RRI Rri Energy

 

 

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

For the quarterly period ended September 30, 2010

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

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)

1000 Main Street
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 October 26, 2010, the latest practicable date for determination, RRI Energy, Inc. had 353,439,183 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 and Nine Months Ended September 30, 2010 and 2009			1
Consolidated Balance Sheets September 30, 2010 (unaudited) and December 31, 2009			2
Consolidated Statements of Cash Flows (unaudited) Nine Months Ended September 30, 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			34
Business Overview			34
Recent Events			35
Consolidated Results of Operations			39
Liquidity and Capital Resources			53
Off-Balance Sheet Arrangements			54
Historical Cash Flows			55
New Accounting Pronouncements, Significant Accounting Policies and Critical Accounting Estimates			57
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			59
Market Risks and Risk Management			59
Non-Trading Market Risks			59
Trading Market Risks			60
Fair Value Measurements			61
ITEM 4. CONTROLS AND PROCEDURES			62
Evaluation of Disclosure Controls and Procedures			62
Changes in Internal Control Over Financial Reporting			62
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS			62
ITEM 1A. RISK FACTORS			62
ITEM 6. EXHIBITS			63
Exhibit 10.1
Exhibit 10.2
Exhibit 10.3
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

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,” “think,” “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 and related refinancing, which could be materially and adversely affected by, among other things, the following:

	•		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.

PART I.
FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

RRI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
		(thousands of dollars, except per share amounts)
Revenues:
Revenues (including $49,536, $(25,095), $98,621 and $(51,225) unrealized gains (losses))		$	697,556			$	507,179			$	1,702,464			$	1,363,140
Expenses:
Cost of sales (including $856, $31,826, $13,278 and $20,857 unrealized gains)			305,616				267,632				837,415				872,373
Operation and maintenance			116,196				114,457				459,815				428,567
General and administrative			20,215				23,686				76,403				80,345
Western states litigation and similar settlements			—				—				17,000				—
Gains on sales of assets and emission and exchange allowances, net			(664	)			(1,013	)			(1,700	)			(21,184	)
Long-lived assets impairments			112,856				—				360,571				—
Depreciation and amortization			64,968				67,724				196,436				203,228
Total operating expense			619,187				472,486				1,945,940				1,563,329
Operating Income (Loss)			78,369				34,693				(243,476	)			(200,189	)
Other Income (Expense):
Debt extinguishments gains (losses)			—				(103	)			—				741
Interest expense			(39,568	)			(44,614	)			(122,197	)			(136,600	)
Interest income			126				407				492				1,376
Other, net			2,040				880				4,663				942
Total other expense			(37,402	)			(43,430	)			(117,042	)			(133,541	)
Income (Loss) from Continuing Operations Before Income Taxes			40,967				(8,737	)			(360,518	)			(333,730	)
Income tax expense (benefit)			18,805				9,532				69,657				(105,988	)
Income (Loss) from Continuing Operations			22,162				(18,269	)			(430,175	)			(227,742	)
Income from discontinued operations			664				2,841				4,178				864,467
Net Income (Loss)		$	22,826			$	(15,428	)		$	(425,997	)		$	636,725
Basic and Diluted Earnings (Loss) per Share:
Income (loss) from continuing operations		$	0.06			$	(0.05	)		$	(1.22	)		$	(0.65	)
Income from discontinued operations			—				0.01				0.01				2.46
Net income (loss)		$	0.06			$	(0.04	)		$	(1.21	)		$	1.81

See Notes to our Unaudited Consolidated Interim Financial Statements

RRI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		September 30, 2010				December 31, 2009
		(thousands of dollars, except per share amounts)
		(unaudited)
ASSETS
Current Assets:
Cash and cash equivalents		$	781,097			$	943,440
Restricted cash			6,930				24,093
Accounts and notes receivable, principally customer, net			124,054				152,569
Inventory			280,612				331,584
Derivative assets			175,146				132,062
Margin deposits			124,953				198,582
Prepayments and other current assets			86,404				86,844
Current assets of discontinued operations ($14,823 and $55,855 of margin deposits)			40,641				108,476
Total current assets			1,619,837				1,977,650
Property, plant and equipment, gross			5,766,852				6,330,879
Accumulated depreciation			(1,644,285	)			(1,728,566	)
Property, Plant and Equipment, net			4,122,567				4,602,313
Other Assets:
Other intangibles, net			290,977				305,913
Derivative assets			51,488				53,138
Prepaid lease			285,772				277,370
Other ($27,655 and $33,793 accounted for at fair value)			198,165				239,078
Long-term assets of discontinued operations			3,230				5,232
Total other assets			829,632				880,731
Total Assets		$	6,572,036			$	7,460,694
LIABILITIES AND EQUITY
Current Liabilities:
Current portion of long-term debt		$	108			$	404,505
Accounts payable, principally trade			99,346				142,787
Derivative liabilities			88,714				151,461
Margin deposits			33,479				2,860
Other			233,318				169,898
Current liabilities of discontinued operations ($0 and $11,000 of margin deposits)			14,891				58,452
Total current liabilities			469,856				929,963
Other Liabilities:
Derivative liabilities			35,964				61,436
Other			265,069				260,547
Long-term liabilities of discontinued operations			13,315				13,700
Total other liabilities			314,348				335,683
Long-term Debt			1,949,689				1,949,771
Commitments and Contingencies
Temporary Equity Stock-based Compensation			7,303				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; 353,432,149 and 352,785,985 issued)			114				114
Additional paid-in capital			6,268,528				6,259,248
Accumulated deficit			(2,398,386	)			(1,972,389	)
Accumulated other comprehensive loss			(39,416	)			(48,586	)
Total stockholders’ equity			3,830,840				4,238,387
Total Liabilities and Equity		$	6,572,036			$	7,460,694

See Notes to our Unaudited Consolidated Interim Financial Statements

RRI ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

		Nine Months Ended September 30,
		2010				2009
		(thousands of dollars)
Cash Flows from Operating Activities:
Net income (loss)		$	(425,997	)		$	636,725
Income from discontinued operations			(4,178	)			(864,467	)
Loss from continuing operations			(430,175	)			(227,742	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization			196,436				203,228
Deferred income taxes			67,566				(106,923	)
Net changes in energy derivatives			(107,469	)			30,748
Gains on sales of assets and emission and exchange allowances, net			(1,700	)			(21,184	)
Western states litigation and similar settlements			17,000				—
Long-lived assets impairments			360,571				—
Amortization of deferred financing costs			5,220				5,405
Other, net			(7,426	)			(1,392	)
Changes in other assets and liabilities:
Accounts and notes receivable, net			29,411				117,255
Inventory			48,189				(1,399	)
Margin deposits, net			104,248				(239,903	)
Net derivative assets and liabilities			(2,358	)			(26,816	)
Western states litigation and similar settlement payments			—				(3,449	)
Accounts payable			(23,814	)			(9,111	)
Other current assets			361				7,817
Other assets			(17,165	)			(19,858	)
Taxes payable/receivable			773				(3,479	)
Other current liabilities			23,726				36,779
Other liabilities			(10,911	)			(15,719	)
Net cash provided by (used in) continuing operations from operating activities			252,483				(275,743	)
Net cash provided by discontinued operations from operating activities			34,586				534,275
Net cash provided by operating activities			287,069				258,532
Cash Flows from Investing Activities:
Capital expenditures			(64,041	)			(157,750	)
Proceeds from sales of assets, net			8,385				35,931
Proceeds from sales of emission and exchange allowances			139				19,180
Purchases of emission allowances			(270	)			(7,624	)
Other, net			4,863				2,998
Net cash used in continuing operations from investing activities			(50,924	)			(107,265	)
Net cash provided by (used in) discontinued operations from investing activities			(4,402	)			313,775
Net cash provided by (used in) investing activities			(55,326	)			206,510
Cash Flows from Financing Activities:
Payments of long-term debt			(399,809	)			(59,413	)
Proceeds from issuances of stock			1,899				4,584
Net cash used in continuing operations from financing activities			(397,910	)			(54,829	)
Net cash used in discontinued operations from financing activities			—				(260,707	)
Net cash used in financing activities			(397,910	)			(315,536	)
Net Change in Cash and Cash Equivalents, Total Operations			(166,167	)			149,506
Less: Net Change in Cash and Cash Equivalents, Discontinued Operations			(3,824	)			(100,197	)
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		$	781,097			$	1,254,070
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest paid (net of amounts capitalized) for continuing operations		$	93,071			$	89,127
Income taxes paid (net of income tax refunds received) for continuing operations			1,167				4,582

See Notes to our Unaudited Consolidated Interim Financial Statements

RRI ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

(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 17. 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 2 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 think 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 because of 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. We recorded $1 million and $23 million during the three months ended September 30, 2010 and 2009, respectively, for lower of average cost or market valuation adjustments in cost of sales and recorded $4 million and $82 million during the nine months ended September 30, 2010 and 2009, respectively.

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 4. 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) Proposed Merger with Mirant

On April 11, 2010, we entered into an Agreement and Plan of Merger with Mirant. We have formed a new wholly-owned subsidiary that will merge with and into Mirant upon closing. As a result, Mirant will be a wholly-owned subsidiary of RRI Energy. We anticipate completing the merger before the end of 2010.

Upon closing the merger, each issued and outstanding share of Mirant common stock, including shares in reserve under the Chapter 11 plan of reorganization for Mirant, will convert into the right to receive 2.835 shares of common stock of RRI Energy, including the preferred share purchase rights granted under the Rights Agreement dated January 15, 2001, between RRI Energy and The Chase Manhattan Bank as Rights Agent. Mirant stock options and other equity awards will convert upon completion of the merger into vested stock options and equity awards with respect to RRI Energy common stock, after giving effect to the exchange ratio. The exchange ratio is fixed but subject to adjustment for a proposed reverse stock split.

Completion of the merger is subject to each of RRI Energy and Mirant receiving legal opinions that the merger will qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended. Under a tax-free reorganization, none of RRI Energy, Mirant or any of the Mirant stockholders generally will recognize any gain or loss in the transaction, except that Mirant stockholders will recognize gain with respect to cash received in lieu of fractional shares of RRI Energy common stock.

The primary remaining condition to closing the merger is completion by the Department of Justice (DOJ) of its review of the merger. On June 14, 2010, we and Mirant filed notification of the proposed transaction with the Federal Trade Commission and the DOJ under the Hart-Scott-Rodino Antitrust Improvements Act (the HSR Act). On July 15, 2010, we received a request for additional information from the DOJ. The additional information is to assist the DOJ on its review of the merger.

On September 20, 2010, both companies entered into agreements which provide for the companies to borrow $1.925 billion upon the closing of the proposed merger. In addition, the companies entered into a revolving credit facility. Completion of these financings is subject to the satisfaction of customary conditions. Upon closing of the merger, the proceeds of these financings and cash on hand will be used to (a) discharge the RRI Energy senior notes due 2014 and the Mirant North America (MNA) senior unsecured notes due 2013, (b) defease the RRI Energy Pennsylvania Economic Development Financing Authority (PEDFA) 6.75% bonds due 2036, (c) repay the MNA senior secured term loan maturing in 2013 and (d) pay related fees and expenses, including accrued interest. Upon their completion, these financings will satisfy the financing condition in the merger agreement.

(3) Stock-based Compensation

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

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
		(in millions)
Stock-based incentive plans compensation expense (pre-tax) (1)		$	2	(2)		$	3			$	9	(2)		$	7

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 and nine months ended September 30, 2010 and 2009 because of our net operating loss carryforwards.

(4) 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 think 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 think 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 7 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:

		September 30, 2010
																		Total
		Level 1 (1)				Level 2 (1)				Level 3				Reclassifications (2)				Fair Value
		(in millions)
Derivative assets:
Power		$	73			$	42			$	6			$	—			$	121
Power basis			—				1				7				—				8
Capacity energy			—				—				4				—				4
Natural gas			71				—				—				—				71
Natural gas basis			6				—				—				—				6
Coal			—				—				15				—				15
Other			—				—				—				1				1
Total derivative assets		$	150			$	43			$	32			$	1			$	226
Derivative liabilities:
Power		$	18			$	83			$	4			$	—			$	105
Power basis			—				7				—				—				7
Natural gas			1				—				1				—				2
Natural gas basis			4				—				—				—				4
Coal			—				—				3				—				3
Emissions			—				2				—				—				2
Other			—				—				—				1				1
Total derivative liabilities		$	23			$	92			$	8			$	1			$	124
Cash equivalents (3)		$	781			$	—			$	—			$	—			$	781
Other assets (4)		$	28			$	—			$	—			$	—			$	28

		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 September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
		Net Derivatives (Level 3)								Net Derivatives (Level 3)
		(in millions)
Balance, beginning of period (net asset (liability))		$	10			$	(117	)		$	(28	)		$	(114	)
Total gains (losses) realized/unrealized included in earnings (1)			19				(7	)			59				(78	)
Purchases, issuances and settlements (net)			(5	)			47				(7	)			115
Transfers into Level 3 (2)			—				—				—				—
Transfers out of Level 3 (2)			—				—				—				—
Balance, end of period (net asset (liability))		$	24			$	(77	)		$	24			$	(77	)
Changes in unrealized gains (losses) relating to derivative assets and liabilities still held as of September 30, 2010 and 2009:
Revenues		$	7			$	—			$	11			$	(1	)
Cost of sales			8				(6	)			21				(41	)
Total		$	15			$	(6	)		$	32			$	(42	)

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 9) are:

		September 30, 2010								December 31, 2009
		Carrying Value				Fair Value (1)				Carrying Value				Fair Value (1)
		(in millions)
Fixed rate debt		$	1,950			$	1,912			$	2,355			$	2,333
Total debt		$	1,950			$	1,912			$	2,355			$	2,333

See note 5.

(5) 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 4 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 6 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 September 30, 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 September 30, 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:

		September 30, 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)		$	22			$	12

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 September 30, 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		$	168			$	51			$	(84	)		$	(35	)		$	100
Trading			7				—				(5	)			—				2
Total derivatives		$	175			$	51			$	(89	)		$	(35	)		$	102

We have the following derivative commodity contracts outstanding as of September 30, 2010:

				Notional Volumes (2)
Commodity		Unit (1)		Current				Long-term
				(in millions)
Power		MWh			(6	)			(1	)
Capacity energy		MWh			(1	)			—
Natural gas (3)		MMBtu			25				7
Natural gas basis		MMBtu			(1	)			—
Coal		MMBtu			93				113

The income (loss) associated with our energy derivatives during the three and nine months ended September 30, 2010 and 2009 is:

		Three Months Ended September 30,
Derivatives Not Designated as Hedging		2010								2009
Instruments		Revenues				Cost of Sales				Revenues				Cost of Sales
		(in millions)
Non-Trading Commodity Contracts:
Unrealized (1)		$	50			$	6			$	(25	)		$	34
Realized (2)(3)(4)			58				(46	)			105				(62	)
Total non-trading		$	108			$	(40	)		$	80			$	(28	)
Trading Commodity Contracts:
Unrealized (1)		$	—			$	(5	)		$	—			$	(2	)
Realized (2)			—				(8	)			—				—
Total trading		$	—			$	(13	)		$	—			$	(2	)

		Nine Months Ended September 30,
Derivatives Not Designated as Hedging		2010								2009
Instruments		Revenues				Cost of Sales				Revenues				Cost of Sales
						(in millions)
Non-Trading Commodity Contracts:
Unrealized (1)		$	99			$	30			$	(51	)		$	25
Realized (2)(3)(4)			207				(158	)			292				(136	)
Total non-trading		$	306			$	(128	)		$	241			$	(111	)
Trading Commodity Contracts:
Unrealized (1)		$	—			$	(17	)		$	—			$	(4	)
Realized (2)			—				(11	)			—				20
Total trading		$	—			$	(28	)		$	—			$	16

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 September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
		(in millions)
Revenues		$	1			$	—			$	1			$	—
Cost of sales			1				5				2				21
Total (1)		$	2			$	5			$	3			$	21

(6) 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 think 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 September 30, 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			$	5			$	174				3	(3)		$	137
Non-investment grade			8				—				8				—				—
No external ratings:
Internally rated — Investment grade			24				—				24				1	(4)			23
Internally rated — Non-investment grade			19				13				6				—				—
Total		$	230			$	18			$	212				4			$	160

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. As of December 31, 2009, we had $45 million of collateral held.

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

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

		September 30, 2010								December 31, 2009
		Cash				Letters of Credit (1)				Cash				Letters of Credit (1)
		(in millions)
Commodity contracts (2)		$	99			$	48			$	207			$	52
Derivative contracts receiving mark-to-market accounting treatment (2)(3)		$	20			$	2			$	97			$	5
Other (4)		$	34			$	—			$	47			$	—

(7) Long-Lived Assets Impairments

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 September 30, 2010, we had $4.4 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.

Based on the further decline of forward commodity prices, our asset recoverability review was updated from March 31, 2010 to September 30, 2010. Our asset recoverability review as of September 30, 2010 indicated that two plants, our Titus plant and our New Castle 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), as of September 30, 2010, we had four additional plants and related intangible assets with a combined carrying value of $597 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 four plants (and possibly others) could be impaired.

Our asset recoverability review as of March 31, 2010 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. See notes 2(g), 4 and 5 to our consolidated financial statements in our Form 10-K for further discussion.

Key Assumptions . The following summarizes some of the most significant estimates and assumptions used in evaluating our plant level undiscounted cash flows as of September 30, 2010 and March 31, 2010. The ranges for the fundamental view assumptions are to account for variability by year and region.

		September 30, 2010		March 31, 2010
Undiscounted Cash Flow Scenarios Weightings:
5-year market forecast with escalation (1)(2)		50%		50%
5-year market forecast with fundamental view (1)		50%		50%
Range of Assumptions in Fundamental View:
Demand for power growth per year		1%-2%		1%-2%
After-tax rate of return on new construction (3)		6.5%-9.5%		6.5%-9.5%
Spread between natural gas and coal prices, $/MMBtu (4)		$3-$5		$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 September 21, 2010 (for the third quarter review) and March 16, 2010 (for the first quarter review) 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 September 21, 2010 (for the third quarter review) and March 16, 2010 (for the first quarter review) 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 SO ₂ , 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 as of September 30, 2010 and March 31, 2010 for our four plants for which the undiscounted cash flows did not exceed the net book value of the long-lived assets.

		September 30, 2010								March 31, 2010
		Titus				New Castle				Elrama				Niles
Valuation approach weightings:
Income approach			100	%			100	%			100	%			100	%
Market-based approach			0	%			0	%			0	%			0	%
Risk-adjusted discount rate for the estimated cash flows			13	%			15	%			15	%			15	%

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

We determined that our Titus plant, which consists of property, plant and equipment, was impaired by $74 million as of September 30, 2010. We determined that our New Castle plant, which consists of property, plant and equipment, was impaired by $39 million as of September 30, 2010. These impairments were primarily as a result of the further decline of forward commodity prices. We think the remaining net book values of $31 million for Titus and $6 million for New Castle represent our best estimates of fair values as of September 30, 2010.

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 as a result of the further decline of forward commodity prices. We think 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 4 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.

														Q3 2010
		September 30, 2010												Impairment
		Level 1				Level 2				Level 3				Charges
		(in millions)
Titus property, plant and equipment (1)		$	—			$	—			$	31			$	74
New Castle property, plant and equipment (2)			—				—				6				39
Total		$	—			$	—			$	37			$	113

														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 a 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 September 30, 2010 and 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 four plants for which we recorded an impairment during the three months ended September 30 or March 31, 2010 that could be materially greater than or less than the fair value estimates as of each applicable date. Any future fair value estimates for the plants where an impairment has been recognized that are greater than the fair value estimates at the time of impairment recognition will not result in reversal of previously recognized impairments.

(8) Comprehensive Income (Loss)

The components of total comprehensive income (loss) are:

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
		(in millions)
Net income (loss)		$	23			$	(15	)		$	(426	)		$	637
Other comprehensive income (loss), net of tax:
Deferred benefits			2				—				(1	)			1
Reclassification of net deferred loss from cash flow hedges into net income/loss			4				5				12				13
Unrealized gains (losses) on available-for-sale securities			(1	)			—				(2	)			3
Comprehensive income (loss)		$	28			$	(10	)		$	(417	)		$	654