretirement
		Three months ended March 31,								Three months ended March 31,
		2010				2009				2010				2009
		(in millions)
Service cost		$	1			$	1			$	—			$	—
Interest cost			2				2				1				2
Expected return on plan assets			(1	)			(1	)			—				—
Net amortization			—				1				—				—
Net periodic benefit costs		$	2			$	3			$	1			$	2