Edgar Filing: MIRANT CORP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

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: 001-16107

Mirant Corporation

(Exact Name of Registrant as Specified in Its Charter)


Delaware		20-3538156
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

1155 Perimeter Center West, Suite 100,		30338
Atlanta, Georgia		(Zip Code)
(Address of Principal Executive Offices)

(678) 579-5000

(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. x Yes ¨ No

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). x Yes ¨ No

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.


Large Accelerated Filer	x	Accelerated Filer	¨
Non-accelerated Filer	¨	Smaller reporting company	¨

(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 x No

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

The number of shares outstanding of the Registrant’s Common Stock, par value $0.01 per share, at August 3, 2009, was 145,101,763.

TABLE OF CONTENTS


		Page
	Glossary of Certain Defined Terms	i - iv

	Cautionary Statement Regarding Forward-Looking Information	3

	PART I—FINANCIAL INFORMATION
Item 1.	Interim Financial Statements (Unaudited):
	Condensed Consolidated Statements of Operations	6
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Stockholders’ Equity	8
	Condensed Consolidated Statements of Comprehensive Income (Loss)	8
	Condensed Consolidated Statements of Cash Flows	9
	Notes to Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	40
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	73
Item 4.	Controls and Procedures	77

	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	78
Item 1A.	Risk Factors	78
Item 2.	Share Repurchases	78
Item 4.	Submission of Matters to a Vote of Security Holders	78
Item 6.	Exhibits	79

Glossary of Certain Defined Terms

APB—Accounting Principles Board.

APB 28—APB Opinion No. 28, Interim Financial Reporting.

APSA—Asset Purchase and Sale Agreement dated June 7, 2000, between the Company and Pepco.

Bankruptcy Code—United States Bankruptcy Code.

Bankruptcy Court—United States Bankruptcy Court for the Northern District of Texas, Fort Worth Division.

Baseload Generating Units—Units that satisfy minimum baseload requirements of the system and produce electricity at an essentially constant rate and run continuously.

CAIR—Clean Air Interstate Rule.

CAISO—California Independent System Operator.

Cal PX—California Power Exchange.

Clean Air Act—Federal Clean Air Act.

Clean Water Act—Federal Water Pollution Control Act.

CO2—Carbon dioxide.

Company—Old Mirant prior to January 3, 2006, and New Mirant on or after January 3, 2006.

CPUC—California Public Utilities Commission.

DWR—California Department of Water Resources.

EBITDA—Earnings before interest, taxes, depreciation and amortization.

EOB—California Electricity Oversight Board.

EPA—United States Environmental Protection Agency.

EPS—Earnings (loss) per share.

Exchange Act—Securities Exchange Act of 1934.

FASB—Financial Accounting Standards Board.

FERC—Federal Energy Regulatory Commission.

FIN—FASB Interpretation.

FIN 45—FIN No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others—An Interpretation of FASB Statements Nos. 5, 57, and 107 and Rescission of FASB Interpretation No. 34.

FIN 46R—FIN No. 46R, Consolidation of Variable Interest Entities (revised December 2003)—an Interpretation of Accounting Research Bulletin No. 51.

FSP—FASB Staff Position.

FSP FAS 107-1 and APB 28-1—FSP FAS No. 107-1 and APB Opinion No. 28-1, Interim Disclosures about Fair Value of Financial Instruments.

FSP FAS 132R-1—FSP FAS No. 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets.

FSP FAS 157-2—FSP FAS No. 157-2, Effective Date of FASB Statement No. 157.

FSP FAS 157-4—FSP FAS No. 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.

GAAP—United States generally accepted accounting principles.

Gross Margin—Operating revenue less cost of fuel, electricity and other products, excluding depreciation and amortization.

Hudson Valley Gas—Hudson Valley Gas Corporation.

Intermediate Generating Units—Units that meet system requirements that are greater than baseload and less than peaking.

ISO—Independent System Operator.

ISO-NE—Independent System Operator-New England.

LIBOR—London InterBank Offered Rate.

MC Asset Recovery—MC Asset Recovery, LLC.

MDE—Maryland Department of the Environment.

Mirant—Old Mirant prior to January 3, 2006, and New Mirant on or after January 3, 2006.

Mirant Americas Energy Marketing—Mirant Americas Energy Marketing, LP.

Mirant Americas Generation—Mirant Americas Generation, LLC.

Mirant Bowline—Mirant Bowline, LLC.

Mirant Chalk Point—Mirant Chalk Point, LLC.

Mirant Delta—Mirant Delta, LLC.

Mirant Energy Trading—Mirant Energy Trading, LLC.

Mirant Lovett—Mirant Lovett, LLC, owner of the Lovett generating facility, which was shut down on April 19, 2008.

Mirant MD Ash Management—Mirant MD Ash Management, LLC.

Mirant Mid-Atlantic—Mirant Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries.

Mirant New York—Mirant New York, LLC.

Mirant North America—Mirant North America, LLC.

Mirant NY-Gen—Mirant NY-Gen, LLC sold by the Company in the second quarter of 2007.

Mirant Potomac River—Mirant Potomac River, LLC.

MW—Megawatt.

MWh—Megawatt hour.

Net Capacity Factor—The average production as a percentage of the potential net dependable capacity used over a year.

New Mirant—Mirant Corporation on or after January 3, 2006.

NOL—Net operating loss.

NOx—Nitrogen oxides.

NSR—New source review.

NYISO—New York Independent System Operator.

NYMEX—New York Mercantile Exchange.

NYSDEC—New York State Department of Environmental Conservation.

NYSE—New York Stock Exchange.

Old Mirant—MC 2005, LLC, known as Mirant Corporation prior to January 3, 2006.

OTC—Over-the-Counter.

Peaking Generating Units—Units used to meet demand requirements during the periods of greatest or peak load on the system.

Pepco—Potomac Electric Power Company.

PG&E—Pacific Gas & Electric Company.

PJM—PJM Interconnection, LLC.

Plan—The plan of reorganization that was approved in conjunction with the Company’s emergence from bankruptcy protection on January 3, 2006.

Reserve Margin—Excess capacity over peak demand.

RGGI—Regional Greenhouse Gas Initiative.

RMR—Reliability-must-run.

RTO—Regional Transmission Organization.

SAB—SEC Staff Accounting Bulletin.

SAB 107—SAB No. 107, Share-Based Payment.

SAB 110—SAB No. 110, Share-Based Payment—an amendment of SAB No. 107.

Securities Act—Securities Act of 1933, as amended.

Series A Warrants—Warrants issued on January 3, 2006, with an exercise price of $21.87 and expiration date of January 3, 2011.

Series B Warrants—Warrants issued on January 3, 2006, with an exercise price of $20.54 and expiration date of January 3, 2011.

SFAS—Statement of Financial Accounting Standards.

SFAS 5—SFAS No. 5, Accounting for Contingencies.

SFAS 107—SFAS No. 107, Disclosure about Fair Value of Financial Instruments.

SFAS 128—SFAS No. 128, Earnings per Share.

SFAS 133—SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (As Amended).

SFAS 141R—SFAS No. 141R, Business Combinations (Revised 2007).

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

iii

SFAS 157—SFAS No. 157, Fair Value Measurements.

SFAS 159—SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.

SFAS 161—SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133.

SFAS 165—SFAS No. 165, Subsequent Events.

SFAS 167—SFAS No. 167, Amendments to FASB Interpretation No. 46(R).

SFAS 168—SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162.

SO2—Sulfur dioxide.

VaR—Value at risk.

VIE—Variable interest entity.

Virginia DEQ—Virginia Department of Environmental Quality.

Wrightsville—Wrightsville, Arkansas power generating facility sold by the Company in the third quarter of 2005.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In addition to historical information, the information presented in this Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements involve known and unknown risks and uncertainties and relate to future events, our future financial performance or our projected business results. In some cases, one can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expect,” “intend,” “seek,” “plan,” “think,” “anticipate,” “estimate,” “predict,” “target,” “potential” or “continue” or the negative of these terms or other comparable terminology.

Forward-looking statements are only predictions. Actual events or results may differ materially from any forward-looking statement as a result of various factors, which include:

•

legislative and regulatory initiatives regarding deregulation, regulation or restructuring of the industry of generating, transmitting and distributing electricity (the “electricity industry”); changes in state, federal and other regulations affecting the electricity industry (including rate and other regulations); changes in, or changes in the application of, environmental and other laws and regulations to which we and our subsidiaries and affiliates are or could become subject;

•

failure of our plants to perform as expected, including outages for unscheduled maintenance or repair;

•

environmental regulations that restrict our ability or render it uneconomic to operate our business, including regulations related to the emission of CO2 and other greenhouse gases;

•

increased regulation that limits our access to adequate water supplies and landfill options needed to support power generation or that increases the costs of cooling water and handling, transporting and disposing off-site of ash and other byproducts;

•

changes in market conditions, including developments in the supply, demand, volume and pricing of electricity and other commodities in the energy markets, including efforts to reduce demand for electricity, and the extent and timing of the entry of additional competition in our markets;

•

continued poor economic and financial market conditions, including impacts on financial institutions and other current and potential counterparties, and negative impacts on liquidity in the power and fuel markets in which we hedge and transact;

•

increased credit standards, margin requirements, market volatility or other market conditions that could increase our obligations to post collateral beyond amounts that are expected;

•

our inability to access effectively the OTC and exchange-based commodity markets or changes in commodity market conditions and liquidity, which may affect our ability to engage in asset management, proprietary trading and fuel oil management activities as expected, or result in material gains or losses from open positions;

•

deterioration in the financial condition of our counterparties and the failure of counterparties to pay amounts owed to us or to perform obligations or services due to us beyond collateral posted;

•

hazards customary to the power generation industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards or the inability of our insurers to provide agreed upon coverage;

•

price mitigation strategies employed by ISOs or RTOs that reduce our revenue and may result in a failure to compensate our generating units adequately for all of their costs;

•

changes in the rules used to calculate capacity, energy and ancillary services payments;

•

legal and political challenges to the rules used to calculate capacity, energy and ancillary services payments;

•

volatility in our gross margin as a result of our accounting for derivative financial instruments used in our asset management, proprietary trading and fuel oil management activities and volatility in our cash flow from operations resulting from working capital requirements, including collateral, to support our asset management, proprietary trading and fuel oil management activities;

•

our ability to enter into intermediate and long-term contracts to sell power and to obtain adequate supply and delivery of fuel for our facilities, at our required specifications and on terms and prices acceptable to us;

•

the failure to utilize new or advancements in power generation technologies;

•

the inability of our operating subsidiaries to generate sufficient cash flow to support our operations;

•

the potential limitation or loss of our NOLs notwithstanding the implementation of a stockholder rights plan;

•

our ability to borrow additional funds and access capital markets;

•

strikes, union activity or labor unrest;

•

our ability to obtain or develop capable leaders and our ability to retain or replace the services of key employees;

•

weather and other natural phenomena, including hurricanes and earthquakes;

•

the cost and availability of emissions allowances;

•

curtailment of operations because of transmission constraints;

•

our inability to complete construction and obtain permits necessary to operate emissions reduction equipment by January 2010 to meet the requirements of the Maryland Healthy Air Act, which may result in reduced unit operations and reduced cash flows and revenues from operations;

•

our ability to execute our business plan in California, including entering into long-term power sales agreements for new generating facilities at our existing sites and entering into new tolling arrangements for our existing generating facilities;

•

our relative lack of geographic diversification in revenue sources resulting in concentrated exposure to the Mid-Atlantic market;

•

the ability of lenders under Mirant North America’s revolving credit facility to perform their obligations;

•

war, terrorist activities, cyberterrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss;

•

the failure to provide a safe working environment for our employees and visitors thereby increasing our exposure to additional liability, loss of productive time, other costs and a damaged reputation;

•

our consolidated indebtedness and the possibility that we or our subsidiaries may incur additional indebtedness in the future;

•

restrictions on the ability of our subsidiaries to pay dividends, make distributions or otherwise transfer funds to us, including restrictions on Mirant North America contained in its financing agreements and restrictions on Mirant Mid-Atlantic contained in its leveraged lease documents, which may affect our ability to access the cash flows of those subsidiaries to make debt service and other payments;

•

the failure to comply with or monitor provisions of our loan agreements and debt may lead to a breach and, if not remedied, result in an event of default thereunder, which would limit access to needed capital and damage our reputation and relationships with financial institutions; and

•

the disposition of the pending litigation described in this Form 10-Q.

Many of these risks, uncertainties and assumptions are beyond our ability to control or predict. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by cautionary statements contained throughout this report. Because of these risks, uncertainties and assumptions, you should not place undue reliance on these forward-looking statements. Furthermore, forward-looking statements speak only as of the date they are made.

Factors that Could Affect Future Performance

We undertake no obligation to update publicly or revise any forward-looking statements to reflect events or circumstances that may arise after the date of this report.

In addition to the discussion of certain risks in Management’s Discussion and Analysis of Results of Operations and Financial Condition and the accompanying Notes to Mirant’s unaudited condensed consolidated financial statements, other factors that could affect our future performance (business, results of operations or financial condition and cash flows) are set forth in our 2008 Annual Report on Form 10-K, our Form 10-Q for the period ended March 31, 2009, and elsewhere in this Form 10-Q and are incorporated herein by reference.

Certain Terms

As used in this report, “we,” “us,” “our,” the “Company” and “Mirant” refer to Mirant Corporation and its subsidiaries, unless the context requires otherwise. Also, as used in this report “we,” “us,” “our,” the “Company” and “Mirant” refer to Old Mirant prior to January 3, 2006, and to New Mirant on or after January 3, 2006.

MIRANT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in millions, except per share data)
Operating revenues (including unrealized gains (losses) of $(44) million, $(911) million, $211 million and $(1.213) billion, respectively)	$	496		$	(393	)	$	1,374		$	(91	)
Cost of fuel, electricity and other products (including unrealized gains of $30 million, $37 million, $29 million and $36 million, respectively)		150			166			421			406

Gross Margin (excluding depreciation and amortization)		346			(559	)		953			(497	)

Operating Expenses:
Operations and maintenance		115			203			277			369
Depreciation and amortization		36			40			72			73
Gain on sales of assets, net		(2	)		(12	)		(17	)		(16	)

Total operating expenses		149			231			332			426

Operating Income (Loss)		197			(790	)		621			(923	)

Other Expense (Income), net:
Interest expense		34			48			72			100
Interest income		(1	)		(21	)		(3	)		(53	)
Other, net		1			5			1			6

Total other expense, net		34			32			70			53

Income (Loss) From Continuing Operations Before Income Taxes		163			(822	)		551			(976	)
Provision for income taxes		—			10			8			10

Income (Loss) From Continuing Operations		163			(832	)		543			(986	)
Income From Discontinued Operations, net		—			49			—			51

Net Income (Loss)	$	163		$	(783	)	$	543		$	(935	)

Basic EPS:
Basic EPS from continuing operations	$	1.12		$	(4.14	)	$	3.74		$	(4.72	)
Basic EPS from discontinued operations		—			0.24			—			0.25

Basic EPS	$	1.12		$	(3.90	)	$	3.74		$	(4.47	)

Diluted EPS:
Diluted EPS from continuing operations	$	1.12		$	(4.14	)	$	3.74		$	(4.72	)
Diluted EPS from discontinued operations		—			0.24			—			0.25

Diluted EPS	$	1.12		$	(3.90	)	$	3.74		$	(4.47	)

Weighted average shares outstanding		145			201			145			209
Effect of dilutive securities		—			—			—			—

Weighted average shares outstanding assuming dilution		145			201			145			209

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

MIRANT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	At June 30, 2009			At December 31, 2008
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	1,865		$	1,831
Funds on deposit		333			204
Receivables, net		502			761
Derivative contract assets		3,110			2,582
Inventories		259			238
Prepaid expenses		123			132

Total current assets		6,192			5,748

Property, Plant and Equipment, net		3,516			3,215


Noncurrent Assets:
Intangible assets, net		191			196
Derivative contract assets		669			585
Deferred income taxes		616			565
Prepaid rent		311			258
Other		95			121

Total noncurrent assets		1,882			1,725

Total Assets	$	11,590		$	10,688

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current portion of long-term debt	$	41		$	46
Accounts payable and accrued liabilities		875			894
Derivative contract liabilities		2,596			2,268
Deferred income taxes		616			565
Other		15			11

Total current liabilities		4,143			3,784

Noncurrent Liabilities:
Long-term debt, net of current portion		2,594			2,630
Derivative contract liabilities		285			244
Pension and postretirement obligations		150			148
Other		99			120

Total noncurrent liabilities		3,128			3,142

Commitments and Contingencies

Stockholders’ Equity:
Preferred stock, par value $.01 per share, authorized 100,000,000 shares, no shares issued at June 30, 2009 and December 31, 2008		—			—
Common stock, par value $.01 per share, authorized 1.5 billion shares, issued 311,192,623 and 310,666,240 at June 30, 2009 and December 31, 2008, respectively, and outstanding 145,098,872 shares and 144,629,446 at June 30, 2009 and December 31, 2008, respectively		3			3
Treasury stock, at cost, 166,093,751 shares and 166,036,794 shares at June 30, 2009 and December 31, 2008, respectively		(5,331	)		(5,330	)
Additional paid-in capital		11,418			11,401
Accumulated deficit		(1,679	)		(2,222	)
Accumulated other comprehensive loss		(92	)		(90	)

Total stockholders’ equity		4,319			3,762

Total Liabilities and Stockholders’ Equity	$	11,590		$	10,688

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

MIRANT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)


	Common Stock		Treasury Stock			Additional Paid-In Capital		Accumulated Deficit			Accumulated Other Comprehensive Loss
	(in millions)
Balance, December 31, 2008	$	3	$	(5,330	)	$	11,401	$	(2,222	)	$	(90	)
Net income		—		—			—		543			—
Share repurchases		—		(1	)		—		—			—
Stock-based compensation		—		—			17		—			—
Other comprehensive loss		—		—			—		—			(2	)

Balance, June 30, 2009	$	3	$	(5,331	)	$	11,418	$	(1,679	)	$	(92	)

MIRANT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)


	Six Months Ended June 30,
	2009			2008
	(in millions)
Net Income (Loss)	$	543		$	(935	)
Other Comprehensive Loss, Net of Tax
Pension and postretirement benefits		(2	)		(7	)

Other comprehensive loss, net of tax		(2	)		(7	)

Total Comprehensive Income (Loss)	$	541		$	(942	)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

MIRANT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Six Months Ended June 30,
	2009			2008
	(in millions)
Cash Flows from Operating Activities:
Net income (loss)	$	543		$	(935	)
Income from discontinued operations		—			51

Income (loss) from continuing operations		543			(986	)

Adjustments to reconcile income (loss) from continuing operations and changes in other operating assets and liabilities to net cash provided by (used in) operating activities:
Depreciation and amortization		75			75
Gain on sales of assets, net		(17	)		(16	)
Unrealized losses (gains) on derivative contracts, net		(240	)		1,177
Stock-based compensation expense		16			13
Lower of cost or market inventory adjustments		22			1
Other, net		—			4
Funds on deposit		(120	)		(268	)
Changes in other operating assets and liabilities		152			(45	)

Total adjustments		(112	)		941

Net cash provided by (used in) operating activities of continuing operations		431			(45	)
Net cash provided by operating activities of discontinued operations		4			46

Net cash provided by operating activities		435			1

Cash Flows from Investing Activities:
Capital expenditures		(378	)		(311	)
Proceeds from the sales of assets		17			15
Other		2			1

Net cash used in investing activities of continuing operations		(359	)		(295	)
Net cash provided by investing activities of discontinued operations		—			25

Net cash used in investing activities		(359	)		(270	)

Cash Flows from Financing Activities:
Repayments and purchases of long-term debt		(41	)		(271	)
Share repurchases		(1	)		(1,737	)
Proceeds from exercises of stock options and warrants		—			15

Net cash used in financing activities of continuing operations		(42	)		(1,993	)
Net cash used in financing activities of discontinued operations		—			—

Net cash used in financing activities		(42	)		(1,993	)

Net Increase (Decrease) in Cash and Cash Equivalents		34			(2,262	)
Cash and Cash Equivalents, beginning of period		1,831			4,961

Cash and Cash Equivalents, end of period	$	1,865		$	2,699

Supplemental Cash Flow Disclosures:
Cash paid for interest, net of amounts capitalized	$	63		$	94
Cash paid for income taxes	$	3		$	—
Cash paid for claims and professional fees from bankruptcy	$	1		$	5

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

A. Description of Business

Mirant is a competitive energy company that produces and sells electricity in the United States. The Company owns or leases 10,112 MW of net electric generating capacity in the Mid-Atlantic and Northeast regions and in California. Mirant also operates an integrated asset management and energy marketing organization based in Atlanta, Georgia.

B. Accounting and Reporting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of Mirant and its wholly-owned subsidiaries have been prepared in accordance with GAAP for interim financial information and with the instructions for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. For further information, refer to the consolidated financial statements and notes thereto included in the Company’s 2008 Annual Report on Form 10-K.

The accompanying unaudited condensed consolidated financial statements include the accounts of Mirant and its wholly-owned and controlled majority-owned subsidiaries as well as a VIE in which Mirant has an interest and is the primary beneficiary. The financial statements have been prepared from records maintained by Mirant and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. As of June 30, 2009, substantially all of Mirant’s subsidiaries are wholly-owned and located in the United States. The Company’s obligations to MC Asset Recovery result in its treatment as a VIE in which Mirant is the primary beneficiary as defined in FIN 46R. The entity, therefore, is included in the Company’s unaudited condensed consolidated financial statements. See Note L for further discussion of MC Asset Recovery.

The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make various estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates. Certain prior period amounts have been reclassified to conform to the current period financial statement presentation.

The Company evaluates events that occur after its balance sheet date but before its financial statements are issued for potential recognition or disclosure. Based on the evaluation, as of August 6, 2009, the Company determined that there were no material subsequent events for recognition or disclosure other than those disclosed herein.

In preparing the Company’s unaudited condensed consolidated financial statements for the three months ended March 31, 2009, management discovered that the amounts previously disclosed for cash paid for interest and cash paid for interest, net of amount capitalized were overstated for each interim period in 2008. For the three and six months ended June 30, 2008, the Company’s cash paid for interest was overstated by approximately $20 million and $23 million, respectively. The Capitalization of Interest Cost discussed later in Note B has been adjusted to

reflect the immaterial correction of these misstatements. For the six months ended June 30, 2008, cash paid for interest, net of amounts capitalized was overstated by approximately $23 million. The supplemental cash flow disclosure for the unaudited condensed consolidated statement of cash flows for the six months ended June 30, 2008, has been adjusted to reflect the immaterial correction of this misstatement. The misstatement of cash paid for interest and cash paid for interest, net of amount capitalized had no effect on the Company’s cash and cash equivalents, net loss or stockholders’ equity.

Inventories

Inventories consist primarily of fuel oil, coal, materials and supplies, and purchased emissions allowances. Inventory is generally stated at the lower of cost or market value. Fuel stock is removed from the inventory account as it is used in the production of electricity. Materials and supplies are removed from the inventory account on a weighted average cost basis when they are used for repairs, maintenance or capital projects. The cost of purchased emissions allowances is also computed on a weighted average cost basis. Purchased emissions allowances are removed from inventory and charged to cost of fuel, electricity and other products in the accompanying unaudited condensed consolidated statements of operations as they are utilized for emissions volumes.

Inventories were comprised of the following (in millions):


	At June 30, 2009		At December 31, 2008
Fuel stock:
Fuel oil	$	126	$	113
Coal		53		43
Other		1		1
Materials and supplies		65		63
Purchased emissions allowances		14		18

Total inventories	$	259	$	238

For the six months ended June 30, 2009, the Company recognized lower of cost or market inventory adjustments of $22 million, primarily related to coal inventory. For the year ended December 31, 2008, the Company recognized lower of cost or market inventory adjustments of $65 million, primarily related to fuel oil inventory.

Impairment of Long-Lived Assets

Mirant evaluates long-lived assets, such as property, plant and equipment and purchased intangible assets subject to amortization, for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Such evaluations are performed in accordance with SFAS 144. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value. In the second quarter of 2009, the Company evaluated its Bowline generating facility for impairment. The sum of the probability weighted undiscounted cash flows for the Bowline generating facility exceeded the carrying value as of June 30, 2009. As a result, the Company did not record an impairment charge for the three and six months ended June 30, 2009. See Note D for further discussion.

Capitalization of Interest Cost

Mirant capitalizes interest on projects during their construction period. The Company determines which debt instruments represent a reasonable measure of the cost of financing construction in terms of interest costs incurred that otherwise could have been avoided. These debt instruments and associated interest costs are included in the calculation of the weighted average interest rate used for determining the capitalization rate. Once a project is placed in service, capitalized interest, as a component of the total cost of the construction, is amortized over the estimated useful life of the asset constructed.

For the three and six months ended June 30, 2009 and 2008, the Company incurred the following interest costs (in millions):


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Total interest costs	$	52		$	60		$	105		$	123
Capitalized and included in property, plant and equipment, net		(18	)		(12	)		(33	)		(23	)

Interest expense	$	34		$	48		$	72		$	100

The amounts of capitalized interest above include interest accrued. For the three and six months ended June 30, 2009, cash paid for interest was $93 million and $96 million, respectively, of which $31 million and $33 million, respectively, was capitalized. For the three and six months ended June 30, 2008, cash paid for interest was $108 million and $117 million, respectively, of which $20 million and $23 million, respectively, was capitalized.

Recently Adopted Accounting Standards

In December 2007, the FASB issued SFAS 141R, which requires an acquirer of a business to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values. SFAS 141R also requires disclosure of information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination. Additionally, SFAS 141R requires that acquisition-related costs be expensed as incurred. The provisions of SFAS 141R became effective for acquisitions completed on or after January 1, 2009; however, the income tax considerations included in SFAS 141R were effective as of that date for all acquisitions, regardless of the acquisition date. The Company adopted SFAS 141R on January 1, 2009, and the adoption had no effect on the Company’s consolidated statements of operations, financial position or cash flows.

On February 12, 2008, the FASB issued FSP FAS 157-2, which deferred the effective date of SFAS 157 for one year for certain nonfinancial assets and liabilities, with the exception of those nonfinancial assets and liabilities that are recognized or disclosed on a recurring basis (at least annually). The Company’s non-recurring nonfinancial assets and liabilities that could be measured at fair value in the Company’s unaudited condensed consolidated financial statements include long-lived asset impairments and the initial recognition of asset retirement obligations. The Company adopted FSP FAS 157-2 on January 1, 2009, and the adoption had no effect on the Company’s consolidated statements of operations, financial position or cash flows. The Company will incorporate the recognition and disclosure provisions of SFAS 157 when required for fair value measurements for non-recurring nonfinancial assets and liabilities. As of June 30, 2009, the Company did not have any events that required a fair value measurement for non-recurring nonfinancial assets or liabilities.

On March 19, 2008, the FASB issued SFAS 161, which amends SFAS 133 to enhance the required disclosures for derivative instruments and hedging activities. The Company utilizes derivative financial instruments to manage its exposure to commodity price risks and for its proprietary trading and fuel oil management activities. The Company adopted SFAS 161 on January 1, 2009. See Note C for these disclosures.

On April 9, 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which amended SFAS 107 and APB 28 to require disclosures about the fair value of financial instruments in interim financial statements. This FSP is effective for interim periods ending after June 15, 2009. The Company adopted FSP FAS 107-1 and APB 28-1 for its disclosures of the fair value of financial instruments for the quarter ended June 30, 2009, and the adoption had no effect on the Company’s consolidated statements of operations, financial position or cash flows. See “Fair Value of Other Financial Instruments” in Note C for these disclosures.

On April 9, 2009, the FASB issued FSP FAS 157-4, which amended SFAS 157 to provide additional guidance on determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurements. Under distressed market conditions, the Company needs to weigh all available evidence in determining whether a transaction occurred in an orderly market. FSP FAS 157-4 requires additional judgment by the Company when determining the fair value of derivative contracts in the current economic environment. The Company adopted FSP FAS 157-4 for its fair value measurements for the quarter ended June 30, 2009, and the adoption did not have a material effect on the Company’s consolidated statements of operations, financial position or cash flows.

On May 28, 2009, the FASB issued SFAS 165, which requires the Company to disclose the date through which it has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. SFAS 165 defines two types of subsequent events; recognized and non-recognized events, with recognized events giving rise to conditions that existed as of the balance sheet date. SFAS 165 is effective for interim periods ending after June 15, 2009. The Company adopted the disclosure requirements of SFAS 165 for the quarter ended June 30, 2009, and the adoption had no effect on the Company’s consolidated statements of operations, financial position or cash flows.

New Accounting Standards Not Yet Adopted at June 30, 2009

On December 30, 2008, the FASB issued FSP FAS 132R-1, which requires enhanced disclosures about plan assets of an employer’s defined benefit pension or other postretirement plan. FSP FAS 132R-1 will require additional information on how the fair value of plan assets is measured, including a reconciliation of beginning and ending balances for Level 3 inputs and the valuation techniques used to measure fair value. FSP FAS 132R-1 is effective for fiscal years ending after December 15, 2009. The Company will adopt FSP FAS 132R-1 for its defined benefit and other postretirement plan disclosures in its Form 10-K for the year ended December 31, 2009. The Company is currently evaluating the potential effect of adopting FSP FAS 132R-1 on its disclosures in the Company’s consolidated financial statements.

On June 12, 2009, the FASB issued SFAS 167, which amended FIN 46R to require the Company to perform an analysis to determine whether the Company’s variable interest gives it a controlling financial interest in a VIE. This analysis should identify the primary beneficiary of a VIE. SFAS 167 also requires ongoing reassessments of whether an enterprise is the primary beneficiary of a VIE and enhances the disclosures to provide more information regarding the Company’s involvement in a VIE. SFAS 167 is effective for fiscal years beginning after November 15, 2009. The Company will adopt SFAS 167 on January 1, 2010. The Company is currently evaluating the potential effect of adopting SFAS 167 on its consolidated financial statements.

On July 1, 2009, the FASB issued SFAS 168, which codified all authoritative nongovernmental GAAP into a single source. SFAS 168 will be effective for interim and annual periods ending after September 15, 2009. SFAS 168 will supersede all existing accounting standards, but does not change the contents of those standards. The Company will adopt SFAS 168 beginning with its Form 10-Q for the quarter ending September 30, 2009, and the adoption will require the Company to change its references to accounting literature to conform to the codified source of authoritative nongovernmental GAAP.

C. Financial Instruments

Derivative Financial Instruments

In connection with generating electricity, the Company is exposed to energy commodity price risk associated with the acquisition of fuel needed to generate electricity, the price of electricity produced and sold, and the fair value of fuel inventories. In addition, the open positions in the Company’s trading activities, comprised of proprietary trading and fuel oil management activities, expose it to risks associated with changes in energy commodity prices. The Company, through its asset management activities, enters into a variety of exchange-traded and OTC energy and energy-related derivative financial instruments, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage exposure to commodity price risks. These contracts have varying terms and durations, which range from a few days to years, depending on the instrument. The Company’s proprietary trading activities also utilize similar derivative contracts in markets where the Company has a physical presence to attempt to generate incremental gross margin. The Company’s fuel oil management activities use derivative financial instruments to hedge economically the fair value of the Company’s physical fuel oil inventories and to optimize the approximately three million barrels of storage capacity that the Company owns or leases.

Changes in the fair value and settlements of derivative financial instruments used to hedge electricity economically are reflected in operating revenue, and changes in the fair value and settlements of derivative financial instruments used to hedge fuel economically are reflected in cost of fuel, electricity and other products in the accompanying unaudited condensed consolidated statements of operations. Most of the Company’s long-term coal agreements are not required to be recorded at fair value under SFAS 133. As such, these contracts are not included in derivative contract assets and liabilities in the accompanying condensed consolidated balance sheets. Changes in the fair value and settlements of derivative contracts for trading activities, comprised of proprietary trading and fuel oil management, are recorded on a net basis as operating revenue in the accompanying unaudited condensed consolidated statements of operations. As of June 30, 2009, the Company does not have any derivative financial instruments for which hedge accounting, as defined by SFAS 133, has been elected.

The Company also considers risks associated with interest rates, counterparty credit and Mirant’s own non-performance risk when valuing its derivative financial instruments. The nominal value of the derivative contract assets and liabilities is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the Company’s transactions being valued.

The following table presents the fair value of derivative financial instruments related to commodity price risk (in millions):


		Fair Value at
Commodity Derivative Contracts	Balance Sheet Location	June 30, 2009			December 31, 2008
Asset management	Derivative contract assets	$	1,903		$	1,285
Trading activities	Derivative contract assets		1,876			1,882

Total derivative contract assets			3,779			3,167

Asset management	Derivative contract liabilities		(1,051	)		(736	)
Trading activities	Derivative contract liabilities		(1,830	)		(1,776	)

Total derivative contract liabilities			(2,881	)		(2,512	)

Asset management, net			852			549
Trading activities, net			46			106

Total derivative contracts, net		$	898		$	655

The following tables present the net gains (losses) for derivative financial instruments recognized in income in the unaudited condensed consolidated statements of operations (in millions):


Commodity Derivative Contracts	Location of Net Gains (Losses) Recognized in Income	Amount of Net Gains (Losses) Recognized in Income for the Three Months Ended
		June 30, 2009									June 30, 2008
		Realized			Unrealized			Total			Realized			Unrealized			Total
Asset management	Operating revenues	$	191		$	(10	)	$	181		$	(94	)	$	(856	)	$	(950	)
Trading activities	Operating revenues		46			(34	)		12			(15	)		(55	)		(70	)
Asset management	Cost of fuel, electricity and other products		(28	)		30			2			8			37			45

Total		$	209		$	(14	)	$	195		$	(101	)	$	(874	)	$	(975	)


Commodity Derivative Contracts	Location of Net Gains (Losses) Recognized in Income	Amount of Net Gains (Losses) Recognized in Income for the Six Months Ended
		June 30, 2009									June 30, 2008
		Realized			Unrealized			Total			Realized			Unrealized			Total
Asset management	Operating revenues	$	327		$	260		$	587		$	(110	)	$	(1,164	)	$	(1,274	)
Trading activities	Operating revenues		74			(49	)		25			(19	)		(49	)		(68	)
Asset management	Cost of fuel, electricity and other products		(44	)		29			(15	)		17			36			53

Total		$	357		$	240		$	597		$	(112	)	$	(1,177	)	$	(1,289	)

The following table presents the notional quantity on long (short) positions for derivative financial instruments on a gross and net basis at June 30, 2009 (in equivalent MWh):


	Notional Quantity
	Derivative Contract Assets		Derivative Contract Liabilities		Net Derivative Contracts
	(in millions)
Commodity Type:
Power¹	(169	)	126		(43	)
Natural gas	(45	)	46		1
Fuel oil	2		(3	)	(1	)

Total	(212	)	169		(43	)

¹	Includes MWh equivalent of natural gas transactions used to hedge power.

Fair Value Hierarchy

Based on the observability of the inputs used in the valuation techniques for fair value measurement, the Company is required to classify recorded fair value measurements according to the fair value hierarchy. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The fair value measurement inputs the Company uses vary from readily observable prices for exchange-traded instruments to price curves that cannot be validated through external pricing sources. The Company’s financial assets and liabilities carried at fair value in the consolidated financial statements are classified in three categories based on the inputs used.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls must be determined based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability.

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009, by category and tenor, respectively. At June 30, 2009, the Company’s only financial assets and liabilities measured at fair value on a recurring basis are derivative financial instruments.

The following table presents financial assets and liabilities, net accounted for at fair value on a recurring basis as of June 30, 2009, by category (in millions):


	Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Other Unobservable Inputs (Level 3)			Total
Assets:
Commodity contracts—asset management	$	13		$	1,852		$	38		$	1,903
Commodity contracts—trading activities		634			1,203			39			1,876

Total derivative contract assets		647			3,055			77			3,779

Liabilities:
Commodity contracts—asset management		(41	)		(1,007	)		(3	)		(1,051	)
Commodity contracts—trading activities		(612	)		(1,209	)		(9	)		(1,830	)

Total derivative contract liabilities		(653	)		(2,216	)		(12	)		(2,881	)

Net:
Commodity contracts—asset management, net		(28	)		845			35			852
Commodity contracts—trading activities, net		22			(6	)		30			46

Total derivative contract assets and liabilities, net	$	(6	)	$	839		$	65		$	898

The following table presents financial assets and liabilities, net accounted for at fair value on a recurring basis as of December 31, 2008, by category (in millions):


	Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Other Unobservable Inputs (Level 3)			Total
Assets:
Commodity contracts—asset management	$	5		$	1,256		$	24		$	1,285
Commodity contracts—trading activities		540			1,319			23			1,882

Total derivative contract assets		545			2,575			47			3,167

Liabilities:
Commodity contracts—asset management		(22	)		(714	)		—			(736	)
Commodity contracts—trading activities		(539	)		(1,236	)		(1	)		(1,776	)

Total derivative contract liabilities		(561	)		(1,950	)		(1	)		(2,512	)

Net:
Commodity contracts—asset management, net		(17	)		542			24			549
Commodity contracts—trading activities, net		1			83			22			106

Total derivative contract assets and liabilities, net	$	(16	)	$	625		$	46		$	655

The following table presents financial assets and liabilities, net accounted for at fair value on a recurring basis as of June 30, 2009, by tenor (in millions):


	Commodity Contracts
	Asset Management		Trading Activities		Total
Remainder of 2009	$	325	$	45	$	370
2010		239		1		240
2011		57		—		57
2012		44		—		44
2013		90		—		90
Thereafter		97		—		97

Total	$	852	$	46	$	898

The volumetric weighted average maturity, or weighted average tenor, of the asset management derivative contract portfolio at both June 30, 2009 and December 31, 2008, was approximately 23 months. The volumetric weighted average maturity, or weighted average tenor, of the trading derivative contract portfolio at June 30, 2009 and December 31, 2008, was approximately 10 months and 8 months, respectively.

Level 3 Disclosures

The following tables present a roll forward of fair values of assets and liabilities, net categorized in Level 3 and the amount included in income for the six months ended June 30, 2009 and 2008 (in millions):


	Commodity Contracts
	Asset Management			Trading Activities			Total
Fair value of assets and liabilities categorized in Level 3 at January 1, 2009	$	24		$	22		$	46
Total gains or losses (realized/unrealized):
Included in income of existing contracts (or changes in net assets or liabilities)¹		(11	)		(11	)		(22	)
Purchases, issuances and settlements²		22			19			41
Transfers in and/or out of Level 3³		—			—			—

Fair value of assets and liabilities categorized in Level 3 at June 30, 2009	$	35		$	30		$	65


	Commodity Contracts
	Asset Management			Trading Activities			Total
Fair value of assets and liabilities categorized in Level 3 at January 1, 2008	$	12		$	—		$	12
Total gains or losses (realized/unrealized):
Included in income of existing contracts (or changes in net assets or liabilities)¹		(11	)		(1	)		(12	)
Purchases, issuances and settlements²		4			3			7
Transfers in and/or out of Level 3³		(1	)		20			19

Fair value of assets and liabilities categorized in Level 3 at June 30, 2008	$	4		$	22		$	26

¹	Reflects the total gains or losses on contracts included in Level 3 at the beginning of each quarterly reporting period and at the end of each quarterly reporting period, and contracts entered into during each quarterly reporting period that remain at the end of each quarterly reporting period.

²	Represents the total cash settlements of contracts during each quarterly reporting period that existed at the beginning of each quarterly reporting period.

Denotes the total contracts that existed at the beginning of each quarterly reporting period and were still held at the end of each quarterly reporting period that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during each quarterly reporting period. Amounts reflect fair value as of the end of each quarterly reporting period.


	Three Months Ended June 30, 2009								Six Months Ended June 30, 2009
	Operating Revenues			Cost of Fuel		Total			Operating Revenues		Cost of Fuel			Total
Gains (losses) included in income	$	(10	)	$	3	$	(7	)	$	16	$	3		$	19
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at June 30, 2009	$	(10	)	$	3	$	(7	)	$	18	$	3		$	21

	Three Months Ended June 30, 2008								Six Months Ended June 30, 2008
	Operating Revenues			Cost of Fuel		Total			Operating Revenues		Cost of Fuel			Total
Gains (losses) included in income	$	19		$	—	$	19		$	18	$	(3	)	$	15
Gains included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at June 30, 2008	$	19		$	—	$	19		$	19	$	2		$	21

Counterparty Credit Concentration Risk

The Company is exposed to the default risk of the counterparties with which the Company transacts. The Company manages its credit risk by entering into master netting agreements and requiring counterparties to post cash collateral or other credit enhancements based on the net exposure and the credit standing of the counterparty. The Company also has non-collateralized power hedges entered into by Mirant Mid-Atlantic. These transactions are senior unsecured obligations of Mirant Mid-Atlantic and the counterparties and do not require either party to post cash collateral for initial margin or for securing exposure as a result of changes in power or natural gas prices. The Company’s credit reserve on its derivative contract assets was $25 million and $52 million at June 30, 2009 and December 31, 2008, respectively.

At June 30, 2009 and December 31, 2008, approximately $45 million and $20 million, respectively, of cash collateral posted to the Company by counterparties under master netting agreements were included in accounts payable and accrued liabilities on the condensed consolidated balance sheets.

The Company also monitors counterparty credit concentration risk on both an individual basis and a group counterparty basis. The following tables highlight the credit quality and the balance sheet settlement exposures related to these activities as of June 30, 2009 and December 31, 2008 (dollars in millions):


	At June 30, 2009
Credit Rating Equivalent	Gross Exposure Before Collateral¹		Net Exposure Before Collateral²		Collateral³		Exposure Net of Collateral		% of Net Exposure
Clearing and Exchange	$	1,718	$	177	$	177	$	—	—
Investment Grade:
Financial institutions		1,466		718		39		679	81	%
Energy companies		935		186		50		136	16	%
Other		—		—		—		—	—
Non-investment Grade:
Financial institutions		—		—		—		—	—
Energy companies		—		—		—		—	—
Other		—		—		—		—	—
No External Ratings:
Internally-rated investment grade		25		20		—		20	3	%
Internally-rated non-investment grade		4		4		—		4	—
Not internally rated		—		—		—		—	—

Total	$	4,148	$	1,105	$	266	$	839	100	%


	At December 31, 2008
Credit Rating Equivalent	Gross Exposure Before Collateral¹		Net Exposure Before Collateral²		Collateral³		Exposure Net of Collateral		% of Net Exposure
Clearing and Exchange	$	1,428	$	107	$	107	$	—	—
Investment Grade:
Financial institutions		1,219		553		20		533	72	%
Energy companies		1,060		232		73		159	22	%
Other		—		—		—		—	—
Non-investment Grade:
Financial institutions		—		—		—		—	—
Energy companies		—		—		—		—	—
Other		—		—		—		—	—
No External Ratings:
Internally-rated investment grade		41		41		—		41	6	%
Internally-rated non-investment grade		4		4		—		4	—
Not internally rated		—		—		—		—	—

Total	$	3,752	$	937	$	200	$	737	100	%

Gross exposure before collateral represents credit exposure, including realized and unrealized transactions, before applying the terms of master netting agreements with counterparties and netting of transactions with clearing brokers and exchanges. The table excludes amounts related to contracts classified as normal purchases/normal sales and non-derivative contractual commitments that are not recorded at fair value in the condensed consolidated balance sheets, except for any related accounts receivable. Such contractual commitments contain credit and economic risk if a counterparty does not perform. Non-performance could have a material adverse effect on the future results of operations, financial condition and cash flows.

²	Net exposure before collateral represents the credit exposure, including both realized and unrealized transactions, after applying the terms of master netting agreements.

³	Collateral includes cash and letters of credit received from counterparties.

The Company had credit exposure to three investment grade counterparties that each represented an exposure of more than 10% of total credit exposure, net of collateral. The aggregate credit exposure, net of collateral, to such counterparties was $528 million and $491 million at June 30, 2009 and December 31, 2008, respectively.

Mirant Credit Risk

The Company’s standard industry contracts contain credit-risk-related contingent features such as ratings-related thresholds and adequate assurance language whereby the Company would be required to post additional cash collateral as a result of a credit event, including a downgrade. However, as a result of the Company’s current credit rating, the Company is typically required to post collateral in the normal course of business to offset completely its net liability positions. At June 30, 2009, the fair value of the Company’s financial instruments with credit-risk-related contingent features in a net liability position was approximately $8 million for which the Company posted collateral, including cash and letters of credit, of $8 million to offset the position.

In addition, at both June 30, 2009 and December 31, 2008, the Company had approximately $1 million of cash collateral posted with counterparties under master netting agreements that was included in funds on deposit on the condensed consolidated balance sheets.

Fair Values of Other Financial Instruments

Other financial instruments recorded at fair value include cash and interest-bearing cash equivalents. The following methods are used by Mirant to estimate the fair value of financial instruments that are not otherwise carried at fair value on the accompanying condensed consolidated balance sheets:

Notes and Other Receivables. The fair value of Mirant’s notes receivable are estimated using interest rates it would receive currently for similar types of arrangements.

Long- and Short-Term Debt. The fair value of Mirant’s long- and short-term debt is estimated using quoted market prices, when available.

The carrying amounts and fair values of Mirant’s financial instruments are as follows (in millions):


	At June 30, 2009				At December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Notes and other receivables	$	7	$	6	$	13	$	12

Liabilities:
Long- and short-term debt	$	2,635	$	2,385	$	2,676	$	2,345

D. Impairments on Assets Held and Used

Bowline Generating Facility

Background

During the second quarter of 2009, the NYISO issued its annual peak load and energy forecast in its Load and Capacity Data report (the “Gold Book”). The Gold Book reports projected supply and demand for the New York control area for the next ten years. The Gold Book reflected a significant decrease in future demand as a result of current economic conditions and the expected future effects of demand-side management programs in New York. The reduction in

future demand as a result of demand-side management programs is being driven primarily by an energy efficiency program being instituted within the State of New York that will seek to achieve a 15% reduction from 2007 energy volumes by 2015. The decrease in the projected future demand resulted in a decrease in the Company’s forecast of the capacity revenue that its 1,139 MW Bowline generating facility will earn in future periods.

In addition to the change in the forecasted capacity revenue, Mirant Bowline also received its property tax assessment during the second quarter of 2009. The assessment significantly exceeds the estimated fair value of the generating facility.

Based on the Company’s current five-year forecast incorporating these developments, Mirant Bowline is projected to operate at a net loss for the current year and to continue to have operating losses for the next several years because of the excessive level of taxation imposed on the Bowline generating facility combined with the forecasted decrease in capacity revenues. Therefore, the Company determined that the Bowline generating facility should be evaluated for impairment in the second quarter of 2009.

Asset Grouping

For purposes of impairment testing, a long-lived asset or assets must be grouped at the lowest level of identifiable cash flows. The Company included its Hudson Valley Gas subsidiary in the impairment analysis as the pipeline operated by Hudson Valley Gas relates solely to the supply of gas for the Bowline generating facility.

Assumptions and Results

The Company developed estimates related to the future costs of the facility, including future property tax payments. Additionally, the Company developed capacity and energy revenue forecasts based on supply and demand assumptions from the NYISO’s Gold Book and proprietary fundamental modeling. The Company also assumed it would monetize excess emissions allowances by selling them. The cash flows for the Bowline generating facility were projected through its estimated remaining useful life of 2027. The sum of the probability weighted undiscounted cash flows for the Bowline generating facility exceeded the carrying value as of June 30, 2009. As a result, the Company did not record an impairment charge for the three and six months ended June 30, 2009.

E. Long-Term Debt

Long-term debt was as follows (dollars in millions):


	At June 30, 2009			At December 31, 2008			Interest Rate	Secured/ Unsecured
Long-term debt:
Mirant Americas Generation:
Senior notes:
Due 2011	$	535		$	535		8.30%	Unsecured
Due 2021		450			450		8.50%	Unsecured
Due 2031		400			400		9.125%	Unsecured
Unamortized debt premiums (discounts), net		(3	)		(3	)
Mirant North America:
Senior secured term loan, due 2009 to 2013		376			415		LIBOR + 1.75%	Secured
Senior notes, due 2013		850			850		7.375%	Unsecured
Capital leases, due 2009 to 2015		27			29		7.375% - 8.19%

Total		2,635			2,676
Less: current portion of long-term debt		(41	)		(46	)

Total long-term debt, net of current portion	$	2,594		$	2,630

Mirant Americas Generation Senior Notes

The senior notes are senior unsecured obligations of Mirant Americas Generation having no recourse to any subsidiary or affiliate of Mirant Americas Generation.

Mirant North America Senior Secured Credit Facilities

Mirant North America, a wholly-owned subsidiary of Mirant Americas Generation, entered into senior secured credit facilities in January 2006, which are comprised of a senior secured term loan, due January 2013, and a senior secured revolving credit facility, due January 2012. The senior secured term loan had an initial principal balance of $700 million, which has amortized to $376 million as of June 30, 2009. At the closing, $200 million drawn under the senior secured term loan was deposited into a cash collateral account to support the issuance of up to $200 million of letters of credit. Although the senior secured revolving credit facility has lender commitments of $800 million, availability thereunder reflects a $45 million reduction as a result of the expectation that Lehman Commercial Paper, Inc., which filed for bankruptcy in October 2008, will not honor its $45 million commitment under the facility. During 2008, Mirant North America transferred to the senior secured revolving credit facility approximately $78 million of letters of credit previously supported by the cash collateral account and withdrew approximately $78 million from the cash collateral account, thereby reducing the cash collateral account to approximately $122 million. At June 30, 2009, the cash collateral balance was approximately $123 million as a result of interest earned on the invested cash balances. At June 30, 2009, there were approximately $139 million of letters of credit outstanding under the senior secured revolving credit facility and $123 million of letters of credit outstanding under the senior secured term loan cash collateral account. At June 30, 2009, $615.8 million was available under the senior secured revolving credit facility and $0.2 million was available under the senior secured term loan for cash draws or for the issuance of letters of credit.

In addition to quarterly principal installments, which are currently $1.2 million, Mirant North America is required to make annual principal prepayments under the senior secured term loan equal to a specified percentage of its excess free cash flow, which is based on adjusted EBITDA less capital expenditures and as further defined in the loan agreement. On March 19, 2009, Mirant North America made a mandatory principal prepayment of approximately $37 million on the term loan. At June 30, 2009, the current estimate of the mandatory principal prepayment of the term loan in March 2010 is approximately $32 million. This amount has been reclassified from long-term debt to current portion of long-term debt at June 30, 2009.

The senior secured credit facilities are senior secured obligations of Mirant North America. In addition, certain subsidiaries of Mirant North America (not including Mirant Mid-Atlantic or Mirant Energy Trading) have jointly and severally guaranteed, as senior secured obligations, the senior secured credit facilities. The senior secured credit facilities have no recourse to any other Mirant entities.

Mirant North America Senior Notes

The senior notes due in 2013 are senior unsecured obligations of Mirant North America. In addition, certain subsidiaries of Mirant North America (not including Mirant Mid-Atlantic or Mirant Energy Trading) have jointly and severally guaranteed, as senior unsecured obligations, the senior notes. The Mirant North America senior notes have no recourse to any other Mirant entities, including Mirant Americas Generation.

F. Guarantees and Letters of Credit

Mirant generally conducts its business through various operating subsidiaries, which enter into contracts as a routine part of their business activities. In certain instances, the contractual obligations of such subsidiaries are guaranteed by, or otherwise supported by, Mirant or another of its subsidiaries, including guarantees or letters of credit issued under the credit facilities of Mirant North America.

In addition, Mirant and its subsidiaries enter into various contracts that include indemnification and guarantee provisions. Examples of these contracts include financing and lease arrangements, purchase and sale agreements, commodity purchase and sale agreements, construction agreements and agreements with vendors. Although the primary obligation of Mirant or a subsidiary under such contracts is to pay money or render performance, such contracts may include obligations to indemnify the counterparty for damages arising from the breach thereof and, in certain instances, other existing or potential liabilities. In many cases, the Company’s maximum potential liability cannot be estimated, because some of the underlying agreements contain no limits on potential liability.

Upon issuance or modification of a guarantee, the Company determines if the obligation is subject to initial recognition and measurement of a liability and/or disclosure of the nature and terms of the guarantee under FIN 45. Generally, guarantees of the performance of a third party are subject to the recognition and measurement, as well as the disclosure provisions, of FIN 45. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation. The Company did not have any guarantees at June 30, 2009, that met the recognition requirements under FIN 45.

For the six months ended June 30, 2009, Mirant had net decreases to its guarantees of approximately $43 million, which included a decrease of approximately $32 million to its letters of credit, a decrease of $9 million to its surety bonds and a decrease of $2 million in other guarantees.

This Note should be read in conjunction with the complete description under Note 10, Commitments and Contingencies—Guarantees, to the Company’s financial statements in its 2008 Annual Report on Form 10-K .

G. Pension and Other Postretirement Benefit Plans

Mirant has various defined benefit and defined contribution pension plans, and other postretirement benefit plans. For a further discussion of these plans see Note 8. Employee Benefit Plans in the Company’s 2008 Annual Report on Form 10-K.

Net Periodic Benefit Cost (Credit)

The components of the net periodic benefit cost (credit) are shown below (in millions):


	Pension Plans						Other Postretirement Benefit Plans
	Three Months Ended June 30,						Three Months Ended June 30,
	2009			2008			2009			2008
Service cost	$	2		$	2		$	—		$	—
Interest cost		4			4			1			1
Expected return of plan assets		(5	)		(4	)		—			—
Net amortization¹		—			—			(1	)		(1	)
Curtailments		—			(1	)		—			(4	)

Net periodic benefit cost (credit)	$	1		$	1		$	—		$	(4	)


	Pension Plans						Other Postretirement Benefit Plans
	Six Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Service cost	$	4		$	4		$	1		$	1
Interest cost		8			8			2			2
Expected return of plan assets		(11	)		(8	)		—			—
Net amortization¹		1			—			(3	)		(3	)
Curtailments		—			(1	)		—			(4	)

Net periodic benefit cost (credit)	$	2		$	3		$	—		$	(4	)

¹	Net amortization amount includes prior service costs and actuarial gains or losses.

H. Stock-based Compensation

On March 3, 2009, the Company granted stock options and issued restricted stock units to executives and certain other employees under the Mirant Corporation 2005 Omnibus Incentive Compensation Plan. The stock options have a ten-year term and the stock options and restricted stock units vest in three equal installments on each of the first, second and third anniversaries of the grant date. The stock options have an exercise price of $10.40, the Company’s closing stock price on the day of the grant, and a grant date fair value of $5.88. The restricted stock units have a grant date fair value of $10.40, the Company’s closing stock price on the day of the grant.

On May 12, 2009, the Company issued restricted stock units to non-management members of the Board of Directors under the Mirant Corporation 2005 Omnibus Incentive Compensation Plan. The restricted stock units vest on the first anniversary of the grant date and delivery of the underlying shares is deferred until their directorship terminates. The restricted stock units have a grant date fair value of $15.13, the Company’s closing stock price on the day of the grant.

During the quarter ended June 30, 2009, Mirant announced that certain of its executives would leave the Company. In accordance with the terms of their respective separation agreements, certain executives agreed to the cancellation of a portion of the stock options and restricted stock units granted on March 3, 2009, which otherwise would have vested in full pursuant to the terms of each executive’s employment agreement. For the three and six months ended June 30, 2009, the Company recognized approximately $7 million of stock-based compensation expense associated with the accelerated vesting and cancellation of awards related to the separation of these executives.

During the three and six months ended June 30, 2009, the Company recognized approximately $12 million and $16 million, respectively, of compensation expense related to stock options, restricted shares and restricted stock units, which includes compensation expense associated with the separation of certain executives discussed above. The Company recognized approximately $6 million and $13 million, respectively, of compensation expense related to stock options, restricted shares and restricted stock units for the three and six months ended June 30, 2008. These amounts are included in operations and maintenance expense in the unaudited condensed consolidated statements of operations. As of June 30, 2009, there was approximately $30 million of total unrecognized compensation cost, excluding estimated forfeitures, related to non-vested stock-based awards.

Stock-based compensation activity for the six months ended June 30, 2009, is as follows:

Stock Options—Service-based


	Number of Options			Weighted Average Exercise Price		Aggregate Intrinsic Value¹ (in millions)
Outstanding at January 1, 2009		2,870,996		$	29.83
Granted		1,390,552		$	10.40
Exercised or converted		(479	)	$	10.40
Forfeited or cancelled		(143,723	)	$	10.98
Expired		(11,714	)	$	31.74

Outstanding at June 30, 2009		4,105,632		$	23.91	$	6.7

Exercisable or convertible at June 30, 2009		2,445,631		$	27.63	$	0.5

Cash proceeds from exercise of options for the six months ended June 30, 2009	$	—

¹	Aggregate intrinsic value is calculated based on the closing stock price at June 30, 2009, of $15.74.

Stock Options—Performance-based


	Number of Options	Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions)
Outstanding at January 1, 2009 and June 30, 2009	730,000	$	28.89

Exercisable or convertible at June 30, 2009	730,000	$	28.89	$	—

Restricted Stock Units and Restricted Stock Shares—Service-based


	Number of Units/ Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2009	695,819		$	34.98
Granted	1,601,028		$	10.53
Vested	(510,542	)	$	29.48
Forfeited or cancelled	(140,003	)	$	10.69

Outstanding at June 30, 2009	1,646,302		$	14.98

I. Earnings Per Share

Mirant calculates basic EPS by dividing income available to stockholders by the weighted average number of common shares outstanding. Diluted EPS gives effect to dilutive potential common shares, including unvested restricted shares and restricted stock units, stock options and warrants. As a result of the net loss for the three and six months ended June 30, 2008, diluted EPS was computed in the same manner as basic EPS in accordance with SFAS 128.

The following table shows the computation of basic and diluted EPS (in millions except per share data):


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
Income (loss) from continuing operations	$	163	$	(832	)	$	543	$	(986	)
Income from discontinued operations		—		49			—		51

Net income (loss)	$	163	$	(783	)	$	543	$	(935	)

Basic and diluted:
Weighted average shares outstanding—basic		145		201			145		209
Shares from assumed exercise of warrants and options		—		23			—		22
Shares from assumed vesting of restricted stock and restricted stock units		—		1			—		1

Weighted average shares outstanding—diluted		145		225			145		232

Basic EPS
EPS from continuing operations	$	1.12	$	(4.14	)	$	3.74	$	(4.72	)
EPS from discontinued operations		—		0.24			—		0.25

Basic EPS	$	1.12	$	(3.90	)	$	3.74	$	(4.47	)

Diluted EPS
EPS from continuing operations	$	1.12	$	(4.14	)	$	3.74	$	(4.72	)
EPS from discontinued operations		—		0.24			—		0.25

Diluted EPS	$	1.12	$	(3.90	)	$	3.74	$	(4.47	)

For the three and six months ended June 30, 2009, the number of securities that are considered antidilutive increased significantly compared to the same period in 2008, as a result of the decrease in the Company’s weighted average stock price. The weighted average number of securities that could potentially dilute basic EPS in the future that were not included in the computation of diluted EPS because to do so would have been antidilutive were as follows:


	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008	2009	2008
	(shares in millions)
Series A Warrants	26.87	—	26.87	—
Series B Warrants	7.05	—	7.05	—
Restricted shares and restricted share units	0.30	0.01	0.65	0.05
Stock options	4.88	1.22	4.46	0.97

Total number of antidilutive shares	39.10	1.23	39.03	1.02

J. Stockholders’ Equity

Stockholder Rights Plan

On March 26, 2009, Mirant announced the adoption of a stockholder rights plan (the “Stockholder Rights Plan”) to help protect the Company’s use of its federal NOLs from certain restrictions contained in Section (“§”) 382 of the Internal Revenue Code of 1986, as amended. In general, an ownership change would occur if certain shifts in ownership of the Company’s stock exceed 50 percentage points measured over a specified period of time. Given §382’s broad definition, an ownership change could be the unintended consequence of otherwise normal market trading in the Company’s stock that is outside the Company’s control. The Stockholder Rights Plan was adopted to reduce the likelihood of such an unintended ownership change occurring. However, there can be no assurance that the Stockholder Rights Plan will prevent such an ownership change.

Under the Stockholder Rights Plan, when a person or group has obtained beneficial ownership of 4.9% or more of the Company’s common stock, or an existing holder with greater than 4.9% ownership acquires more shares representing at least an additional 0.2% of the Company’s common stock, there would be a triggering event causing potential significant dilution in the economic interest and voting power of such person or group. Such triggering event would also occur if an existing holder with greater than 4.9% ownership but less than 5.0% ownership acquires more shares that would result in such stockholder obtaining beneficial ownership of 5.0% or more of the Company’s common stock. The Board of Directors has the discretion to exempt an acquisition of common stock from the provisions of the Stockholder Rights Plan if it determines the acquisition will not jeopardize tax benefits or is otherwise in the Company’s best interests.

This Stockholder Rights Plan is limited in life, and the rights expire upon the earliest of (1) the Board of Directors’ determination that the plan is no longer needed for the preservation of NOLs as a result of the implementation of legislative changes or any other change; (2) March 25, 2010; or (3) certain other events described in the Stockholder Rights Plan.

K. Segment Reporting

The Company has four operating segments: Mid-Atlantic, Northeast, California and Other Operations. The Mid-Atlantic segment consists of four generating facilities located in Maryland and Virginia with total net generating capacity of 5,230 MW. The Northeast segment consists of three generating facilities located in Massachusetts and one generating facility located in New York with

total net generating capacity of 2,535 MW. For the three and six months ended June 30, 2008, the Northeast region also included the Lovett generating facility, which was shut down on April 19, 2008. The California segment consists of three generating facilities located in or near the City of San Francisco, with total net generating capacity of 2,347 MW and includes business development efforts for new generation in California. Other Operations includes proprietary trading and fuel oil management activities, unallocated corporate overhead, interest expense on debt at Mirant Americas Generation and Mirant North America and interest income on the Company’s invested cash balances. In the following tables, eliminations are primarily related to intercompany sales of emissions allowances and interest on intercompany notes receivable and notes payable.

Operating Segments


	Mid- Atlantic			Northeast		California		Other Operations			Eliminations			Total
	(in millions)
Three Months Ended June 30, 2009:
Operating revenues¹	$	391		$	58	$	33	$	14		$	—		$	496
Cost of fuel, electricity and other products²		134			13		4		(1	)		—			150

Gross margin		257			45		29		15			—			346

Operating Expenses:
Operations and maintenance		101			35		24		(45	)		—			115
Depreciation and amortization		24			5		5		2			—			36
Gain on sales of assets, net		(2	)		—		—		—			—			(2	)

Total operating expenses (income)		123			40		29		(43	)		—			149

Operating income		134			5		—		58			—			197
Total other expense, net		1			—		—		33			—			34

Income from continuing operations before income taxes		133			5		—		25			—			163
Provision for income taxes		—			—		—		—			—			—

Income from continuing operations	$	133		$	5	$	—	$	25		$	—		$	163

Total assets at June 30, 2009	$	6,548		$	715	$	160	$	7,964		$	(3,797	)	$	11,590

¹	Includes unrealized losses of $4 million, $6 million and $34 million for Mid-Atlantic, Northeast and Other Operations, respectively.

²	Includes unrealized gains of $4 million and $26 million for Mid-Atlantic and Northeast, respectively.


	Mid- Atlantic			Northeast			California			Other Operations			Eliminations			Total
	(in millions)
Six Months Ended June 30, 2009:
Operating revenues¹	$	1,063		$	210		$	68		$	36		$	(3	)	$	1,374
Cost of fuel, electricity and other products²		299			101			12			9			—			421

Gross margin		764			109			56			27			(3	)		953

Operating Expenses:
Operations and maintenance		206			67			43			(39	)		—			277
Depreciation and amortization		48			9			10			5			—			72
Gain on sales of assets, net		(10	)		(2	)		(1	)		—			(4	)		(17	)

Total operating expenses (income)		244			74			52			(34	)		(4	)		332

Operating income		520			35			4			61			1			621
Total other expense, net		2			—			1			67			—			70

Income (loss) from continuing operations before income taxes		518			35			3			(6	)		1			551
Provision for income taxes		—			—			—			8			—			8

Income (loss) from continuing operations	$	518		$	35		$	3		$	(14	)	$	1		$	543

Total assets at June 30, 2009	$	6,548		$	715		$	160		$	7,964		$	(3,797	)	$	11,590

¹	Includes unrealized gains of $238 million and $22 million for Mid-Atlantic and Northeast, respectively, and unrealized losses of $49 million for Other Operations.

²	Includes unrealized gains of $5 million and $24 million for Mid-Atlantic and Northeast, respectively.


	Mid- Atlantic			Northeast			California			Other Operations			Eliminations			Total
	(in millions)
Three Months Ended June 30, 2008:
Operating revenues¹	$	(499	)	$	113		$	44		$	(51	)	$	—		$	(393	)
Cost of fuel, electricity and other products²		106			63			13			(16	)		—			166

Gross margin		(605	)		50			31			(35	)		—			(559	)

Operating Expenses:
Operations and maintenance		113			56			22			12			—			203
Depreciation and amortization		23			4			10			3			—			40
Loss (gain) on sales of assets, net		(2	)		(12	)		(1	)		—			3			(12	)

Total operating expenses		134			48			31			15			3			231

Operating income (loss)		(739	)		2			—			(50	)		(3	)		(790	)
Total other expense, net		—			1			—			31			—			32

Income (loss) from continuing operations before income taxes		(739	)		1			—			(81	)		(3	)		(822	)
Provision for income taxes		—			—			—			10			—			10

Income (loss) from continuing operations	$	(739	)	$	1		$	—		$	(91	)	$	(3	)	$	(832	)

Total assets at December 31, 2008	$	5,620		$	722		$	181		$	7,253		$	(3,088	)	$	10,688

¹	Includes unrealized losses of $829 million, $27 million and $55 million for Mid-Atlantic, Northeast and Other Operations, respectively.

²	Includes unrealized gains of $11 million and $26 million for Mid-Atlantic and Northeast, respectively.


	Mid- Atlantic			Northeast			California			Other Operations			Eliminations			Total
	(in millions)
Six Months Ended June 30, 2008:
Operating revenues¹	$	(389	)	$	254		$	86		$	(42	)	$	—		$	(91	)
Cost of fuel, electricity and other products²		252			152			26			(24	)		—			406

Gross margin		(641	)		102			60			(18	)		—			(497	)

Operating Expenses:
Operations and maintenance		210			97			40			22			—			369
Depreciation and amortization		44			10			14			5			—			73
Loss (gain) on sales of assets, net		(2	)		(16	)		(1	)		—			3			(16	)

Total operating expenses		252			91			53			27			3			426

Operating income (loss)		(893	)		11			7			(45	)		(3	)		(923	)
Total other expense, net		—			—			—			53			—			53

Income (loss) from continuing operations before income taxes		(893	)		11			7			(98	)		(3	)		(976	)
Provision for income taxes		—			—			—			10			—			10

Income (loss) from continuing operations	$	(893	)	$	11		$	7		$	(108	)	$	(3	)	$	(986	)

Total assets at December 31, 2008	$	5,620		$	722		$	181		$	7,253		$	(3,088	)	$	10,688

¹	Includes unrealized losses of $1.124 billion, $40 million and $49 million for Mid-Atlantic, Northeast and Other Operations, respectively.

²	Includes unrealized gains of $6 million and $30 million for Mid-Atlantic and Northeast, respectively.

L. Litigation and Other Contingencies

The Company is involved in a number of significant legal proceedings. In certain cases, plaintiffs seek to recover large and sometimes unspecified damages, and some matters may be unresolved for several years. The Company cannot currently determine the outcome of the proceedings described below or the ultimate amount of potential losses and therefore has not made any provision for such matters unless specifically noted below. Pursuant to SFAS 5, management provides for estimated losses to the extent information becomes available indicating that losses are probable and that the amounts are reasonably estimable. Additional losses could have a material adverse effect on the Company’s results of operations, financial position or cash flows.

Environmental Matters

EPA Information Request. In January 2001, the EPA issued a request for information to Mirant concerning the implications under the EPA’s NSR regulations promulgated under the Clean Air Act of past repair and maintenance activities at the Potomac River facility in Virginia and the Chalk Point, Dickerson and Morgantown facilities in Maryland. The requested information concerned the period of operations that predates the ownership and lease of those facilities by Mirant Potomac River, Mirant Chalk Point and Mirant Mid-Atlantic. Mirant responded fully to this request. Under the APSA, Pepco is responsible for fines and penalties arising from any violation of the NSR regulations associated with operations prior to the acquisition or lease of the facilities by Mirant Potomac River, Mirant Chalk Point and Mirant Mid-Atlantic. If a violation is determined to have occurred at any of the facilities, Mirant Potomac River, Mirant Chalk Point and Mirant Mid-Atlantic, as the owner or lessee of the facility, may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. Mirant Chalk Point and Mirant Mid-Atlantic have installed and are installing a variety of emissions control equipment on the Chalk Point, Dickerson and Morgantown facilities in Maryland to comply with the Maryland Healthy Air Act, but that equipment may not include all of the emissions control equipment that could be required if a violation of the EPA’s NSR regulations is determined to have occurred at one or more of those facilities. If such a violation is determined to have occurred after the acquisition or lease of the facilities by Mirant Potomac River, Mirant Chalk Point and Mirant Mid-Atlantic or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, Mirant Potomac River, Mirant Chalk Point or Mirant Mid-Atlantic could also be subject to fines and penalties by the state or federal government for the period after its acquisition or lease of the facility at issue, the cost of which may be material, although applicable bankruptcy law may bar such liability for periods prior to January 3, 2006, when the Plan became effective for Mirant Potomac River, Mirant Chalk Point and Mirant Mid-Atlantic.

Faulkner Fly Ash Facility. By letter dated April 2, 2008, the Environmental Integrity Project and the Potomac Riverkeeper notified Mirant and various of its subsidiaries that they and certain individuals intend to file suit alleging that violations of the Clean Water Act are occurring at the Faulkner Fly Ash Facility owned by Mirant MD Ash Management. The April 2, 2008, letter alleges that the Faulkner facility discharges certain pollutants at levels that exceed Maryland’s water quality criteria, that it discharged certain pollutants without obtaining an appropriate National Pollutant Discharge Elimination System (“NPDES”) permit, and that Mirant MD Ash Management failed to perform monthly monitoring required under an applicable NPDES permit. The letter indicated that the organizations intend to file suit to enjoin the violations alleged, to obtain civil penalties for past violations occurring after January 3, 2006, and to recover attorneys’ fees. Mirant disputes the allegations of violations of the Clean Water Act made by the two organizations in the April 2, 2008, letter.

In May 2008, the MDE filed a complaint in the Circuit Court for Charles County, Maryland, against Mirant MD Ash Management and Mirant Mid-Atlantic. The complaint alleges violations of Maryland’s water pollution laws similar to those asserted in the April 2, 2008, letter from the Environmental Integrity Project and the Potomac Riverkeeper. The MDE complaint requests that the court (1) prohibit continuation of the alleged unpermitted discharges, (2) require Mirant MD Ash Management and Mirant Mid-Atlantic to cease from disposing of any further coal combustion byproducts at the Faulkner Fly Ash Facility and close and cap the existing disposal cells within one year and (3) assess civil penalties of up to $10,000 per day for each violation. The discharges that are the subject of the MDE’s complaint result from a leachate treatment system installed by Mirant MD Ash Management in accordance with a December 18, 2000, Complaint and Consent Order (the “December 2000 Consent Order”) entered by the Maryland Secretary of the Environment, Water Management Administration pursuant to an agreement between the MDE and Pepco, the previous owner of the Faulkner Fly Ash Facility. Mirant MD Ash Management and Mirant Mid-Atlantic on July 23, 2008, filed a motion seeking dismissal of the MDE complaint, arguing that the discharges are permitted by the December 2000 Consent Order.

Suit Regarding Chalk Point Emissions. On June 25, 2009, the Chesapeake Climate Action Network and four individuals filed a complaint against Mirant Mid-Atlantic and Mirant Chalk Point in the United States District Court for the District of Maryland. The plaintiffs allege that Mirant Chalk Point has violated the Clean Air Act and Maryland environmental regulations by failing to install controls to limit emissions of particulate matter on Unit 3 and Unit 4 of the Chalk Point generating facility, which at times burn residual fuel oil. The plaintiffs seek to enjoin the alleged violations, to obtain civil penalties of up to $32,500 per day for past noncompliance and to recover attorney’s fees. Mirant Mid-Atlantic and Mirant Chalk Point dispute the plaintiffs’ allegations of violations of the Clean Air Act and Maryland environmental regulations.

New York State Administrative Claims. On January 24, 2006, the State of New York and the NYSDEC filed a notice of administrative claims in the Company’s Chapter 11 proceedings asserting a claim seeking to require the Company to provide funding to its subsidiaries owning generating facilities in New York to satisfy certain specified environmental compliance obligations, citing various then outstanding matters between the State and the Company’s subsidiaries owning generating facilities in New York related to compliance with environmental laws and regulations. On April 12, 2008, the State of New York and the NYSDEC filed a separate notice of administrative claims in the bankruptcy proceedings of Mirant New York, Mirant Bowline and Mirant Lovett (all of which emerged from bankruptcy in 2007) alleging various potential violations of New York environmental laws and regulations related to the operation of the Bowline and Lovett generating facilities during the period those entities were in bankruptcy. Except for the alleged violations described below in Lovett Coal Ash Management Facility Notice of Hearing and Complaint, all of the matters or alleged violations set out in the January 24, 2006, and April 12, 2008, administrative claims have now been resolved.

Riverkeeper Suit Against Mirant Lovett. On March 11, 2005, Riverkeeper, Inc. filed suit against Mirant Lovett in the United States District Court for the Southern District of New York under the Clean Water Act. The suit alleges that Mirant Lovett failed to implement a marine life exclusion system at its Lovett generating facility and to perform monitoring for the exclusion of certain aquatic organisms from the facility’s cooling water intake structures in violation of Mirant Lovett’s water discharge permit issued by the State of New York. The plaintiff requested the court to impose civil penalties of $32,500 per day of violation and to award the plaintiff attorneys’ fees. Mirant Lovett’s view is that it complied with the terms of its water discharge permit, as amended by a Consent Order entered June 29, 2004. Mirant Lovett has filed a motion seeking dismissal of the suit on the grounds that it complied with the terms of its water discharge permit, the closure of the Lovett generating facility in April 2008 moots the plaintiff’s request for injunctive relief, and the discharge in bankruptcy received by Mirant Lovett in 2007 bars any claim for penalties.

Lovett Coal Ash Management Facility Notice of Hearing and Complaint. On April 16, 2008, the staff of the NYSDEC filed a complaint with the NYSDEC against Mirant Lovett alleging various violations of New York’s Environmental Conservation Law arising from the coal ash management facility (“CAMF”) located near the former Lovett generating facility, including the alleged discharge of pollutants into the groundwater in excess of allowed levels. The complaint also contends that Mirant Lovett failed to provide an adequate Leachate Assessment Report related to the CAMF that the NYSDEC staff asserts was required under the terms of a Consent Order dated June 2, 2006. The complaint requests that Mirant Lovett be required to perform various assessments related to groundwater quality and causes of leachate from the CAMF and seeks assessment of a civil penalty of $200,000 and the recovery of $15,000 for the portion of a penalty imposed under the June 2, 2006, Consent Order that had been suspended. On July 17, 2009, Mirant Lovett and the NYSDEC entered into a consent order that resolved the proceeding initiated by the NYSDEC staff’s April 16, 2008, complaint. Under the consent order, Mirant Lovett is to investigate the nature, extent and source of sulfate contamination, and any other contamination, that may be on or emanating from the CAMF or the property on which the former Lovett generating facility was located, and provide a report of its investigation to the NYSDEC. If Mirant Lovett fails to comply with the consent order, it is to pay a civil penalty of $30,000.

Notices of Intent to Sue for Alleged Violations of the Endangered Species Act. By letter dated September 27, 2007, the Coalition for a Sustainable Delta, four water districts, and an individual (the “Noticing Parties”) provided notice to Mirant and Mirant Delta of their intent to file suit alleging that Mirant Delta has violated, and continues to violate, the Federal Endangered Species Act through the operation of its Contra Costa and Pittsburg generating facilities. The Noticing Parties contend that the facilities use of water drawn from the Sacramento-San Joaquin Delta for cooling purposes results in harm to four species of fish listed as endangered species. The Noticing Parties assert that Mirant Delta’s authorizations to take (i.e., cause harm to) those species, a biological opinion and incidental take statement issued by the National Marine Fisheries Service on October 17, 2002, for three of the fish species and a biological opinion and incidental take statement issued by the United States Fish and Wildlife Service on November 4, 2002, for the fourth fish species, have been violated by Mirant Delta and no longer apply to permit the effects on the four fish species caused by the operation of the Contra Costa and Pittsburg generating facilities. Following receipt of these letters, in late October 2007, Mirant Delta received correspondence from the United States Fish and Wildlife Service, the National Marine Fisheries Service and the United States Army Corps of Engineers (the “Corps”) clarifying that Mirant Delta continued to be authorized to take the four species of fish protected under the Federal Endangered Species Act. The agencies have initiated a process that will review the environmental effects of Mirant Delta’s water usage, including effects on the protected species of fish. That process could lead to changes in the manner in which Mirant Delta can use river water for the operation of the Contra Costa and Pittsburg generating facilities. In a subsequent letter, the Coalition for a Sustainable Delta also alleged violations of the National Environmental Policy Act and the California Endangered Species Act associated with the operation of Mirant Delta’s facilities. On May 14, 2009, the Coalition for a Sustainable Delta, Kern County Water Agency and an individual sent a new notice of intent to sue to the Corps alleging that the Corps had violated the Federal Endangered Species Act by issuing permits related to the operation of Mirant Delta’s Contra Costa and Pittsburg generating facilities without ensuring that conservation measures would be implemented to minimize and mitigate the harm to the four endangered fish species and their habitat allegedly resulting from such operation. Mirant Delta disputes the allegations made by the Noticing Parties and those made in the May 14, 2009, notice.

Notice of Violations Relating to State Line Generating Station. On April 16, 2009, the EPA issued a Notice and Finding of Violations to Mirant Americas, Dominion Resources Services, Inc., Dominion Resources, Inc. and Commonwealth Edison Company. The notice alleges that various

activities occurring from 1994 through 2008 at the Kincaid generating facility in Illinois and the State Line generating facility in Indiana violated the EPA’s NSR regulations and other provisions of the Clean Air Act. Mirant and its subsidiaries have had no ownership interest in or other involvement with the Kincaid facility. Through subsidiaries, Mirant acquired the State Line facility from a subsidiary of Commonwealth Edison Company in December 1997. Mirant sold its subsidiaries owning the State Line facility to subsidiaries of Dominion Resources in June 2002. The contracts under which Mirant acquired and sold its ownership interests in the State Line facility were rejected in Mirant’s bankruptcy proceedings, and, as a result, Mirant and its subsidiaries have no contractual obligations to either Commonwealth Edison Company and its subsidiaries or Dominion resources and its subsidiaries related to the State Line facility. Furthermore, applicable bankruptcy law may bar any liability of Mirant and its subsidiaries for fines based on events occurring in periods prior to January 3, 2006, when the Plan became effective. The EPA advised Mirant in May 2009 that it did not intend to take further action against Mirant Americas with respect to the activities addressed by the April 16, 2009, notice.

Chapter 11 Proceedings

On July 14, 2003, and various dates thereafter, Mirant Corporation and certain of its subsidiaries (collectively, the “Mirant Debtors”) filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Mirant and most of the Mirant Debtors emerged from bankruptcy on January 3, 2006, when the Plan became effective. The remaining Mirant Debtors (Mirant New York, Mirant Bowline, Mirant Lovett, Mirant NY-Gen and Hudson Valley Gas) emerged from bankruptcy on various dates in 2007. As of June 30, 2009, approximately 850,000 of the shares of Mirant common stock to be distributed under the Plan had not yet been distributed and have been reserved for distribution with respect to claims disputed by the Mirant Debtors that have not been resolved. Under the terms of the Plan, upon the resolution of such a disputed claim, the claimant will receive the same pro rata distributions of Mirant common stock, cash, or both common stock and cash as previously allowed claims, regardless of the price at which Mirant common stock is trading at the time the claim is resolved.

To the extent the aggregate amount of the payouts determined to be due with respect to disputed claims ultimately exceeds the amount of the funded claim reserve, Mirant would have to issue additional shares of common stock to address the shortfall, which would dilute existing Mirant stockholders, and Mirant and Mirant Americas Generation would have to pay additional cash amounts as necessary under the terms of the Plan to satisfy such pre-petition claims. If Mirant is required to issue additional shares of common stock to satisfy unresolved claims, certain parties who received approximately 21 million of the 300 million shares of common stock distributed under the Plan are entitled to receive additional shares of common stock to avoid dilution of their distributions under the Plan.

Actions Pursued by MC Asset Recovery

Under the Plan, the rights to certain actions filed by Mirant and various of its subsidiaries against third parties were transferred to MC Asset Recovery. MC Asset Recovery, although wholly-owned by Mirant, is governed by managers who are independent of Mirant and its other subsidiaries. Under the Plan, any cash recoveries obtained by MC Asset Recovery from the actions transferred to it, net of fees and costs incurred in prosecuting the actions, are to be paid to the unsecured creditors of Mirant Corporation in the Chapter 11 proceedings and the holders of the equity interests in Mirant immediately prior to the effective date of the Plan except where such a recovery results in an allowed claim in the bankruptcy proceedings, as described below. MC Asset Recovery is a disregarded entity for income tax purposes, and Mirant is responsible for income taxes related to its operations. The Plan provides that Mirant may not reduce payments to be made to unsecured creditors and former holders of equity interests from recoveries obtained by

MC Asset Recovery for the taxes owed by Mirant, if any, on any net recoveries up to $175 million. If the aggregate recoveries exceed $175 million net of costs, then under the Plan Mirant may reduce the payments to be made to such unsecured creditors and former holders of equity interests by the amount of any taxes it will owe or NOLs utilized with respect to taxable income resulting from the amount in excess of $175 million.

The Plan and MC Asset Recovery’s Limited Liability Company Agreement also obligate Mirant to make contributions to MC Asset Recovery as necessary to pay professional fees and certain other costs reasonably incurred by MC Asset Recovery, including expert witness fees and other costs of the actions transferred to MC Asset Recovery. In June 2008, Mirant and MC Asset Recovery, with the approval of the Bankruptcy Court, agreed to limit the total amount of funding to be provided by Mirant to MC Asset Recovery to $67.8 million, and the amount of such funding obligation not already incurred by Mirant at that time was fully accrued. Mirant is entitled to be repaid the amounts it funds from any recoveries obtained by MC Asset Recovery before any distribution is made from such recoveries to the unsecured creditors of Mirant Corporation and the former holders of equity interests.

On March 31, 2009, The Southern Company (“Southern Company”) and MC Asset Recovery entered into a settlement agreement (the “MCAR Settlement”) resolving claims asserted by MC Asset Recovery in MC Asset Recovery, LLC v. Southern Company, a suit pending in the Northern District of Georgia (the “Southern Company Litigation”). Southern Company filed a Form 8-K dated April 2, 2009, that describes the settlement and the claims that it resolves. Southern Company and MC Asset Recovery finalized certain terms of the settlement on June 8, 2009. Pursuant to the settlement, Southern Company paid $202 million to MC Asset Recovery in settlement of all claims asserted in the Southern Company Litigation. MC Asset Recovery used a portion of that payment to pay fees owed to the managers of MC Asset Recovery and other expenses of MC Asset Recovery not previously funded by Mirant, and it retained $47 million from that payment to fund future expenses and to apply against unpaid expenditures. MC Asset Recovery distributed the remaining $155 million to Mirant. In accordance with the Plan, Mirant has retained approximately $52 million of that distribution as reimbursement for the funds it had provided to MC Asset Recovery and costs it incurred related to MC Asset Recovery that had not been previously reimbursed. The Company recognized the $52 million as a reduction of operations and maintenance expense for the three and six months ended June 30, 2009. Pursuant to MC Asset Recovery’s Limited Liability Company Agreement and an order of the Bankruptcy Court dated October 31, 2006, Mirant is to distribute approximately $1.7 million to the managers of MC Asset Recovery. The remaining approximately $101 million of the amount recovered by MC Asset Recovery will be distributed 50% to the class of Mirant creditors identified in the Plan as Mirant Debtor Class 3—Unsecured Claims and 50% to Mirant Debtor Class 5—Equity Interests. Mirant expects these distributions to be made in August 2009. Once these distributions occur, Mirant will have no further obligation to provide funding to MC Asset Recovery. As a result, Mirant reversed its remaining accrual of $10 million of funding obligations as a reduction in operations and maintenance expense for the three and six months ended June 30, 2009. The Company does not expect to owe any taxes related to the MC Asset Recovery settlement with Southern Company.

Certain of the actions transferred to MC Asset Recovery seek to recover damages for fraudulent transfers that occurred prior to the filing of Mirant’s bankruptcy proceedings. Each of those actions alleges that the defendants engaged in transactions with Mirant or its subsidiaries at a time when they were insolvent or were rendered insolvent by the resulting transfers and that they did not receive fair value for those transfers. If MC Asset Recovery succeeds in obtaining any recoveries on these avoidance claims transferred to it, the party or parties from which such recoveries are obtained could seek to file claims in Mirant’s bankruptcy proceedings. Mirant would vigorously contest the allowance of any such claims on the grounds that, among other things, the avoidance claims being pursued by MC Asset Recovery seek to recover only amounts received by

third parties in excess of fair value and that the recovery of such amounts does not reinstate any enforceable pre-petition obligation that could give rise to a claim. If such a claim were to be allowed by the Bankruptcy Court as a result of a recovery by MC Asset Recovery, then the party receiving the claim would be entitled to either Mirant common stock or such stock and cash as provided under the Plan. Under such circumstances, the order entered by the Bankruptcy Court on December 9, 2005, confirming the Plan provides that Mirant would retain from the net amount recovered an amount equal to the dollar amount of the resulting allowed claim rather than distribute such amount to the unsecured creditors and former equity holders as described above. In the MCAR Settlement, Southern Company released any potential claim that Southern Company could have asserted in Mirant’s bankruptcy proceedings arising out of that settlement.

California and Western Power Markets

FERC Refund Proceedings Arising Out of California Energy Crisis. High prices experienced in California and western wholesale electricity markets in 2000 and 2001 caused various purchasers of electricity in those markets to initiate proceedings seeking refunds. Several of those proceedings remain pending either before the FERC or on appeal to the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”). The proceedings that remain pending include proceedings (1) ordered by the FERC on July 25, 2001, (the “FERC Refund Proceedings”) to determine the amount of any refunds and amounts owed for sales made by market participants, including Mirant Americas Energy Marketing, in the CAISO or the Cal PX markets from October 2, 2000, through June 20, 2001 (the “Refund Period”), (2) ordered by the FERC to determine whether there had been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest from December 25, 2000, through June 20, 2001 (the “Pacific Northwest Proceeding”), and (3) arising from a complaint filed in 2002 by the California Attorney General that sought refunds for transactions conducted in markets administered by the CAISO and the Cal PX outside the Refund Period set by the FERC and for transactions between the DWR and various owners of generation and power marketers, including Mirant Americas Energy Marketing and subsidiaries of Mirant Americas Generation. Various parties appealed the FERC orders related to these proceedings to the Ninth Circuit seeking review of a number of issues, including changing the Refund Period to include periods prior to October 2, 2000, and expanding the sales of electricity subject to potential refund to include bilateral sales made to the DWR and other parties. While various of these appeals remain pending, the Ninth Circuit ruled in orders issued on August 2, 2006, and September 9, 2004, that the FERC should consider further whether to grant relief for sales of electricity made in the CAISO and Cal PX markets prior to October 2, 2000, at rates found to be unjust, and, in the proceeding initiated by the California Attorney General, what remedies, including potential refunds, are appropriate where entities, including Mirant Americas Energy Marketing, purportedly did not comply with certain filing requirements for transactions conducted under market-based rate tariffs.

On January 14, 2005, Mirant and certain of its subsidiaries (the “Mirant Settling Parties”) entered into a Settlement and Release of Claims Agreement (the “California Settlement”) with PG&E, Southern California Edison Company, San Diego Gas and Electric Company, the CPUC, the DWR, the EOB and the Attorney General of the State of California (collectively, the “California Parties”). The California Settlement was approved by the FERC on April 13, 2005, and became effective on April 15, 2005, upon its approval by the Bankruptcy Court. The California Settlement resulted in the release of most of Mirant Americas Energy Marketing’s potential liability (1) in the FERC Refund Proceedings for sales made in the CAISO or the Cal PX markets, (2) in the Pacific Northwest Proceeding, and (3) in any proceedings at the FERC resulting from the complaint filed in 2002 by the California Attorney General. Based on the California Settlement, on April 15, 2008, the FERC dismissed Mirant Americas Energy Marketing and the other subsidiaries of the Company from the proceeding initiated by the complaint filed in 2002 by the California Attorney General.

Under the California Settlement, the California Parties and those other market participants who have opted into the settlement have released the Mirant Settling Parties, including Mirant Americas Energy Marketing, from any liability for refunds related to sales of electricity and natural gas in the western markets from January 1, 1998, through July 14, 2003. Also, the California Parties have assumed the obligation of Mirant Americas Energy Marketing to pay any refunds determined by the FERC to be owed by Mirant Americas Energy Marketing to other parties that do not opt into the settlement for transactions in the CAISO and Cal PX markets during the Refund Period, with the liability of the California Parties for such refund obligation limited to the amount of certain receivables assigned by Mirant Americas Energy Marketing to the California Parties under the California Settlement. The settlement did not relieve Mirant Americas Energy Marketing of liability for any refunds that the FERC determines it to owe (1) to participants in the Cal PX and CAISO markets that are not California Parties (or that did not elect to opt into the settlement) for periods outside the Refund Period and (2) to participants in bilateral transactions with Mirant Americas Energy Marketing that are not California Parties (or that did not elect to opt into the settlement).

Resolution of the refund proceedings that remain pending before the FERC or that currently are on appeal to the Ninth Circuit could ultimately result in the FERC concluding that the prices received by Mirant Americas Energy Marketing in some transactions occurring in 2000 and 2001 should be reduced. The Company’s view is that the bulk of any obligations of Mirant Americas Energy Marketing to make refunds as a result of sales completed prior to July 14, 2003, in the CAISO or Cal PX markets or in bilateral transactions either have been addressed by the California Settlement or have been resolved as part of Mirant Americas Energy Marketing’s bankruptcy proceedings. To the extent that Mirant Americas Energy Marketing’s potential refund liability arises from contracts that were transferred to Mirant Energy Trading as part of the transfer of the trading and marketing business under the Plan, Mirant Energy Trading may have exposure to any refund liability related to transactions under those contracts.

Mirant Americas Energy Marketing Contract Dispute with Southern California Water. On December 21, 2001, Southern California Water Company filed a complaint at the FERC seeking reformation of the purchase price of energy under a long-term contract it had entered with Mirant Americas Energy Marketing, claiming that the prices under that contract were unjust and unreasonable because, when it entered the contract, western power markets were dysfunctional and non-competitive. The contract was for the purchase of 15 MWs during the period April 1, 2001, through December 31, 2006. Upon the transfer of the assets of the trading and marketing business to Mirant Energy Trading under the Plan, Mirant Energy Trading assumed Mirant Americas Energy Marketing’s contract obligations to Southern California Water Company, including any potential refund obligations. On May 1, 2009, Mirant Energy Trading and Southern California Water Company entered into a settlement agreement under which Southern California Water Company agreed to release its claims in return for a payment from Mirant Energy Trading of $1 million. The settlement agreement became effective on May 21, 2009, upon Southern California Water Company’s withdrawal of its complaint at the FERC becoming effective.

Complaint Challenging Capacity Rates Under the RPM Provisions of PJM’s Tariff

On May 30, 2008, a variety of parties, including the state public utility commissions of Maryland, Pennsylvania, New Jersey, and Delaware, ratepayer advocates, certain electric cooperatives, various groups representing industrial electricity users, and federal agencies (the “RPM Buyers”), filed a complaint with the FERC asserting that capacity auctions held to determine capacity payments under PJM’s reliability pricing model (the “RPM”) tariff had produced rates that were unjust and unreasonable. PJM conducted the capacity auctions that are the subject of the complaint to set the capacity payments in effect under the RPM provisions of PJM’s tariff for twelve month periods beginning June 1, 2008, June 1, 2009, and June 1, 2010. The

RPM Buyers allege that (i) the time between when the auctions were held and the periods that the resulting capacity rates would be in effect were too short to allow competition from new resources in the auctions, (ii) the administrative process established under the RPM provisions of PJM’s tariff was inadequate to restrain the exercise of market power through the withholding of capacity to increase prices, and (iii) the locational pricing established under the RPM provisions of PJM’s tariff created opportunities for sellers to raise prices while serving no legitimate function. The RPM Buyers asked the FERC to reduce significantly the capacity rates established by the capacity auctions and to set June 1, 2008, as the date beginning on which any rates found by the FERC to be excessive would be subject to refund. If the FERC were to reduce the capacity payments set through the capacity auctions to the rates proposed by the RPM Buyers, the capacity revenue the Company has received or expects to receive for the period June 1, 2008 through May 31, 2011, would be reduced by approximately $600 million. On September 19, 2008, the FERC issued an order dismissing the complaint. The FERC found that no party had violated the RPM provisions of PJM’s tariff and that the prices determined during the auctions were in accordance with the tariff’s provisions. The RPM Buyers filed a request for rehearing, which the FERC denied on June 18, 2009.

Other Legal Matters

The Company is involved in various other claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company’s results of operations, financial position or cash flows.

M. Settlements and Other Charges

Potomac River Settlement

In July 2008, the City of Alexandria, Virginia (in which the Potomac River generating facility is located) and Mirant Potomac River entered into an agreement containing certain terms that were included in a proposed comprehensive state operating permit for the Potomac River generating facility issued by the Virginia DEQ that month. Under that agreement, Mirant Potomac River committed to spend $34 million over several years to reduce particulate emissions. The $34 million was placed in escrow and is included in funds on deposit and other noncurrent assets in the accompanying condensed consolidated balance sheets and in the Company’s estimated capital expenditures. On July 30, 2008, the Virginia State Air Pollution Control Board approved the comprehensive permit with terms consistent with the agreement between Mirant Potomac and the City of Alexandria, and the Virginia DEQ issued the permit on July 31, 2008.

Prior to the issuance of the comprehensive state operating permit in July 2008, the Potomac River generating facility operated under a state operating permit issued June 1, 2007, that significantly restricted the facility’s operations by imposing stringent limits on its SO2 emissions and constraining unit operations so that no more than three of the facility’s five units could operate at one time. In compliance with the comprehensive permit, in 2008 the Company merged the stacks for units 3, 4 and 5 into one stack at the Potomac River generating facility and, in January 2009, the Company merged the stacks for units 1 and 2 into one stack. With the completion of the stack mergers, the permit issued in July 2008 will not constrain operations of the Potomac River generating facility below historical operations and will allow operation of all five units at one time. Certain provisions of Virginia’s air emissions regulations adopted to implement the CAIR, however, could constrain the facility’s operations. Mirant Potomac River has challenged those regulations in court.

Item 2.

Management’s Discussion and Analysis of Results of Operations and Financial Condition

The following discussion should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto, which are included elsewhere in this report.

Overview

We are a competitive energy company that produces and sells electricity in the United States. We own or lease 10,112 MW of net electric generating capacity in the Mid-Atlantic and Northeast regions and in California. We also operate an integrated asset management and energy marketing organization based in Atlanta, Georgia.

Hedging Activities

We hedge economically a substantial portion of our Mid-Atlantic coal-fired baseload generation and certain of our Mid-Atlantic and Northeast gas and oil-fired generation through OTC transactions. However, we generally do not hedge our intermediate and peaking units for tenors greater than 12 months. A significant portion of our hedges are financial swap transactions between Mirant Mid-Atlantic and financial counterparties that are senior unsecured obligations of such parties and do not require either party to post cash collateral either for initial margin or for securing exposure as a result of changes in power or natural gas prices. At July 14, 2009, our aggregate hedge levels based on expected generation for each period were as follows:


	Aggregate Hedge Levels Based on Expected Generation
	2009		2010		2011		2012		2013
Power	100	%	84	%	44	%	41	%	24	%
Fuel	92	%	83	%	62	%	32	%	6	%

Capital Expenditures and Capital Resources

For the six months ended June 30, 2009, we paid $345 million for capital expenditures, excluding capitalized interest, of which $248 million related to compliance with the Maryland Healthy Air Act. As of June 30, 2009, we have paid approximately $1.245 billion for capital expenditures related to compliance with the Maryland Healthy Air Act. Including amounts already spent to date, we expect to incur total capital expenditures of $1.674 billion to comply with the limitations on SO2, NOx and mercury emissions imposed by the Maryland Healthy Air Act.

The following table details the expected timing of payments for our estimated capital expenditures, excluding capitalized interest, for the remaining six months of 2009 and for 2010 (in millions):


	2009		2010
Maryland Healthy Air Act	$	242	$	187
Other environmental		11		28
Maintenance		87		137
Construction		28		69
Other		13		16

Total	$	381	$	437

The 2010 estimated capital expenditures for compliance with the Maryland Healthy Air Act include amounts that are withheld from progress payments under construction contracts and that

will be paid after final completion of the project. As of June 30, 2009, we have a total contract retention liability of $94 million, of which $51 million is included in current accounts payable and accrued liabilities in our unaudited condensed consolidated balance sheet. The remainder of the contract retention liability is included in other noncurrent liabilities in our unaudited condensed consolidated balance sheet.

We expect that available cash and future cash flows from operations will be sufficient to fund these capital expenditures.

Scrubber Operating Expenses

Our capital expenditures related to compliance with the Maryland Healthy Air act include the installation of flue gas desulfurization emissions controls (“scrubbers”) at our Chalk Point, Dickerson and Morgantown coal-fired units. Beginning in the first quarter of 2010, we expect to recognize additional costs associated with operating the scrubbers. Examples of these costs include limestone, water, and chemicals used during the removal of SO2 emissions and also include handling and marketing related to the recyclable gypsum byproduct created during the scrubbing process. In addition, we expect to recognize higher depreciation expense because the scrubbers will be placed in service and we will begin depreciating the capitalized costs associated with them over the shorter of their expected life or the remaining lease term for the leased Dickerson and Morgantown generating units.

Commodity Prices

The forward prices for power, natural gas, fuel oil and coal decreased during the three and six months ended June 30, 2009, and we recognized unrealized losses of $14 million and unrealized gains of $240 million, respectively. In addition, during the three and six months ended June 30, 2009, the average spot market price for power decreased at a faster pace than the decline in the average market price of coal. As a result, the energy gross margin from our baseload coal units was negatively affected by contracting “dark spreads,” the difference between the price received for electricity generated compared to the market price of the coal required to produce the electricity. However, we are generally economically neutral for that portion of the portfolio that we have hedged because our realized gross margin will reflect the contractual prices of our power and fuel contracts.

Our coal supply comes primarily from the Central Appalachian and Northern Appalachian coal regions. We enter into contracts of varying tenors to secure appropriate quantities of fuel that meet the varying specifications of our generating facilities. For our coal-fired generating facilities, we purchase coal from a variety of suppliers under contracts with varying lengths, some of which extend to 2013. Most of our coal contracts are not required to be recorded at fair value under SFAS 133. As such, these contracts are not included in derivative contract assets and liabilities in the accompanying condensed consolidated balance sheets. As of June 30, 2009, the estimated net fair value of these long-term coal agreements was approximately $(186) million.

Granted Emissions Allowances

As a result of the capital expenditures we are incurring to comply with the requirements of the Maryland Healthy Air Act, we anticipate that we will have excess SO2 and NOx emissions allowances in future periods. We plan to continue to maintain some SO2 and NOx emissions allowances above those needed for our current expected generation in case our actual generation exceeds our current forecasts for future periods and for possible future additions of generating capacity. At June 30, 2009, the estimated fair value of our anticipated excess SO2 and NOx emissions allowances was approximately $48 million.

Results of Operations

The following discussion of our performance is organized by reportable segment, which is consistent with the way we manage our business.

In the tables below, the Mid-Atlantic region includes our Chalk Point, Dickerson, Morgantown and Potomac River facilities. The Northeast region includes our Bowline, Canal, Kendall and Martha’s Vineyard facilities. For the three and six months ended June 30, 2008, the Northeast region also included the Lovett generating facility, which was shut down on April 19, 2008. The California region includes our Contra Costa, Pittsburg and Potrero facilities. Other Operations includes proprietary trading and fuel oil management activities. Other Operations also includes unallocated corporate overhead, interest expense on debt at Mirant Americas Generation and Mirant North America and interest income on our invested cash balances.

Three Months Ended June 30, 2009 versus Three Months Ended June 30, 2008

Consolidated Financial Performance

We reported net income of $163 million for the three months ended June 30, 2009, compared to a net loss of $783 million for the same period in 2008. The change in net income (loss) is detailed as follows (in millions):


	Three Months Ended June 30,						Increase/ (Decrease)
	2009			2008			Increase/ (Decrease)
Realized gross margin	$	360		$	315		$	45
Unrealized gross margin		(14	)		(874	)		860

Total gross margin		346			(559	)		905

Operating Expenses:
Operations and maintenance		115			203			(88	)
Depreciation and amortization		36			40			(4	)
Gain on sales of assets, net		(2	)		(12	)		10

Total operating expenses, net		149			231			(82	)

Operating income (loss)		197			(790	)		987
Total other expense, net		34			32			2

Income (loss) from continuing operations before income taxes		163			(822	)		985
Provision for income taxes		—			10			(10	)

Income (loss) from continuing operations		163			(832	)		995
Income from discontinued operations		—			49			(49	)

Net income (loss)	$	163		$	(783	)	$	946

The following discussion includes non-GAAP financial measures because we present our consolidated financial performance in terms of gross margin. Gross margin is our operating revenue less cost of fuel, electricity and other products, and excludes depreciation and amortization. We present gross margin, excluding depreciation and amortization, and realized gross margin separately from unrealized gross margin in order to be consistent with how we manage our business. Realized gross margin and unrealized gross margin are both non-GAAP financial measures. Realized gross margin represents our gross margin less unrealized gains and losses on derivative financial instruments for the periods presented. Conversely, unrealized gross margin is equivalent to our unrealized gains and losses on derivative financial instruments for the periods presented. Management evaluates our operating results excluding the impact of unrealized gains and losses. None of our derivative financial instruments recorded at fair value are designated as hedges under SFAS 133 and changes in their fair values are therefore recognized currently in income as unrealized gains or losses. As a result, our financial results are, at times, volatile and subject to fluctuations in value primarily because of changes in forward electricity and fuel prices. Adjusting our gross margin to exclude unrealized gains and losses provides a measure of performance that eliminates the volatility created by significant shifts in market values between periods. However, our realized and unrealized gross margin may not be comparable to similarly titled non-GAAP financial measures used by other companies. We encourage our investors to review our unaudited condensed consolidated financial statements and other publicly filed reports in their entirety and not to rely on a single financial measure.

For the three months ended June 30, 2009, our realized gross margin increase of $45 million was principally a result of the following:

•

an increase of $171 million in realized value of hedges. In 2009, realized value of hedges was $152 million, which reflects the amount by which the settlement value of power contracts exceeded market prices, partially offset by the amount by which contract prices for fuel exceeded market prices for fuel. In 2008, realized value of hedges was $(19) million, which reflects the amount by which market prices exceeded the settlement value of power contracts, partially offset by the amount by which market prices for fuel exceeded the contract prices for fuel; and

•

an increase of $5 million in contracted and capacity primarily related to higher capacity prices in 2009; partially offset by

•

a decrease of $131 million in energy, primarily as a result of a decrease in power prices, an increase in the cost of emissions allowances, including $12 million to comply with the RGGI during the three months ended June 30, 2009, and decreases in natural gas prices which at times made it uneconomic for certain of our coal-fired units to generate. These decreases were partially offset by an 18% increase in generation volumes at our Mid-Atlantic baseload units primarily because of a decrease in planned outages in 2009 compared to 2008.

For the three months ended June 30, 2009, our unrealized gross margin increase of $860 million was principally a result of the following:

•

unrealized losses of $14 million in 2009, which included unrealized losses of $167 million from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods, partially offset by a $153 million net increase in the value of hedge and trading contracts for future periods primarily related to decreases in forward power and natural gas prices; and

•

unrealized losses of $874 million in 2008, which included a $932 million net decrease in the value of hedge contracts for future periods primarily related to increases in forward power and natural gas prices, partially offset by unrealized gains of $58 million from power and fuel contracts that settled during the period for which net unrealized losses had been recorded in prior periods.

Our operating expense decrease of $82 million was primarily a result of a decrease of $88 million in operations and maintenance expense, partially offset by a decrease of $10 million in gain on sales of emissions allowances sold to third parties. The MC Asset Recovery settlement with Southern Company resulted in a $62 million reduction in operations and maintenance expense for 2009. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the settlement between MC Asset Recovery and Southern Company. Excluding the settlement, operations and maintenance expense decreased $26 million, primarily as a result of the shutdown of the Lovett generating facility in April 2008 and a decrease in maintenance costs associated with planned outages at our Mid-Atlantic generating facilities during 2009 compared to 2008.

Other expense, net increased $2 million for the three months ended June 30, 2009, and reflects lower interest income as a result of lower interest rates on invested cash and lower average cash balances in 2009 compared to the same period in 2008, partially offset by lower interest expense as a result of lower outstanding debt and higher interest capitalized on projects under construction.

Gross Margin Overview

The following tables detail realized and unrealized gross margin for the three months ended June 30, 2009 and 2008, by operating segments (in millions):


	Three Months Ended June 30, 2009
	Mid- Atlantic			Northeast			California		Other Operations			Eliminations		Total
Energy	$	19		$	3		$	—	$	49		$	—	$	71
Contracted and capacity		86			22			29		—			—		137
Realized value of hedges		152			—			—		—			—		152

Total realized gross margin		257			25			29		49			—		360
Unrealized gross margin		—			20			—		(34	)		—		(14	)

Total gross margin	$	257		$	45		$	29	$	15		$	—	$	346


	Three Months Ended June 30, 2008
	Mid- Atlantic			Northeast			California		Other Operations			Eliminations		Total
Energy	$	161		$	20		$	1	$	20		$	—	$	202
Contracted and capacity		81			21			30		—			—		132
Realized value of hedges		(29	)		10			—		—			—		(19	)

Total realized gross margin		213			51			31		20			—		315
Unrealized gross margin		(818	)		(1	)		—		(55	)		—		(874	)

Total gross margin	$	(605	)	$	50		$	31	$	(35	)	$	—	$	(559	)

Energy represents gross margin from the generation of electricity, fuel sales and purchases at market prices, fuel handling, steam sales and our proprietary trading and fuel oil management activities.

Contracted and capacity represents gross margin received from capacity sold in ISO and RTO administered capacity markets, through RMR contracts, through tolling agreements and from ancillary services.

Realized value of hedges represents the actual margin upon the settlement of our power and fuel hedging contracts and the difference between market prices and contract costs for coal that we purchased under long-term agreements. Power hedging contracts include sales of both power and natural gas used to hedge power prices as well as hedges to capture the incremental value related to the geographic location of our physical assets.

Unrealized gross margin represents the net unrealized gain or loss on our derivative contracts, including the reversal of unrealized gains and losses recognized in prior periods and changes in value for future periods.

Operating Statistics

The following table summarizes Net Capacity Factor by region for the three months ended June 30, 2009 and 2008:


	Three Months Ended June 30,				Increase/ (Decrease)
	2009		2008		Increase/ (Decrease)
Mid-Atlantic	30	%	27	%	3	%
Northeast	7	%	11	%	(4	)%
California	4	%	3	%	1	%
Total	18	%	17	%	1	%

The following table summarizes power generation volumes by region for the three months ended June 30, 2009 and 2008 (in gigawatt hours):


	Three Months Ended June 30,		Increase/ (Decrease)		Increase/ (Decrease)
	2009	2008	Increase/ (Decrease)		Increase/ (Decrease)
Mid-Atlantic:
Baseload	3,441	2,904	537		18%
Intermediate	34	111	(77	)	(69)%
Peaking	5	42	(37	)	(88)%

Total Mid-Atlantic	3,480	3,057	423		14%

Northeast:
Baseload	333	207	126		61%
Intermediate	38	402	(364	)	(91)%
Peaking	—	1	(1	)	(100)%

Total Northeast	371	610	(239	)	(39)%

California:
Intermediate	213	158	55		35%
Peaking	1	10	(9	)	(90)%

Total California	214	168	46		27%

Total	4,065	3,835	230		6%

The total increase in power generation volumes for the three months ended June 30, 2009, as compared to the three months ended June 30, 2008, is primarily the result of the following:

Mid-Atlantic. An increase in our Mid-Atlantic baseload generation as a result of a decrease in planned outages in 2009 compared to 2008, partially offset by a decrease in our Mid-Atlantic intermediate and peaking generation.

Northeast. A decrease in our Northeast intermediate generation as a result of transmission upgrades in 2009, which reduced the demand for certain of our intermediate units, partially offset by an increase in our Northeast baseload generation as a result of an increase in market spark spreads.

units are subject to RMR arrangements. Therefore, changes in power generation volumes from those facilities, which can be caused by weather, planned outages or other factors, generally do not affect our gross margin.

Mid-Atlantic

Our Mid-Atlantic segment, which accounts for approximately 50% of our net generating capacity, includes four generating facilities with total net generating capacity of 5,230 MW.

The following table summarizes the results of operations of our Mid-Atlantic segment (in millions):


	Three Months Ended June 30,						Increase/ (Decrease)
	2009			2008			Increase/ (Decrease)
Gross Margin:
Energy	$	19		$	161		$	(142	)
Contracted and capacity		86			81			5
Realized value of hedges		152			(29	)		181

Total realized gross margin		257			213			44
Unrealized gross margin		—			(818	)		818

Total gross margin		257			(605	)		862

Operating Expenses:
Operations and maintenance		101			113			(12	)
Depreciation and amortization		24			23			1
Gain on sales of assets, net		(2	)		(2	)		—

Total operating expenses, net		123			134			(11	)

Operating income (loss)		134			(739	)		873
Total other expense, net		1			—			1

Income (loss) from continuing operations before income taxes	$	133		$	(739	)	$	872

Gross Margin

The increase of $44 million in realized gross margin was principally a result of the following:

•

an increase of $181 million in realized value of hedges. In 2009, realized value of hedges was $152 million, which reflects the amount by which the settlement value of power contracts exceeded market prices, partially offset by the amount by which contract prices for coal that we purchased under long-term agreements exceeded market prices for coal. In 2008, realized value of hedges was $(29) million, which was the result of market prices exceeding the settlement value of power contracts, partially offset by the amount by which market prices for coal exceeded the contract prices for coal that we purchased under long-term agreements; and

•

an increase of $5 million in contracted and capacity primarily related to higher capacity prices in 2009; partially offset by

•

a decrease of $142 million in energy, primarily as a result of a decrease in power prices and an increase in the cost of emissions allowances, including $11 million to comply with the RGGI during the three months ended June 30, 2009. These decreases were partially offset by an 18% increase in generation volumes at our Mid-Atlantic baseload units primarily because of a decrease in planned outages in 2009 compared to 2008 and a decrease in the price of coal.

The increase of $818 million in unrealized gross margin was comprised of the following:

•

unrealized gross margin in 2009 included a $123 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power and natural gas prices, offset by unrealized losses of $123 million from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods; and

•

unrealized losses of $818 million in 2008, which included an $868 million net decrease in the value of hedge contracts for future periods primarily related to increases in forward power and natural gas prices, partially offset by unrealized gains of $50 million from power and fuel contracts that settled during the period for which net unrealized losses had been recorded in prior periods.

Operating Expenses

The decrease of $11 million in operating expenses was primarily a result of a decrease in planned outages during 2009 compared to 2008.

Northeast

Our Northeast segment is comprised of our three generating facilities located in Massachusetts and one generating facility located in New York with total net generating capacity of 2,535 MW.

The following table summarizes the results of operations of our Northeast segment (in millions):


	Three Months Ended June 30,					Increase/ (Decrease)
	2009		2008			Increase/ (Decrease)
Gross Margin:
Energy	$	3	$	20		$	(17	)
Contracted and capacity		22		21			1
Realized value of hedges		—		10			(10	)

Total realized gross margin		25		51			(26	)
Unrealized gross margin		20		(1	)		21

Total gross margin		45		50			(5	)

Operating Expenses:
Operations and maintenance		35		56			(21	)
Depreciation and amortization		5		4			1
Gain on sales of assets, net		—		(12	)		12

Total operating expenses, net		40		48			(8	)

Operating income		5		2			3
Total other expense, net		—		1			(1	)

Income from continuing operations before income taxes	$	5	$	1		$	4

Gross Margin

The decrease of $26 million in realized gross margin was principally a result of the following:

•

a decrease of $17 million in energy, primarily as a result of a decrease in power prices and a 39% decrease in generation volumes because of transmission upgrades in 2009 and the shutdown of unit 5 of the Lovett generating facility in 2008, partially offset by lower fuel costs; and

•

a decrease of $10 million in realized value of hedges. In 2008, realized value of hedges was $10 million, which reflects the amount by which market prices for fuel exceeded the contract prices for fuel, offset by the amount by which market prices exceeded the settlement value of power contracts; partially offset by

•

an increase of $1 million in contracted and capacity primarily related to higher capacity prices in 2009.

The increase of $21 million in unrealized gross margin was comprised of the following:

•

unrealized gains of $20 million in 2009, which included a $29 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power and fuel prices; partially offset by unrealized losses of $9 million from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods; and

•

unrealized losses of $1 million in 2008, which included a $2 million net decrease in the value of hedge contracts for future periods, partially offset by unrealized gains of $1 million from power and fuel contracts that settled during the period for which net unrealized losses had been recorded in prior periods.

Operating Expenses

The decrease of $8 million in operating expenses included a decrease of $21 million in operations and maintenance expense primarily related to the shutdown of the Lovett generating facility in April 2008, partially offset by a decrease of $12 million in gain on sale of assets related to emissions allowances sold to third parties in 2008.

California

Our California segment consists of the Contra Costa, Pittsburg and Potrero facilities with total net generating capacity of 2,347 MW and includes business development efforts for new generation in California.

The following table summarizes the results of operations of our California segment (in millions):


	Three Months Ended June 30,					Increase/ (Decrease)
	2009		2008			Increase/ (Decrease)
Gross Margin:
Energy	$	—	$	1		$	(1	)
Contracted and capacity		29		30			(1	)

Total realized gross margin		29		31			(2	)
Unrealized gross margin		—		—			—

Total gross margin		29		31			(2	)

Operating Expenses:
Operations and maintenance		24		22			2
Depreciation and amortization		5		10			(5	)
Gain on sales of assets, net		—		(1	)		1

Total operating expenses, net		29		31			(2	)

Income from continuing operations before income taxes	$	—	$	—		$	—

Other Operations

Other Operations includes proprietary trading and fuel oil management activities, unallocated corporate overhead, interest expense on debt at Mirant Americas Generation and Mirant North America and interest income on our invested cash balances.

The following table summarizes the results of operations of our Other Operations segment (in millions):


	Three Months Ended June 30,						Increase/ (Decrease)
	2009			2008			Increase/ (Decrease)
Gross Margin:
Energy	$	49		$	20		$	29

Total realized gross margin		49			20			29
Unrealized gross margin		(34	)		(55	)		21

Total gross margin		15			(35	)		50

Operating Expenses:
Operations and maintenance		(45	)		12			(57	)
Depreciation and amortization		2			3			(1	)

Total operating expenses (income), net		(43	)		15			(58	)

Operating income (loss)		58			(50	)		108
Total other expense, net		33			31			2

Income (loss) from continuing operations before income taxes	$	25		$	(81	)	$	106

Gross Margin

The increase of $29 million in realized gross margin was a result of an $11 million increase in gross margin from proprietary trading activities and an $18 million increase in gross margin from our fuel oil management activities. The increase in gross margin from proprietary trading activities was a result of higher realized value associated with power positions in 2009 as compared to 2008. The increase in gross margin from fuel oil management activities was a result of an increase in the realized value associated with positions related to our fuel oil inventory.

The increase of $21 million in unrealized gross margin was comprised of the following:

•

unrealized losses of $34 million in 2009, which included unrealized losses of $35 million from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods, partially offset by a $1 million net increase in the value of contracts for future periods; and

•

unrealized losses of $55 million in 2008, which included a $62 million net decrease in the value of contracts for future periods, partially offset by unrealized gains of $7 million from power and fuel contracts that settled during the period for which net unrealized losses had been recorded in prior periods.

Operating Expenses

The decrease of $58 million in operating expenses was principally the result of the following:

•

a decrease of $62 million related to the MC Asset Recovery settlement with Southern Company in 2009, including a $52 million reduction in operations and maintenance expense

for the reimbursement of funds provided to MC Asset Recovery and costs incurred related to MC Asset Recovery not previously reimbursed and a $10 million reversal of accruals for future funding to MC Asset Recovery. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the settlement between MC Asset Recovery and Southern Company; and

•

a decrease of $4 million related to the bonus plan for dispositions that ended in June 2008; partially offset by

•

an increase related to a curtailment gain on pension and postretirement benefits of $5 million related to the shutdown of the Lovett generating facility in April 2008; and

•

an increase of $9 million related to severance and stock-based compensation costs primarily as a result of the departure of certain executives in 2009. See Note H to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the departure of these executives.

Other Expense, Net

The increase of $2 million in other expense, net was principally the result of the following:

•

a decrease of $19 million in interest income primarily related to lower interest rates on invested cash and lower average cash balances; partially offset by

•

a decrease of $14 million in interest expense primarily as a result of lower outstanding debt and higher interest capitalized on projects under construction; and

•

a decrease of $3 million in other expenses, net, primarily related to the loss on the 2008 purchase of Mirant Americas Generation senior notes due in 2011.

Other Significant Consolidated Statements of Operations Comparison

Provision for Income Taxes

Provision for income taxes decreased $10 million. The $10 million provision for income taxes for the three months ended June 30, 2008, was primarily related to alternative minimum tax.

Discontinued Operations

For the three months ended June 30, 2008, income from discontinued operations was $49 million and included insurance recoveries related to the Sual generating facility outages that occurred prior to the sale of the Philippine business.

Six Months Ended June 30, 2009 versus Six Months Ended June 30, 2008

Consolidated Financial Performance

We reported net income of $543 million for the six months ended June 30, 2009, compared to a net loss of $935 million for the same period in 2008. The change in net income (loss) is detailed as follows (in millions):


	Six Months Ended June 30,						Increase/ (Decrease)
	2009			2008			Increase/ (Decrease)
Realized gross margin	$	713		$	680		$	33
Unrealized gross margin		240			(1,177	)		1,417

Total gross margin		953			(497	)		1,450

Operating Expenses:
Operations and maintenance		277			369			(92	)
Depreciation and amortization		72			73			(1	)
Gain on sales of assets, net		(17	)		(16	)		(1	)

Total operating expenses, net		332			426			(94	)

Operating income (loss)		621			(923	)		1,544
Total other expense, net		70			53			17

Income (loss) from continuing operations before income taxes		551			(976	)		1,527
Provision for income taxes		8			10			(2	)

Income (loss) from continuing operations		543			(986	)		1,529
Income from discontinued operations		—			51			(51	)

Net income (loss)	$	543		$	(935	)	$	1,478

For the six months ended June 30, 2009, our realized gross margin increase of $33 million was principally a result of the following:

•

an increase of $243 million in realized value of hedges. In 2009, realized value of hedges was $260 million, which reflects the amount by which the settlement value of power contracts exceeded market prices, partially offset by the amount by which contract prices for fuel exceeded market prices for fuel. In 2008, realized value of hedges was $17 million, which reflects the amount by which market prices for fuel exceeded the contract prices for fuel, partially offset by the amount by which market prices exceeded the settlement value of power contracts; and

•

an increase of $9 million in contracted and capacity primarily related to higher capacity prices in 2009; partially offset by

•

a decrease of $219 million in energy, primarily as a result of a decrease in power prices and an increase in the cost of emissions allowances, including $27 million to comply with the RGGI in 2009. The decreases in energy gross margin were partially offset by a decrease in the price of fuel.

For the six months ended June 30, 2009, our unrealized gross margin increase of $1.417 billion was principally a result of the following:

•

unrealized gains of $240 million in 2009, which included a $494 million net increase in the value of hedge and trading contracts for future periods primarily related to decreases in

forward power and natural gas prices, partially offset by unrealized losses of $254 million from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods; and

•

unrealized losses of $1.177 billion in 2008, which included a $1.241 billion net decrease in the value of hedge contracts for future periods primarily related to increases in forward power and natural gas prices, partially offset by unrealized gains of $64 million from power and fuel contracts that settled during the period for which net unrealized losses had been recorded in prior periods.

Our operating expense decrease of $94 million was primarily a result of a decrease of $92 million in operations and maintenance expense. The MC Asset Recovery settlement with Southern Company resulted in a $62 million reduction in operations and maintenance expense for 2009. Excluding the settlement, operations and maintenance expense decreased $30 million, primarily as a result of the shutdown of the Lovett generating facility in April 2008 and a decrease in maintenance costs associated with planned outages at our Mid-Atlantic generating facilities during 2009 compared to 2008.

Other expense, net increased $17 million for the six months ended June 30, 2009, and reflects lower interest income as a result of lower interest rates on invested cash and lower average cash balances in 2009 compared to the same period in 2008, partially offset by lower interest expense as a result of lower outstanding debt and higher interest capitalized on projects under construction.

Gross Margin Overview

The following tables detail realized and unrealized gross margin for the six months ended June 30, 2009 and 2008, by operating segments (in millions):


	Six Months Ended June 30, 2009
	Mid- Atlantic			Northeast			California		Other Operations			Eliminations			Total
Energy	$	91		$	18		$	—	$	76		$	(3	)	$	182
Contracted and capacity		171			44			56		—			—			271
Realized value of hedges		259			1			—		—			—			260

Total realized gross margin		521			63			56		76			(3	)		713
Unrealized gross margin		243			46			—		(49	)		—			240

Total gross margin	$	764		$	109		$	56	$	27		$	(3	)	$	953


	Six Months Ended June 30, 2008
	Mid- Atlantic			Northeast			California		Other Operations			Eliminations			Total
Energy	$	326		$	42		$	2	$	31		$	—		$	401
Contracted and capacity		159			45			58		—			—			262
Realized value of hedges		(8	)		25			—		—			—			17

Total realized gross margin		477			112			60		31			—			680
Unrealized gross margin		(1,118	)		(10	)		—		(49	)		—			(1,177	)

Total gross margin	$	(641	)	$	102		$	60	$	(18	)	$	—		$	(497	)

Operating Statistics

The following table summarizes Net Capacity Factor by region for the six months ended June 30, 2009 and 2008:


	Six Months Ended June 30,				Increase/ (Decrease)
	2009		2008		Increase/ (Decrease)
Mid-Atlantic	32	%	32	%	—	%
Northeast	12	%	13	%	(1	)%
California	4	%	3	%	1	%
Total	20	%	20	%	—	%

The following table summarizes power generation volumes by region for the six months ended June 30, 2009 and 2008 (in gigawatt hours):


	Six Months Ended June 30,		Increase/ (Decrease)		Increase/ (Decrease)
	2009	2008	Increase/ (Decrease)		Increase/ (Decrease)
Mid-Atlantic:
Baseload	7,167	6,974	193		3	%
Intermediate	139	184	(45	)	(24	)%
Peaking	36	88	(52	)	(59	)%

Total Mid-Atlantic	7,342	7,246	96		1	%

Northeast:
Baseload	698	575	123		21	%
Intermediate	572	915	(343	)	(37	)%
Peaking	—	1	(1	)	(100	)%

Total Northeast	1,270	1,491	(221	)	(15)	%

California:
Intermediate	389	289	100		35	%
Peaking	1	20	(19	)	(95	)%

Total California	390	309	81		26	%

Total	9,002	9,046	(44	)	—	%

The total decrease in power generation volumes for the six months ended June 30, 2009, as compared to the six months ended June 30, 2008, is primarily the result of the following:

California. All of our California facilities operate under tolling agreements or are subject to RMR arrangements. Our natural gas-fired units in service at Contra Costa and Pittsburg operate under tolling agreements with PG&E for 100% of the capacity from these units and our Potrero units are subject to RMR arrangements. Therefore, changes in power generation volumes from those facilities, which can be caused by weather, planned outages or other factors, generally do not affect our gross margin.

Mid-Atlantic

Our Mid-Atlantic segment, which accounts for approximately 50% of our net generating capacity, includes four generating facilities with total net generating capacity of 5,230 MW.

The following table summarizes the results of operations of our Mid-Atlantic segment (in millions):


	Six Months Ended June 30,						Increase/ (Decrease)
	2009			2008			Increase/ (Decrease)
Gross Margin:
Energy	$	91		$	326		$	(235	)
Contracted and capacity		171			159			12
Realized value of hedges		259			(8	)		267

Total realized gross margin		521			477			44
Unrealized gross margin		243			(1,118	)		1,361

Total gross margin		764			(641	)		1,405

Operating Expenses:
Operations and maintenance		206			210			(4	)
Depreciation and amortization		48			44			4
Gain on sales of assets, net		(10	)		(2	)		(8	)

Total operating expenses, net		244			252			(8	)

Operating income (loss)		520			(893	)		1,413
Total other expense, net		2			—			2

Income (loss) from continuing operations before income taxes	$	518		$	(893	)	$	1,411

Gross Margin

The increase of $44 million in realized gross margin was principally a result of the following:

•

an increase of $267 million in realized value of hedges. In 2009, realized value of hedges was $259 million, which reflects the amount by which the settlement value of power contracts exceeded market prices, partially offset by the amount by which contract prices for coal that we purchased under long-term agreements exceeded market prices for coal. In 2008, realized value of hedges was $(8) million, which was the result of market prices exceeding the settlement value of power contracts, partially offset by the amount by which market prices for coal exceeded the contract prices for coal that we purchased under long-term agreements; and

•

an increase of $12 million in contracted and capacity primarily related to higher capacity prices in 2009; partially offset by

•

a decrease of $235 million in energy, primarily as a result of a decrease in power prices and an increase in the cost of emissions allowances, including $24 million to comply with the RGGI in 2009. These decreases were partially offset by a decrease in the price of coal.

The increase of $1.361 billion in unrealized gross margin was comprised of the following:

•

unrealized gains of $243 million in 2009, which included a $434 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power and natural gas prices, partially offset by unrealized losses of $191 million from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods; and

•

unrealized losses of $1.118 billion in 2008, which included a $1.184 billion net decrease in the value of hedge contracts for future periods primarily related to increases in forward power and natural gas prices, partially offset by unrealized gains of $66 million from power and fuel contracts that settled during the period for which net unrealized losses had been recorded in prior periods.

Operating Expenses

The decrease of $8 million in operating expenses was primarily a result of the following:

•

an increase of $8 million in gain on sale of assets related to emissions allowances sold to third parties in 2009; and

•

a decrease of $4 million in operations and maintenance expense primarily as a result of a decrease in planned outages during 2009 compared to 2008; partially offset by

•

an increase of $4 million in depreciation and amortization expense related to pollution control equipment to reduce emissions of NOx placed in service as part of our compliance with the Maryland Healthy Air Act.

Northeast

Our Northeast segment is comprised of our three generating facilities located in Massachusetts and one generating facility located in New York with total net generating capacity of 2,535 MW.

The following table summarizes the results of operations of our Northeast segment (in millions):


	Six Months Ended June 30,						Increase/ (Decrease)
	2009			2008			Increase/ (Decrease)
Gross Margin:
Energy	$	18		$	42		$	(24	)
Contracted and capacity		44			45			(1	)
Realized value of hedges		1			25			(24	)

Total realized gross margin		63			112			(49	)
Unrealized gross margin		46			(10	)		56

Total gross margin		109			102			7

Operating Expenses:
Operations and maintenance		67			97			(30	)
Depreciation and amortization		9			10			(1	)
Gain on sales of assets, net		(2	)		(16	)		14

Total operating expenses, net		74			91			(17	)

Income from continuing operations before income taxes	$	35		$	11		$	24

Gross Margin

The decrease of $49 million in realized gross margin was principally a result of the following:

•

a decrease of $24 million in realized value of hedges. In 2009, realized value of hedges was $1 million, which reflects the amount by which the settlement value of power contracts exceeded market prices, offset by the amount by which contract prices for fuel exceeded market prices for fuel. In 2008, realized value of hedges was $25 million, which reflects the amount by which market prices for fuel exceeded the contract prices for fuel and the amount by which the settlement value of power contracts exceeded market prices; and

•

a decrease of $24 million in energy, primarily as a result of a decrease in power prices, an increase in the cost of emissions allowances, including $3 million to comply with the RGGI in 2009, the shutdown of the Lovett generating facility in 2008 and a 15% decrease in generation volumes because of transmission upgrades, partially offset by lower fuel costs; and

•

a decrease of $1 million in contracted and capacity primarily related to the shutdown of the Lovett generating facility.

The increase of $56 million in unrealized gross margin was comprised of the following:

•

unrealized gains of $46 million in 2009, which included a $54 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power and fuel prices; partially offset by unrealized losses of $8 million from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods; and

•

unrealized losses of $10 million in 2008, which included a $9 million net decrease from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods and a $1 million net decrease in the value of hedge contracts for future periods.

Operating Expenses

The decrease of $17 million in operating expenses included a decrease of $30 million in operations and maintenance expense primarily related to the shutdown of the Lovett generating facility in April 2008, partially offset by a decrease of $14 million in gain on sale of assets related to emissions allowances sold to third parties in 2008.

California

The following table summarizes the results of operations of our California segment (in millions):


	Six Months Ended June 30,						Increase/ (Decrease)
	2009			2008			Increase/ (Decrease)
Gross Margin:
Energy	$	—		$	2		$	(2	)
Contracted and capacity		56			58			(2	)

Total realized gross margin		56			60			(4	)
Unrealized gross margin		—			—			—

Total gross margin		56			60			(4	)

Operating Expenses:
Operations and maintenance		43			40			3
Depreciation and amortization		10			14			(4	)
Gain on sales of assets, net		(1	)		(1	)		—

Total operating expenses, net		52			53			(1	)

Operating income		4			7			(3	)
Total other expense, net		1			—			1

Income from continuing operations before income taxes	$	3		$	7		$	(4	)

Other Operations

The following table summarizes the results of operations of our Other Operations segment (in millions):


	Six Months Ended June 30,						Increase/ (Decrease)
	2009			2008			Increase/ (Decrease)
Gross Margin:
Energy	$	76		$	31		$	45

Total realized gross margin		76			31			45
Unrealized gross margin		(49	)		(49	)		—

Total gross margin		27			(18	)		45

Operating Expenses:
Operations and maintenance		(39	)		22			(61	)
Depreciation and amortization		5			5			—

Total operating expenses, net		(34	)		27			(61	)

Operating income (loss)		61			(45	)		106
Total other expense, net		67			53			14

Loss from continuing operations before income taxes	$	(6	)	$	(98	)	$	92

Gross Margin

The increase of $45 million in realized gross margin was a result of a $34 million increase in gross margin from proprietary trading activities and an $11 million increase in gross margin from our fuel oil management activities. The increase in gross margin from proprietary trading activities was a result of higher realized value associated with power positions in 2009 as compared to 2008. The increase in gross margin from fuel oil management activities was a result of an increase in the realized value associated with positions related to our fuel oil inventory.

Unrealized gross margin was the same for each period and was comprised of the following:

•

unrealized losses of $49 million in 2009, which included unrealized losses of $54 million from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods, partially offset by a $5 million net increase in the value of contracts for future periods; and

•

unrealized losses of $49 million in 2008, which included a $57 million net decrease in the value of contracts for future periods, partially offset by unrealized gains of $8 million from power and fuel contracts that settled during the period for which net unrealized losses had been recorded in prior periods.

Operating Expenses

The decrease of $61 million in operating expenses was principally the result of the following:

•

a decrease of $62 million related to the MC Asset Recovery settlement with Southern Company in 2009, including a $52 million reduction in operations and maintenance expense for the reimbursement of funds provided to MC Asset Recovery and costs incurred related to MC Asset Recovery not previously reimbursed and a $10 million reversal of accruals for future funding to MC Asset Recovery. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the settlement between MC Asset Recovery and Southern Company; and

•

a decrease of $10 million related to the bonus plan for dispositions that ended in June 2008; partially offset by

•

an increase related to a curtailment gain on pension and postretirement benefits of $5 million related to the shutdown of the Lovett generating facility in April 2008; and

•

Other Expense, Net

The increase of $14 million in other expense, net was principally the result of the following:

•

a decrease of $48 million in interest income primarily related to lower interest rates on invested cash and lower average cash balances; partially offset by

•

a decrease of $30 million in interest expense primarily as a result of lower outstanding debt and higher interest capitalized on projects under construction; and

•

a loss of $6 million in 2008 related to the purchase in 2008 of $134 million of Mirant Americas Generation senior notes due in 2011.

Other Significant Consolidated Statements of Operations Comparison

Provision for Income Taxes

Provision for income taxes decreased $2 million. The $8 million provision for income taxes for the six months ended June 30, 2009, includes $5 million related to alternative minimum tax and $3 million for state income taxes. The $10 million provision for income taxes for the six months ended June 30, 2008, was primarily related to alternative minimum tax.

Discontinued Operations

For the six months ended June 30, 2008, income from discontinued operations was $51 million and included insurance recoveries related to the Sual generating facility outages that occurred prior to the sale of the Philippine business and final working capital adjustments related to the 2007 sale of the Caribbean business.

Financial Condition

Liquidity and Capital Resources

We expect that we have sufficient liquidity for our future operations, capital expenditures and debt obligations. The principal sources of our liquidity are expected to be: (1) existing cash on hand (including $1.4 billion at Mirant Corporation) and expected cash flows from the operations of our subsidiaries; (2) letters of credit issued or borrowings made under Mirant North America’s senior secured revolving credit facility; and (3) letters of credit issued under Mirant North America’s senior secured term loan.

Sources of Funds

The table below sets forth total cash, cash equivalents and availability under credit facilities of Mirant and its subsidiaries at June 30, 2009 and December 31, 2008 (in millions):


	At June 30, 2009			At December 31, 2008
Cash and Cash Equivalents:
Mirant Corporation	$	1,369		$	1,469
Mirant Americas Generation		—			—
Mirant North America		259			229
Mirant Mid-Atlantic		164			125
Other		73			8

Total cash and cash equivalents		1,865			1,831
Less: cash restricted and reserved for other purposes		(63	)		(2	)

Total available cash and cash equivalents		1,802			1,829
Available under credit facilities		616			583

Total cash, cash equivalents and credit facilities availability	$	2,418		$	2,412

We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At June 30, 2009 and December 31, 2008, except for amounts held in bank accounts to cover upcoming payables, all of our cash and cash equivalents were invested in AAA-rated United States Treasury money market funds.

At June 30, 2009, the cash restricted and reserved for other purposes included $52 million at MC Asset Recovery that was not available to Mirant Corporation. These funds were transferred to Mirant Corporation on July 15, 2009, and were no longer considered restricted after that date. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the settlement between MC Asset Recovery and Southern Company. Available under credit facilities at June 30, 2009 and December 31, 2008, reflects a $45 million reduction as a result of the expectation that Lehman Commercial Paper, Inc., which filed for bankruptcy protection in October 2008, will not honor its $45 million commitment under the Mirant North America senior secured revolving credit facility.

We and certain of our subsidiaries, including Mirant Americas Generation and Mirant North America, are holding companies. The chart below is a summary representation of our capital structure and is not a complete corporate organizational chart.

LOGO

Except for existing cash on hand and, in the case of Mirant North America, borrowings and letters of credit under its credit facilities, the Mirant Corporation, Mirant Americas Generation and Mirant North America holding companies are dependent for liquidity on the distributions and dividends of their subsidiaries. The ability of Mirant North America and its subsidiary Mirant Mid-Atlantic to make distributions and pay dividends is restricted under the terms of their debt agreements and leveraged lease documentation, respectively. At June 30, 2009, Mirant North America had distributed to its parent, Mirant Americas Generation, all available cash that was permitted to be distributed under the terms of its debt agreements, leaving $423 million at Mirant North America and its subsidiaries. Of this amount, $164 million was held by Mirant Mid-Atlantic, which, as of June 30, 2009, met the tests under the leveraged lease documentation permitting it to make distributions to Mirant North America. Although Mirant North America is in compliance with its financial covenants, as of June 30, 2009, it is restricted from making distributions by the free cash flow requirements under the restricted payment test of its senior credit facility. The primary factor lowering the free cash flow calculation for Mirant North America is the significant capital expenditure program of Mirant Mid-Atlantic to install emissions controls at its Chalk Point, Dickerson and Morgantown coal-fired units to comply with the Maryland Healthy Air Act. We do not expect the liquidity effect of the restriction on distributions

under the Mirant North America senior credit facility to be material given that the majority of our liquidity needs arise from the activities of Mirant North America and its subsidiaries, the restriction does not limit Mirant North America from making distributions to Mirant Americas Generation to fund interest payments on its senior notes and the majority of our total available cash and cash equivalents are held unrestricted at Mirant Corporation.

Uses of Funds

Our requirements for liquidity and capital resources, other than for the day-to-day operation of our generating facilities, are significantly influenced by the following activities: (1) capital expenditures; (2) debt service and payments under the Mirant Mid-Atlantic leveraged leases; (3) collateral required for our asset management and proprietary trading and fuel oil management activities; and (4) the development of new generating facilities.

Capital Expenditures. Our capital expenditures, excluding capitalized interest for the six months ended June 30, 2009, were $345 million. Our estimated capital expenditures, excluding capitalized interest, for the period July 1, 2009, through December 31, 2010, are $818 million. See Capital Expenditures and Capital Resources in this Item 2 for further discussion of our capital expenditures.

Cash Collateral and Letters of Credit. In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, we often are required to provide credit support to our counterparties or make deposits with brokers. In addition, we often are required to provide cash collateral or letters of credit to access the transmission grid, to participate in power pools, to fund debt service and rent reserves and for other operating activities. Credit support includes cash collateral, letters of credit and financial guarantees. In the event that we default, the counterparty can draw on a letter of credit or apply cash collateral held to satisfy the existing amounts outstanding under an open contract. As of June 30, 2009, we had approximately $77 million of posted cash collateral and $269 million of letters of credit outstanding primarily to support our asset management activities, trading activities, debt service and rent reserve requirements and other commercial arrangements. Included in the letter of credit amount outstanding is a cash-collateralized letter of credit in support of our response to a request for proposals for new power generation. Our liquidity requirements are highly dependent on the level of our hedging activities, forward prices for energy, emissions allowances and fuel, commodity market volatility and credit terms with third parties.

The following table summarizes cash collateral posted with counterparties and brokers, letters of credit issued and surety bonds as of June 30, 2009 and December 31, 2008 (in millions):


	At June 30, 2009		At December 31, 2008
Cash collateral posted—energy trading and marketing	$	35	$	67
Cash collateral posted—other operating activities		42		44
Letters of credit—energy trading and marketing		55		76
Letters of credit—debt service and rent reserves		101		101
Letters of credit—other operating activities		113		124
Surety bonds—energy trading and marketing		16		25

Total	$	362	$	437

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

There were no significant changes to our debt obligations, off-balance sheet arrangements and contractual obligations as of June 30, 2009, from those presented in our 2008 Annual Report on Form 10-K.

Cash Flows

Continuing Operations

Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash provided by operating activities from continuing operations increased $476 million for the six months ended June 30, 2009, compared to the same period in 2008, primarily as a result of the following:

•

Funds on deposit. An increase in cash provided of $298 million primarily related to a decrease in collateral posted with our counterparties primarily as a result of decreases in forward energy prices. For the six months ended June 30, 2009, funds on deposit also reflects a $150 million increase in funds on deposit on our unaudited condensed consolidated balance sheet as a result of the MC Asset Recovery settlement with Southern Company. The increase in funds on deposit is offset by a $150 million increase in accounts payable and accrued liabilities on our unaudited condensed consolidated balance sheet and has no net effect on cash flows from operating activities;

•

Net accounts receivable and payable. An increase in cash provided of $83 million primarily related to a decrease in power prices in 2009 compared to the same period in 2008. In addition, the implementation in June 2009 of weekly settlements with PJM (in lieu of monthly settlements) has reduced the amount of outstanding receivables for the PJM market;

•

Operating expense. A decrease in cash used related to lower operations and maintenance expense of $89 million, including $52 million of cash that we were reimbursed in 2009 as a result of the MC Asset Recovery settlement with Southern Company for funds that we provided to MC Asset Recovery and costs that we incurred related to MC Asset Recovery that had not been previously reimbursed. See Results of Operations for additional discussion of our performance in 2009 compared to the same period in 2008;

•

Realized gross margin. An increase in cash provided of $54 million in 2009, compared to the same period in 2008, excluding the non-cash charge for lower of cost or market fuel inventory adjustments of $21 million. See Results of Operations for additional discussion of our performance in 2009 compared to the same period in 2008;

•

Collateral posted by counterparties. An increase in cash provided of $28 million primarily as a result of decreases in forward energy prices; and

•

Other operating assets and liabilities. An increase in cash provided of $16 million related to changes in other operating assets and liabilities.

The decreases in cash used in and increases in cash provided by operating activities were partially offset by the following:

•

Inventories. An increase in cash used of $47 million as a result of higher inventory levels of coal and fuel oil, partially offset by lower market prices in 2009 as compared to 2008;

•

Prepaid rent. An increase in cash used of $23 million because the scheduled rent payments for our Mirant Mid-Atlantic leveraged leases were higher for 2009 than 2008; and

•

Interest expense, net. An increase in cash used of $22 million reflecting lower interest income as a result of lower interest rates on invested cash, as well as lower average cash balances, partially offset by lower interest expense from lower outstanding debt and higher capitalized interest.

Investing Activities. Net cash used in investing activities from continuing operations increased by $64 million for the six months ended June 30, 2009, compared to the same period in 2008. This difference was primarily related to an increase in cash used for capital expenditures of $67 million primarily related to our environmental capital expenditures for our Maryland generating facilities.

Financing Activities. Net cash used in financing activities from continuing operations decreased by $1.951 billion for the six months ended June 30, 2009, compared to the same period in 2008. This difference was primarily a result of the following:

•

Stock repurchases. A decrease in cash used of $1.736 billion as a result of our 2008 stock repurchases;

•

Repayments and repurchases of long-term debt. A decrease in cash used of $230 million for repayment and repurchases of debt, including $132 million for the 2008 purchase and retirement of Mirant Americas Generation senior notes due in 2011; offset by

•

Exercise of stock options and warrants. A decrease in cash provided of $15 million as a result of the exercise of stock options and warrants in 2008.

Discontinued Operations

Operating Activities. In 2009, net cash provided by operating activities from discontinued operations was from the sale of transmission credits from our previously owned Wrightsville facility. In 2008, net cash provided by operating activities from discontinued operations was primarily a result of $41 million of business interruption insurance recoveries related to the outages of the Sual generating facility and the sale of transmission credits from our previously owned Wrightsville facility of $5 million.

Investing Activities. In 2008, net cash provided by investing activities from discontinued operations of $25 million related to insurance recoveries for repairs to the Sual generating facility and the Swinging Bridge facility of Mirant NY-Gen.

Environmental and Regulatory Matters

PJM Reliability Pricing Model Forward Capacity Market. Our Mid-Atlantic facilities sell electricity into the markets operated by PJM. Load-serving entities within PJM are required to have adequate sources of generating capacity. Our facilities located in the Mid-Atlantic region that sell electricity into the PJM market participate in the reliability pricing model (the “RPM”) forward capacity market. On December 12, 2008, PJM filed with the FERC to revise elements of the RPM forward capacity market. PJM sought to implement these changes in time for the May 2009 annual auction for the provision of capacity from June 1, 2012, to May 31, 2013. We and others filed oppositions to the proposed changes with the FERC. On February 9, 2009, PJM, a coalition of PJM customers, and several state public service commissions filed a settlement agreement with the FERC that, if approved, would materially modify several provisions of the December 2008 filing to the detriment of suppliers in the RPM capacity auction. Under the FERC’s rules and regulations, any party to a contested proceeding may unilaterally file a settlement in that proceeding with the FERC. We and others filed comments opposing the settlement. On March 26, 2009, the FERC issued an order that accepted the majority of changes to elements of the RPM forward capacity market proposed in the December 2008 filing and rejected the majority of changes to elements of the RPM forward capacity market proposed in the February 2009 settlement filing. Other parties have sought rehearing of the FERC’s March 26, 2009, order.

Virginia CAIR Implementation. In April 2006, Virginia enacted legislation that, among other things, granted the Virginia State Air Pollution Control Board the discretion to prohibit electric generating facilities located in a non-attainment area from purchasing SO2 and NOx allowances to achieve compliance under the EPA’s CAIR. In the fourth quarter of 2007, the Virginia State Air Pollution Control Board approved regulations that it interprets as prohibiting the acquisition in any manner of SO2 and NOx allowances by facilities in non-attainment areas to satisfy the requirements of the CAIR as implemented by Virginia. Mirant Potomac River’s Potomac River facility is located in a non-attainment area for ozone. Thus, this Virginia regulation effectively caps the Potomac River facility’s SO2 and NOx emissions at amounts equal to the allowances allocated to the facility. Mirant Potomac River challenged the legality of the regulations regarding the trading of

NOx allowances in Virginia state court. In July 2008, the Circuit Court for the City of Richmond, Virginia issued a ruling dismissing that challenge, which ruling Mirant Potomac River appealed. On June 23, 2009, the Court of Appeals of Virginia issued an opinion reversing the circuit court, concluding that the Virginia State Air Pollution Control Board exceeded its statutory authority in the Virginia regulation by prohibiting facilities in non-attainment areas from using allowances acquired by any form of transfer to satisfy the requirements of the CAIR, rather than limiting the prohibition to purchased allowances. On August 4, 2009, the Virginia Court of Appeals denied a request for rehearing filed by the Virginia State Air Pollution Control Board. The Virginia State Air Pollution Control Board may petition the Virginia Supreme Court to review the decision by the Virginia Court of Appeals, and the ruling by the Virginia Court of Appeals has not yet become effective.

Regulation of Greenhouse Gases, including the RGGI. Concern over climate change has led to significant legislative and regulatory efforts at the state and federal level to limit greenhouse gas emissions. One such effort is the RGGI, a multi-state initiative in the Northeast outlining a cap-and-trade program to reduce CO2 emissions from electric generating units with capacity of 25 MW or greater. The RGGI program calls for signatory states, which include Maryland, Massachusetts and New York, to stabilize CO2 emissions to an established baseline from 2009 through 2014, followed by a 2.5% reduction each year from 2015 to 2018.

In 2009, we expect to produce approximately 14.6 million tons of CO2 at our Maryland, Massachusetts and New York generating facilities. The RGGI regulations require those facilities to obtain allowances to emit CO2 beginning in 2009. No allowances were granted to existing sources of such emissions. Instead, allowances have been made available for such facilities only by purchase through periodic auctions conducted quarterly or through subsequent purchase from a party that holds allowances sold through a quarterly auction process. The Maryland regulations implementing the RGGI, which were amended on May 8, 2009, also provide that if the allowance clearing price reaches or exceeds $7 per ton of CO2 in the auctions of allowances that occur during the first three years, Maryland will withhold the remainder of that year’s allowances from sale in any future auction during that calendar year and make those allowances available by direct sale to generators in Maryland. In this scenario, between 0 and 50% of Maryland’s allowances allocated for sale in that year may be made available for purchase by such generators. Any such allowances made available for each generator to purchase at $7 per ton will be in proportion to each generator’s annual average heat input during specified historical periods as compared to the total average input for all affected Maryland generators in existence at that time. In none of the auctions held to date has the price reached $7 per ton.

The fourth auction of allowances by the RGGI states was held on June 17, 2009. The clearing price for the approximately 30.9 million allowances sold in the auction allocated for use beginning in 2009 was $3.23 per ton. Allowances allocated for use beginning in 2012 were also made available, and the clearing price for the approximately 2.2 million of such allowances sold in the auction was $2.06 per ton. The allowances sold in this auction can be used for compliance in any of the RGGI states. Further auctions will occur quarterly through the end of the first compliance period in 2011, with the next auction scheduled for September 9, 2009.

Complying with the RGGI in Maryland, Massachusetts and New York could have a material adverse effect upon our operations and our operating costs, depending upon the availability and cost of emissions allowances and the extent to which such costs may be offset by higher market prices to recover increases in operating costs caused by the RGGI.

In California, emissions of greenhouse gases are governed by California’s Global Warming Solutions Act (“AB 32”), which requires that greenhouse gas emissions be reduced to 1990 levels by 2020. In December 2008, the California Air Resource Board (“CARB”) approved a Scoping Plan for implementing AB 32. The Scoping Plan requires that CARB adopt a cap-and-trade regulation

by January 2011 and that the cap and trade program begin in 2012. The CARB’s schedule for developing regulations to implement AB 32 is being coordinated with the schedule of the Western Climate Initiative (“WCI”) for development of a regional cap-and-trade program for greenhouse gas emissions. Through the WCI, California is working with six other western states and four Canadian provinces to coordinate and implement a regional cap-and-trade program. AB 32, and any plans, rules and programs approved to implement AB 32, could have a material adverse effect on how we operate our California facilities and the costs of operating the facilities.

In August 2008, Massachusetts adopted its Global Warming Solutions Act (the “Climate Protection Act”), which establishes a program to reduce greenhouse gas emissions significantly over the next 40 years. Under the Climate Protection Act, the Commonwealth of Massachusetts Department of Environmental Protection has established a reporting and verification system for statewide greenhouse gas emissions, including emissions from generating facilities producing all electricity consumed in Massachusetts, and determined the state’s greenhouse gas emissions level from 1990. The Massachusetts Executive Office of Energy and Environmental Affairs (“MAEEA”) is to establish statewide greenhouse gas emissions limits effective beginning in 2020 that will reduce such emissions from the 1990 levels by a range of 10% to 25% beginning in 2020, with the reduction increasing to 80% below 1990 levels by 2050. In setting these limits, the MAEEA is to consider the potential costs and benefits of various reduction measures, including emissions limits for electric generating facilities, and may consider the use of market-based compliance mechanisms. A violation of the emissions limits established under the Climate Protection Act may result in a civil penalty of up to $25,000 per day. Implementation of the Climate Protection Act could have a material adverse effect on how we operate our Massachusetts facilities and the costs of operating those facilities.

In April 2009, the Maryland General Assembly passed the Greenhouse Gas Emissions Reduction Act of 2009 (the “Maryland Act”), which will become effective in October 2009. The Maryland Act requires a reduction in greenhouse gas emissions in Maryland by 25% from 2006 levels by 2020. However, this provision of the Maryland Act is only in effect through 2016 unless a subsequent statutory enactment extends its effective period. The Maryland Act requires the MDE to develop a proposed implementation plan to achieve these reductions by the end of 2011 and to adopt a final plan by the end of 2012.

Various bills have been proposed in Congress to govern CO2 emissions from generating facilities. Also, in light of the United States Supreme Court ruling in Massachusetts v. EPA that greenhouse gases fit within the Clean Air Act’s definition of “air pollutant,” the EPA may also promulgate regulations regarding the emission of greenhouse gases. On April 17, 2009, the EPA issued a proposed determination under a portion of the Clean Air Act that regulates vehicles that greenhouse gases in the atmosphere endanger the public’s health and welfare through their contribution to climate change. The EPA has also proposed a rule that would require owners of facilities in many sectors of the economy, including power generation, to report annually to the EPA the quantity and source of greenhouse gas emissions released from those facilities in the preceding year. Neither of these proposals seek to restrict the emission of CO2, but Congress or the EPA will likely take action to regulate CO2 emissions within the next several years. The final form of such regulation will be influenced by political and economic factors and is uncertain at this time. Current proposals include a cap-and-trade system that would require us to purchase allowances for some or all of the CO2 emitted by our generating facilities. Although we expect that market prices for electricity would increase following such regulation and would allow us to recover most of the cost of these allowances, we cannot predict with any certainty the actual increases in costs such regulation could impose upon us or our ability to recover such cost increases through higher market rates for electricity, and such regulation could have a material adverse effect on our consolidated statements of operations, financial position or cash flows. We expect to produce approximately 16.3 million total tons of CO2 at our generating facilities in 2009.

Critical Accounting Estimates

The sections below contain updates to our summary of critical accounting estimates included under Item 7, Management’s Discussion and Analysis of Results of Operations and Financial Condition, in our 2008 Annual Report on Form 10-K.

Revenue Recognition and Accounting for Energy Trading and Marketing Activities

Nature of Estimates Required. We utilize two comprehensive accounting models, an accrual model and a fair value model, in reporting our results of operations and financial position. We determine the appropriate model for our operations based on applicable accounting standards.

The accrual model is used to account for our revenues from the sale of energy, capacity and ancillary services. We recognize revenue when it has been earned and collection is probable as a result of electricity delivered to customers pursuant to contractual commitments that specify volume, price and delivery requirements. Sales of energy are based on economic dispatch, or they may be ‘as-ordered’ by an ISO or RTO, based on member participation agreements, but without an underlying contractual commitment. ISO and RTO revenues and revenues for sales of energy based on economic dispatch are recorded on the basis of MWh delivered, at the relevant day-ahead or real-time prices.

The fair value model is used to measure fair value on a recurring basis for derivative energy contracts that hedge economically our electricity generating facilities or that are used in our proprietary trading and fuel oil management activities. We use a variety of derivative financial instruments, such as futures, forwards, swaps and option contracts, in the management of our business. Such derivative financial instruments have varying terms and durations, or tenors, which range from a few days to a number of years, depending on the instrument.

Pursuant to SFAS 133, derivative financial instruments are reflected in our consolidated financial statements at fair value, with changes in fair value recognized currently in income unless they qualify for a scope exception. Management considers fair value techniques and valuation adjustments related to credit and liquidity to be critical accounting estimates. These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors. The fair value of derivative financial instruments is included in derivative contract assets and liabilities in our condensed consolidated balance sheets. Transactions that are not accounted for using the fair value model under SFAS 133 are either not derivatives or qualify for a scope exception and are accounted for under accrual accounting. We recognize inception gains and losses, which are transacted at different prices between the bid price and the ask price, immediately in income.

Key Assumptions and Approach Used. Determining the fair value of our derivatives is based largely on observable quoted prices from exchanges and independent brokers in active markets. We think that these prices represent the best available information for valuation purposes. For most delivery locations and tenors where we have positions, we receive multiple independent broker price quotes. If no active market exists, we estimate the fair value of certain derivative financial instruments using price extrapolation, interpolation and other quantitative methods. We have not identified any distressed market conditions that would alter our valuation techniques at June 30, 2009. Fair value estimates involve uncertainties and matters of significant judgment. Our techniques for fair value estimation include assumptions for market prices, correlation and volatility. The degree of estimation increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points. Note C to our unaudited condensed consolidated financial statements contained elsewhere in this report explains the fair value hierarchy. Our assets and liabilities classified as Level 3 in the fair value hierarchy represent approximately 2% of our total assets and less than 1% of our total liabilities measured at fair value at June 30, 2009.

The fair value of derivative contract assets and liabilities in our condensed consolidated balance sheets is also affected by our assumptions as to time value, credit risk and non-performance risk. The nominal value of the contracts is discounted using a forward interest rate curve based on LIBOR. In addition, the fair value of our derivative contract assets is reduced to reflect the estimated default risk of counterparties on their contractual obligations to us. The default risk of our counterparties for a significant portion of our overall net position is measured based on published spreads on credit default swaps. The fair value of our derivative contract liabilities is reduced to reflect our estimated risk of default on our contractual obligations to counterparties and is measured based on published default rates of our debt. The credit risk reflected in the fair value of our derivative contract assets and the non-performance risk reflected in the fair value of our derivative contract liabilities are calculated with consideration of our master netting agreements with counterparties and our exposure is reduced by cash collateral posted to us against these obligations.

Effect if Different Assumptions Used. The amounts recorded as revenue or cost of fuel, electricity and other products change as estimates are revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control. Because we use derivative financial instruments and have not elected cash flow or fair value hedge accounting under SFAS 133, certain components of our financial statements, including gross margin, operating income and balance sheet ratios, are at times volatile and subject to fluctuations in value primarily as a result of changes in energy and fuel prices. Significant negative changes in fair value could require us to post additional collateral either in the form of cash or letters of credit. Because the fair value measurements of our material assets and liabilities are based on observable market information, there is not a significant range of values around the fair value estimate. For our derivative financial instruments that are measured at fair value using quantitative pricing models, a significant change in estimate could affect our results of operations and cash flows at the time contracts are ultimately settled. See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for further sensitivities in our assumptions used to calculate fair value. See Note C to our unaudited condensed consolidated financial statements contained elsewhere in this report for further information on derivative financial instruments related to energy trading and marketing activities.

Stock-Based Compensation

Nature of Estimates Required. We account for stock-based compensation through the recognition in the statement of operations of the grant-date fair value of stock options and other equity-based compensation issued to employees and directors. We consider the assumptions inherent in our valuation and calculation of compensation expense critical to our unaudited condensed consolidated financial statements because the underlying assumptions are subject to significant judgment and the resulting compensation expense may be material to our results of operations.

Key Assumptions and Approach Used. The Black-Scholes option-pricing model was used to measure the grant-date fair value of the stock options. The Black-Scholes model requires certain assumptions concerning implied volatility, dividend yield, expected term and grant price. These assumptions have a significant effect on the options’ fair value. The expected term and expected volatility often have the most effect on the fair value of the option.

We use our own implied volatility from our traded options in accordance with SAB 107. Additionally, we assume there will be no dividends paid over the expected term of the awards. As a result of our lack of exercise history, the simplified method for estimating expected term has been used in accordance with SAB 107 and SAB 110, to the extent applicable. We plan to continue applying the simplified method in estimating the expected term of future stock option grants until

we have sufficient exercise history. The grant price used in the Black-Scholes option pricing model is the NYSE closing price of our common stock on the day of grant. The risk-free rate for periods within the contractual term of the stock option is based on the United States Treasury yield curve in effect at the time of the grant.

We have determined that all of the awards granted in 2009 and 2008 qualify for equity accounting treatment. Equity accounting treatment requires awards to be measured at the grant-date fair value with compensation expense recognized over the award’s requisite service period, with no subsequent re-measurement.

Compensation expense has been adjusted based on estimated forfeitures. During three and six months ended June 30, 2009, we recognized approximately $12 million and $16 million, respectively, of compensation expense related to stock options, restricted shares and restricted stock units.

Effect if Different Assumptions Used. As a result of the uncertainty, complexity and judgment involved in the valuation of stock options, the assumptions related to accounting for share-based payments could result in material changes to our unaudited condensed consolidated financial statements if different assumptions were used. A 10% increase in the volatility assumption for our valuation of stock options would have resulted in an increase of approximately $1 million in recognized compensation expense for the three and six months ended June 30, 2009. A 1% decrease in the forfeiture rate would result in a change of less than $1 million in the recognized compensation expense for the three and six months ended June 30, 2009. Generally, as the expected term, expected volatility and risk-free rate increase, the option’s fair value increases as a result of greater upside potential of the stock. However, as the expected dividend yield increases, the option’s fair value may decrease as option holders typically do not receive dividends.

See Note H to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information on stock-based compensation.

Asset Impairments

Nature of Estimates Required. We evaluate our long-lived assets, including intangible assets, for impairment in accordance with applicable accounting guidance. The amount of an impairment charge is calculated as the excess of the asset’s carrying value over its fair value, which generally represents the discounted expected future cash flows attributable to the asset, or, in the case of an asset we expect to sell, as its fair value less costs to sell.

SFAS 144 requires management to recognize an impairment charge if the sum of the undiscounted expected future cash flows from a long-lived asset or definite-lived intangible asset is less than the carrying value of that asset. We evaluate our long-lived assets (property, plant and equipment) and definite-lived intangible assets for impairment whenever indicators of impairment exist or when we commit to sell the asset. These evaluations of long-lived assets and definite-lived intangible assets may result from significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operational analyses. If the carrying amount is not recoverable, an impairment charge is recorded.

The continued decline in natural gas prices has caused power prices to continue to decline over the past year, thereby affecting the energy gross margin earned by our generating facilities. Additionally, the current economic recession and various demand-response programs have resulted in a decrease in the forecasted generation volumes of our generating facilities. On an ongoing basis, we evaluate our long-lived assets for indications of impairment; however, given the

remaining useful lives for many of our generating facilities, the total undiscounted cash flows for these generating facilities are more significantly affected by the long-term view of supply and demand than by the short term fluctuations in energy prices and demand. As such, we typically do not consider short term decreases in either energy prices or demand to cause an impairment evaluation.

Key Assumptions and Approach Used. The impairment evaluation is a two-step process, the first of which involves comparing the undiscounted cash flows to the carrying value of the asset. If the carrying value exceeds the undiscounted cash flows, the fair value of the asset must be calculated on a discounted basis. The fair value of an asset is the price that would be received from a sale of the asset in an orderly transaction between market participants at the measurement date. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, when available. In the absence of quoted prices for identical or similar assets, fair value is estimated using various internal and external valuation methods. These methods include discounted cash flow analyses and reviewing available information on comparable transactions. The determination of fair value requires management to apply judgment in estimating future capacity and energy prices, environmental and maintenance expenditures and other cash flows. Our estimates of the fair value of the assets include significant assumptions about the timing of future cash flows, remaining useful lives and the selection of a discount rate that reflects the risk inherent in future cash flows.

Mirant Bowline—Based on our current five-year forecast, Mirant Bowline is projected to operate at a net loss for the current year and to continue to have operating losses for the next several years. Therefore, we determined that our 1,139 MW Bowline generating facility should be evaluated for impairment in the second quarter. Our estimates of the asset’s undiscounted future cash flows for purposes of our impairment analysis required significant judgments related to future property tax assessments of the asset. Our estimates also included assumptions related to the future capacity and energy revenues our Bowline generating facility is projected to earn. Additionally, we assumed we would monetize excess emissions allowances by selling them. The sum of the probability weighted undiscounted cash flows through the facility’s estimated remaining useful life of 2027 exceeded the carrying value as of June 30, 2009. As a result, we did not record an impairment charge for the three and six months ended June 30, 2009. See Note D to our unaudited condensed consolidated financial statements contained elsewhere in this report for further information related to our impairment analysis of the Bowline generating facility.

Mirant Canal—Our 1,126 MW Canal generating facility is located in the lower Southeastern Massachusetts (“SEMA”) load zone in the ISO-NE control area. ISO-NE previously has determined that, at times, it is necessary for the Canal generating facility to operate to meet local reliability criteria for SEMA when it is not economic for the Canal generating facility to operate based upon prevailing market prices. When the Canal facility operates to meet local reliability criteria, we are compensated at the price we bid into the ISO-NE, pursuant to ISO-NE market rules, rather than at the lower market price.

During the first half of 2009, NSTAR Electric completed two of three planned phases to upgrade the SEMA transmission system. These upgrades are expected to reduce the need for the Canal generating facility to operate to maintain local reliability. The final phase of these transmission upgrades is scheduled to be completed in September 2009. We are currently evaluating whether an impairment review of Canal is required in light of the effect of the transmission upgrades.

Mirant Potrero—Our 362 MW Potrero generating facility continues to be subject to an RMR arrangement through 2009, which is renewable annually, based on the CAISO’s local reliability requirements. There are several projects underway in the San Francisco area to increase reliability for the region that once completed are expected to reduce and possibly eliminate the

need for the Potrero generating facility to operate for reliability reasons. Among these projects is the TransBay Cable, which is an underwater cable in San Francisco Bay that is expected to decrease the need for generating resources in the City of San Francisco. While the TransBay Cable project has been long planned, it currently is expected to become operational by mid-2010. However, there is still uncertainty as to the timing of the completion of the TransBay cable, and until such time that the cable is operational, Potrero unit 3 will continue to be needed for reliability as determined by the CAISO. We will continue to monitor developments to assess whether an impairment review is required.

Effect if Different Assumptions Used. The estimates and assumptions used to determine whether an impairment exists are subject to a high degree of uncertainty. The estimated fair value of an asset would change if different estimates and assumptions were used in our applied valuation techniques, including estimated undiscounted cash flows, discount rates and remaining useful lives for assets held and used. If actual results are not consistent with the assumptions used in estimating future cash flows and asset fair values, we may be exposed to additional losses that could be material to our results of operations.

Litigation

See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for further information related to our legal proceedings.

We are currently involved in certain legal proceedings. We estimate the range of liability through discussions with applicable legal counsel and analysis of case law and legal precedents. We record our best estimate of a loss, or the low end of our range if no estimate is better than another estimate within a range of estimates, when the loss is considered probable. As additional information becomes available, we reassess the potential liability related to our pending litigation and revise our estimates. Revisions in our estimates of the potential liability could materially affect our results of operations and the ultimate resolution may be materially different from the estimates that we make.

Recently Adopted Accounting Standards

See Note B to our unaudited condensed consolidated financial statements contained elsewhere in this report for further information related to our recently adopted accounting standards.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk, primarily associated with commodity prices. We also consider risks associated with interest rates and credit when valuing our derivative financial instruments.

The estimated net fair value of our derivative contract assets and liabilities was a net asset of $898 million at June 30, 2009. The estimated net fair value of our derivative contract assets and liabilities was a net liability of $1.307 billion at June 30, 2008. The following tables provide a summary of the factors affecting the change in fair value of the derivative contract asset and liability accounts for the six months ended June 30, 2009 and 2008, respectively (in millions):


	Commodity Contracts
	Asset Management			Trading Activities			Total
Fair value of portfolio of assets and liabilities at January 1, 2009	$	549		$	106		$	655
Gains (losses) recognized in the period, net:
New contracts and other changes in fair value¹		217			(80	)		137
Roll off of previous values²		(197	)		(54	)		(251	)
Purchases, issuances and settlements³		283			74			357

Fair value of portfolio of assets and liabilities at June 30, 2009	$	852		$	46		$	898


	Commodity Contracts
	Asset Management			Trading Activities			Total
Fair value of portfolio of assets and liabilities at January 1, 2008⁴	$	(133	)	$	4		$	(129	)
Gains (losses) recognized in the period, net:
New contracts and other changes in fair value¹		(1,095	)		(39	)		(1,134	)
Roll off of previous values²		57			10			67
Purchases, issuances and settlements³		(92	)		(19	)		(111	)

Fair value of portfolio of assets and liabilities at June 30, 2008	$	(1,263	)	$	(44	)	$	(1,307	)

The fair value, as of the end of each quarterly reporting period, of contracts entered into during each quarterly reporting period and the gains or losses attributable to contracts that existed as of the beginning of each quarterly reporting period and were still held at the end of each quarterly reporting period.

²	The fair value, as of the beginning of each quarterly reporting period, of contracts that settled during each quarterly reporting period.

³	Denotes cash settlements during each quarterly reporting period of contracts that existed at the beginning of each quarterly reporting period.

⁴	Reflects our portfolio of derivative contract assets and liabilities at December 31, 2007, adjusted for a day one net gain of $1 million recognized upon adoption of SFAS 157 on January 1, 2008.

The tables above do not include long-term coal agreements that are not required to be recorded at fair value under SFAS 133. As such, these contracts are not included in derivative contract assets and liabilities in the accompanying condensed consolidated balance sheets. As of June 30, 2009, these coal agreements had an estimated net fair value of approximately $(186) million. See “Long-Term Coal Agreement Risk” for further discussion later in this section.

We did not elect the fair value option for any financial instruments under SFAS 159. However, we do transact using derivative financial instruments, which are required to be recorded at fair value under SFAS 133 in our unaudited condensed consolidated balance sheets.

Counterparty Credit Risk

The valuation of our derivative contract assets is affected by the default risk of the counterparties with which we transact. We recognized a reserve, which is reflected as a reduction of our derivative contract assets, related to counterparty credit risk of $25 million and $52 million at June 30, 2009 and December 31, 2008, respectively.

We have historically calculated the credit reserve for all of our derivative contract assets considering our current exposure, net of the effect of credit enhancements, and potential loss exposure from the financial commitments in our risk management portfolio, and applied historical default probabilities using current credit ratings of our counterparties. In accordance with SFAS 157, we calculate the credit reserve through consideration of observable market inputs, when available. Our non-collateralized power hedges entered into by Mirant Mid-Atlantic with our major trading partners, which represent 65% of our net notional position at June 30, 2009, are senior unsecured obligations of Mirant Mid-Atlantic and the counterparties, and do not require either party to post cash collateral for initial margin or for securing exposure as a result of changes in power or natural gas prices. We calculate a credit reserve using published spreads on credit default swaps for our counterparties applied to our current exposure and potential loss exposure from the financial commitments in our risk management portfolio. Potential loss exposure is calculated as our current exposure plus a calculated VaR over the remaining life of the contracts. We apply a similar approach to calculate the fair value of our coal contracts that are not included in derivative contract assets and liabilities in the condensed consolidated balance sheets and which also do not require either party to post cash collateral for initial margin or for securing exposure as a result of changes in coal prices. We do not, however, transact in credit default swaps or any other credit derivative. An increase of 10% in the spread of credit default swaps of our major trading partners for our non-collateralized power hedges entered into by Mirant Mid-Atlantic would result in an increase of $2 million in our credit reserve as of June 30, 2009. An increase of 10% in the spread of credit default swaps of our coal suppliers would result in an increase of less than $1 million in our credit reserve of our long-term coal agreements that are not included in derivative contract assets and liabilities in the accompanying unaudited condensed consolidated balance sheets as of June 30, 2009.

The default risk for the remainder of the portfolio is generally offset by cash collateral or other credit enhancements. For the remainder of our risk management portfolio, we use published historical default probabilities to calculate a credit reserve applied to our current exposure, net of the effect of credit enhancements, and potential loss exposure from the financial commitments. Potential loss exposure is calculated as our current exposure plus a calculated five-day VaR. An increase in counterparty credit risk could affect the ability of our counterparties to deliver on their obligations to us. As a result, we may require our counterparties to post additional collateral or provide other credit enhancements. A downgrade of one notch in the average credit rating of our counterparties in this portion of the portfolio would result in an increase of $1 million in our credit reserve as of June 30, 2009.

Once we have delivered a physical commodity or have financially settled the credit risk, we are subject to collection risk. Collection risk is similar to credit risk and collection risk is accounted for when we establish our provision for uncollectible accounts. We manage this risk using the same techniques and processes used in credit risk discussed above.

We also monitor counterparty credit concentration risk on both an individual basis and a group counterparty basis. See Note C to our unaudited condensed consolidated financial statements contained elsewhere in this report for further discussion of our counterparty credit concentration risk.

Mirant Credit Risk

In valuing our derivative contract liabilities, we apply a valuation adjustment for non-performance, which is based on the probability of our default. We determine this non-performance adjustment value by multiplying our liability exposure, including outstanding balances for realized transactions, unrealized transactions and the effect of credit enhancements, by the one-year probability of our default based on our current credit rating. The one-year probability of default rate considers the tenor of our portfolio and the correlation of default between counterparties within our industry. The non-performance adjustment related to our credit risk at June 30, 2009, was immaterial. A downgrade of one notch in our credit rating would have an immaterial effect on our unaudited condensed consolidated statement of operations as of June 30, 2009.

Broker Quotes

In determining the fair value of our derivative contract assets and liabilities, we use third-party market pricing where available. We consider active markets to be those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our transactions in Level 1 of the fair value hierarchy primarily consist of natural gas and crude oil futures traded on the NYMEX and swaps cleared against NYMEX prices. For these transactions, we use the unadjusted published settled prices on the valuation date. Our transactions in Level 2 of the fair value hierarchy typically include non-exchange-traded derivatives such as OTC forwards, swaps and options. We value these transactions using quotes from independent brokers or other widely accepted valuation methodologies. Transactions are classified in Level 2 if substantially all (greater than 90%) of the fair value can be corroborated using observable market inputs such as transactable broker quotes. In accordance with the exit price objective under SFAS 157, the fair value of our derivative contract assets and liabilities is determined using bid prices for our assets and ask prices for liabilities. The quotes that we obtain from brokers are non-binding in nature, but are from brokers that typically transact in the market being quoted and are based on their knowledge of market transactions on the valuation date. We typically obtain multiple broker quotes on the valuation date for each delivery location that extend for the tenor of our underlying contracts. The number of quotes that we can obtain depends on the relative liquidity of the delivery location on the valuation date. If multiple broker quotes are received for a contract, we use an average of the quoted bid or ask prices. If only one broker quote is received for a delivery location and it cannot be validated through other external sources, we will assign the quote to a lower level within the fair value hierarchy. In some instances, we may combine broker quotes for a liquid delivery hub with broker quotes for the price spread between the liquid delivery hub and the delivery location under the contract. We also may apply interpolation techniques to value monthly strips if broker quotes are only available on a seasonal or annual basis. We perform validation procedures on the broker quotes at least on a monthly basis. The validation procedures include reviewing the quotes for accuracy and comparing them to our internal price curves. In certain instances, we may discard a broker quote if it is a clear outlier and multiple other quotes are obtained. At June 30, 2009, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.

Inactive markets are considered those markets with few transactions, non-current pricing or prices that vary over time or among market makers. Our transactions in Level 3 of the fair value hierarchy may involve transactions whereby observable market data, such as broker quotes, are not available for substantially all of the tenor of the contract or we are only able to obtain indicative broker quotes that cannot be corroborated by observable market data. In such cases, we may apply valuation techniques such as extrapolation to determine fair value. Proprietary models

may also be used to determine the fair value of certain of our derivative contract assets and liabilities that may be structured or otherwise tailored. The degree of estimation increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points. Our techniques for fair value estimation include assumptions for market prices, correlation and volatility. At June 30, 2009, our assets and liabilities classified as Level 3 in the fair value hierarchy represented approximately 2% of our total assets and less than 1% of our total liabilities measured at fair value. See Note C to our unaudited condensed consolidated financial statements contained elsewhere in this report for further explanation of the fair value hierarchy.

Interest Rate Risk

Fair Value Measurement

We are also subject to interest rate risk when determining the fair value of our derivative contract assets and liabilities. The nominal value of our derivative contract assets and liabilities is also discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of our transactions. An increase of 100 basis points in the average LIBOR rate would result in a decrease of $3 million to our derivative contract assets and a decrease of $2 million to our derivative contract liabilities at June 30, 2009.

Debt

Our debt that is subject to variable interest rates consists of the Mirant North America senior secured term loan and senior secured revolving credit facility. If both were fully drawn, the amount subject to variable interest rates would be approximately $1.1 billion and a 1% per annum increase in the average market rate would result in an increase in our annual interest expense of approximately $11 million.

Long-Term Coal Agreement Risk

As noted above, the credit concentration table excludes amounts related to contracts classified as normal purchases/normal sales, including our long-term coal agreements. We have non-performance risk associated with these agreements. There is risk that our coal suppliers may not provide the contractual quantities on the dates specified within the agreements or the deliveries may be carried over to future periods. If our coal suppliers do not perform in accordance with the agreements, we may have to procure coal in the market to meet our needs, or power in the market to meet our obligations. In addition, a number of the coal suppliers do not currently have an investment grade credit rating and, accordingly, we may have limited recourse to collect damages in the event of default by a supplier. We seek to mitigate this risk through diversification of coal suppliers and through guarantees. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers. Non-performance or default risk by our coal suppliers could have a material adverse effect on our future results of operations, financial condition and cash flows.

For a further discussion of market risks, our risk management policy and our use of VaR to measure some of these risks, see Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2008 Annual Report on Form 10-K.

Item 4.

Controls and Procedures

Effectiveness of Disclosure Controls and Procedures

As required by Exchange Act Rule 13a-15(b), our management, including our Chief Executive Officer and our Chief Financial Officer, conducted an assessment of the effectiveness of the design and operation of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of June 30, 2009. Based upon this assessment, our management concluded that, as of June 30, 2009, the design and operation of these disclosure controls and procedures were effective.

Appearing as exhibits to this report are the certifications of the Chief Executive Officer and the Chief Financial Officer required in accordance with Section 302 of the Sarbanes-Oxley Act of 2002.

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting that have occurred during the six month period ended June 30, 2009, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II

Item 1.

Legal Proceedings

See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for discussion of the material legal proceedings to which we are a party.

Item 1A.

Risk Factors

Part I, Item 1A. Risk Factors of our 2008 Annual Report on Form 10-K and Part II, Item 1A. Risk Factors of our Form 10-Q for the period ended March 31, 2009, includes a discussion of our risk factors. There have been no material changes in our risk factors since those reported in our 2008 Annual Report on Form 10-K and Form 10-Q for the period ended March 31, 2009.

Item 2.

Share Repurchases

For the three months ended June 30, 2009, we repurchased 1,109 shares for $13,248 for the settlement of minimum statutory payroll withholding taxes associated with the vesting of restricted shares and restricted stock units. These restricted shares and restricted stock units relate to grants that were made to executives and certain employees and are not related to a publicly announced share repurchase plan. See Note H contained elsewhere in this report for additional information related to stock-based compensation.

The following table sets forth information regarding repurchases of our common stock during the three-month period ended June 30, 2009:


Period	Total number of shares repurchased	Average price paid per share		Total number of shares purchased as part of publicly announced plans	Approximate dollar value of shares that may yet be purchased under the plans
April 1, 2009—April 30, 2009	594	$	10.76	—	$	—
May 1, 2009—May 31, 2009	182	$	13.31	—	$	—
June 1, 2009—June 30, 2009	333	$	13.31	—	$	—

Total	1,109			—

Item 4.

Submission of Matters to a Vote of Security Holders

The Company’s Annual Meeting of Stockholders was held on Thursday, May 7, 2009, in Atlanta, Georgia. The following matters were submitted to a vote of the Company’s stockholders:

(1)

Election of the following persons as directors for a one-year term expiring in 2010:


	VOTES FOR	VOTES WITHHELD
Thomas W. Cason	101,399,097	8,543,080
A.D. (Pete) Correll	101,210,979	8,731,198
Terry G. Dallas	101,239,318	8,702,859
Thomas H. Johnson	101,277,111	8,665,066
John T. Miller	101,393,828	8,548,349
Edward R. Muller	100,526,197	9,415,980
Robert C. Murray	101,403,543	8,538,634
John M. Quain	101,262,270	8,679,907
William L. Thacker	101,392,758	8,549,419

(2)

Ratification of the appointment of KPMG LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2009:


VOTES FOR	VOTES AGAINST	ABSTENTIONS
108,983,117	856,880	102,180

(3)

A stockholder proposal regarding a report on global warming:


VOTES FOR	VOTES AGAINST	ABSTENTIONS	BROKER NON-VOTES
35,253,988	48,310,971	10,312,400	16,064,818

Item 6.

Exhibits

(a) Exhibits.


Exhibit No.		Exhibit Name
3.1		Amended and Restated Certificate of Incorporation of Registrant (Incorporated herein by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed January 3, 2006)
3.2		Amended and Restated Bylaws of Registrant (Incorporated herein by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed August 6, 2009)
4.1		The Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any instrument defining the rights of holders of long-term debt of the Company and all of its consolidated subsidiaries for which financial statements are required to be filed with the Securities and Exchange Commission
31.1*		Certification of the Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a))
31.2*		Certification of the Chief Financial Officer Pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a))
32.1*		Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))
32.2*		Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))
101*		The following unaudited financial statements from the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, filed on August 7, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Balance Sheets, (iii) the Condensed Consolidated Statements of Stockholder’s Equity, (iv) the Condensed Consolidated Statements of Comprehensive Income (Loss), (v) the Condensed Consolidated Statements of Cash Flows, and (vi) Notes to Condensed Consolidated Financial Statements, tagged as blocks of text.

*	Asterisk indicates exhibits filed herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	MIRANT CORPORATION

Date: August 6, 2009	By:	/S/ THOMAS E. LEGRO
		Thomas E. Legro
		Senior Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)