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 September 30, 2008

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 is a large accelerated filer, accelerated filer, non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-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 October 30, 2008, was 156,571,700.

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	8
	Condensed Consolidated Statements of Cash Flows	9
	Notes to Condensed Consolidated Financial Statements (unaudited)	10
Item 2.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	42
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	76
Item 4.	Controls and Procedures	80

	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	81
Item 1A.	Risk Factors	81
Item 2.	Share Repurchases	83
Item 6.	Exhibits	84

Glossary of Certain Defined Terms

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.

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.

EITF—The Emerging Issues Task Force formed by the Financial Accounting Standards Board.

EITF 02-3—EITF Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.

EOB—California Electricity Oversight Board.

EPA—United States Environmental Protection Agency.

EPS—Earnings per share.

FASB—Financial Accounting Standards Board.

FERC—Federal Energy Regulatory Commission.

FIN—FASB Interpretation.

FIN 39—FIN No. 39, Offsetting of Amounts Related to Certain Contracts.

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.

FIN 47—FIN No. 47, Accounting for Conditional Asset Retirements—an interpretation of FASB Statement No. 143.

FSP—FASB Staff Position.

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

FSP FAS 157-3—FSP FAS No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.

FSP FIN 39-1—FSP FIN No. 39-1, Amendment of FASB Interpretation No. 39 (FIN 39).

GAAP—Generally accepted accounting principles in the United States.

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.

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.

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.

Mirant Potomac River—Mirant Potomac River, LLC.

Mirant Power Purchase—Mirant Power Purchase, LLC.

MW—Megawatt.

MWh—Megawatt hour.

NAAQS—National ambient air quality standard.

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.

NOV—Notice of violation.

NOx—Nitrogen oxides.

NSR—New source review.

NYISO—Independent System Operator of New York.

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.

Orange and Rockland—Orange and Rockland Utilities, Inc.

OTC—Over-the-Counter.

Ozone Season—The period between May 1 and September 30 of each year.

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.

PM2.5—Particulate matter that is 2.5 microns or less in size.

PPA—Power purchase agreement.

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.

SEC—U.S. Securities and Exchange Commission.

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 an expiration date of January 3, 2011.

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

SFAS—Statement of Financial Accounting Standards.

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

iii

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

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

SFAS 143—SFAS No. 143, Accounting for Asset Retirement Obligations.

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

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

SFAS 158—SFAS No. 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans: an amendment of FASB Statements Nos. 87, 88, 106 and 132R.

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.

SO2—Sulfur dioxide.

VIE—Variable interest entity.

Virginia DEQ—Virginia Department of Environmental Quality.

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;

•

changes in market conditions, including developments in the supply, demand, volume and pricing of electricity and other commodities in the energy markets; changes in credit standards of market participants or the extent and timing of the entry of additional competition in our markets or those of our subsidiaries and affiliates;

•

increased 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 over-the-counter and exchange-based commodity markets or changes in commodity market liquidity or other commodity market conditions, which may affect our ability to engage in asset management and proprietary trading activities as expected, or result in material extraordinary gains or losses from open positions in fuel oil or other commodities;

•

deterioration in the financial condition of our counterparties and the resulting decrease in market liquidity and/or 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 as a result of such hazards;

•

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 and energy payments;

•

legal and political challenges to the rules used to calculate capacity payments in the markets in which we operate;

•

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

•

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

•

our ability to borrow additional funds and access capital markets;

•

strikes, union activity or labor unrest;

•

weather and other natural phenomena, including hurricanes and earthquakes;

•

the cost and availability of emissions allowances;

•

curtailment of operations because of transmission constraints;

•

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;

•

our inability to complete construction of 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;

•

the continued impact of deteriorating economic conditions and credit contraction on our business, including impacts on the ability of contractual counterparties and lenders under Mirant North America’s revolving credit facility to perform their obligations and impacts on liquidity in the power and fuel markets in which we hedge and transact;

•

war, terrorist activities or the occurrence of a catastrophic loss;

•

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; 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, financial condition or results of operations and cash flows) are set forth in our 2007 Annual Report on Form 10-K and in Part II, Item 1A. Risk Factors in this Form 10-Q.

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 September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in millions, except per share data)
Operating revenues (including unrealized gains (losses) of $1.438 billion, $16 million, $225 million and $(402) million, respectively)	$	2,172		$	717		$	2,081		$	1,610
Cost of fuel, electricity and other products (including unrealized (gains) losses of $43 million, $3 million, $7 million and $(19) million, respectively)		360			195			766			699

Gross Margin		1,812			522			1,315			911

Operating Expenses:
Operations and maintenance		150			171			519			519
Depreciation and amortization		35			33			108			97
Impairment losses		—			—			—			175
Gain on sales of assets, net		(11	)		—			(27	)		(24	)

Total operating expenses		174			204			600			767

Operating Income		1,638			318			715			144

Other Expense (Income), net:
Interest expense		46			60			146			190
Interest income		(14	)		(83	)		(67	)		(136	)
Other, net		4			(340	)		10			(343	)

Total other expense (income), net		36			(363	)		89			(289	)

Income From Continuing Operations Before Reorganization Items, Net and Income Taxes		1,602			681			626			433
Reorganization items, net		—			—			—			(2	)
Provision (benefit) for income taxes		(5	)		39			5			9

Income From Continuing Operations		1,607			642			621			426
Income From Discontinued Operations, net		—			133			51			1,553

Net Income	$	1,607		$	775		$	672		$	1,979

Basic EPS:
Basic EPS from continuing operations	$	9.18		$	2.51		$	3.15		$	1.66
Basic EPS from discontinued operations		—			0.52			0.26			6.07

Basic EPS	$	9.18		$	3.03		$	3.41		$	7.73

Diluted EPS:
Diluted EPS from continuing operations	$	8.69		$	2.27		$	2.86		$	1.50
Diluted EPS from discontinued operations		—			0.47			0.24			5.49

Diluted EPS	$	8.69		$	2.74		$	3.10		$	6.99

Weighted average shares outstanding		175			256			197			256
Effect of dilutive securities		10			27			20			27

Weighted average shares outstanding assuming dilution		185			283			217			283

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

MIRANT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	At September 30, 2008			At December 31, 2007
	(Unaudited)
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	2,264		$	4,961
Funds on deposit		247			304
Receivables, net		690			589
Price risk management assets		1,817			687
Inventories		272			357
Prepaid expenses		148			142

Total current assets		5,438			7,040

Property, Plant and Equipment, net		3,028			2,590

Noncurrent Assets:
Intangible assets, net		199			206
Price risk management assets		355			153
Deferred income taxes		471			240
Prepaid rent		239			234
Other		106			75

Total noncurrent assets		1,370			908

Total Assets	$	9,836		$	10,538

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current portion of long-term debt	$	59		$	142
Accounts payable and accrued liabilities		841			718
Price risk management liabilities		1,782			709
Deferred income taxes		471			240
Other		11			12

Total current liabilities		3,164			1,821

Noncurrent Liabilities:
Long-term debt		2,696			2,953
Price risk management liabilities		303			261
Asset retirement obligations		39			44
Pension and postretirement obligations		105			101
Other		62			48

Total noncurrent liabilities		3,205			3,407

Commitments and Contingencies
Stockholders’ Equity:
Preferred stock, par value $.01 per share, authorized 100,000,000 shares, no shares issued at September 30, 2008 and December 31, 2007		—			—
Common stock, par value $.01 per share, authorized 1.5 billion shares, issued 310,664,974 and 301,196,073 at September 30, 2008 and December 31, 2007, respectively, and outstanding 156,571,700 shares and 221,811,972 at September 30, 2008 and December 31, 2007, respectively		3			3
Treasury stock, at cost, 154,093,274 shares and 79,384,101 shares at September 30, 2008 and December 31, 2007, respectively		(5,130	)		(2,586	)
Additional paid-in capital		11,396			11,357
Accumulated deficit		(2,815	)		(3,486	)
Accumulated other comprehensive income		13			22

Total stockholders’ equity		3,467			5,310

Total Liabilities and Stockholders’ Equity	$	9,836		$	10,538

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 Income
	(in millions)
Balance, December 31, 2007	$	3	$	(2,586	)	$	11,357	$	(3,486	)	$	22
Net income		—		—			—		672			—
Share repurchases		—		(2,544	)		—		—			—
Stock-based compensation		—		—			20		—			—
Exercises of stock options and warrants		—		—			19		—			—
SFAS 157 adoption		—		—			—		1			—
SFAS 158 measurement date transition		—		—			—		(2	)		(1	)
Other comprehensive loss		—		—			—		—			(8	)

Balance, September 30, 2008	$	3	$	(5,130	)	$	11,396	$	(2,815	)	$	13

MIRANT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)


	Nine Months Ended September 30,
	2008			2007
	(in millions)
Net Income	$	672		$	1,979
Other comprehensive income, net of tax
Cumulative translation adjustment		—			4
Pension and other postretirement benefits		(8	)		(6	)

Other comprehensive loss, net of tax		(8	)		(2	)

Total Comprehensive Income	$	664		$	1,977

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)


	Nine Months Ended September 30,
	2008			2007
	(in millions)
Cash Flows from Operating Activities:
Net income	$	672		$	1,979
Income from discontinued operations		51			1,553

Income from continuing operations		621			426

Adjustments to reconcile net income from continuing operations and changes in working capital to net cash provided by operating activities:
Depreciation and amortization		111			104
Impairment losses		—			175
Gain on sales of assets		(27	)		(24	)
Price risk management activities, net		(218	)		383
Stock-based compensation		19			20
Other postretirement benefits curtailment gain		(5	)		(32	)
Settlement of the Back-to-Back Agreement with Pepco		—			(341	)
Funds on deposit		60			(92	)
Other, net		4			3
Changes in other working capital		22			48

Total adjustments		(34	)		244

Net cash provided by operating activities of continuing operations		587			670
Net cash provided by operating activities of discontinued operations		48			178

Net cash provided by operating activities		635			848

Cash Flows from Investing Activities:
Capital expenditures, excluding capitalized interest		(443	)		(385	)
Capitalized interest for projects under construction		(27	)		(15	)
Proceeds from the sales of assets and other investments		27			34
Restricted deposit payments and other		(31	)		5

Net cash used in investing activities of continuing operations		(474	)		(361	)
Net cash provided by investing activities of discontinued operations		25			5,263

Net cash provided by (used in) investing activities		(449	)		4,902

Cash Flows from Financing Activities:
Share repurchases		(2,561	)		(10	)
Repayments and purchases of long-term debt		(340	)		(139	)
Proceeds from exercises of stock options and warrants		19			7
Other		(1	)		—

Net cash used in financing activities of continuing operations		(2,883	)		(142	)
Net cash used in financing activities of discontinued operations		—			(669	)

Net cash used in financing activities		(2,883	)		(811	)

Net Increase (Decrease) in Cash and Cash Equivalents		(2,697	)		4,939
Cash and Cash Equivalents, beginning of period		4,961			1,139
Plus: Cash and Cash Equivalents in Assets Held for Sale, beginning of period		—			247
Less: Cash and Cash Equivalents in Assets Held for Sale, end of period		—			—

Cash and Cash Equivalents, end of period	$	2,264		$	6,325

Supplemental Cash Flow Disclosures:
Cash paid for interest, net of amounts capitalized	$	124		$	243
Cash paid for income taxes	$	2		$	31
Cash paid for claims and professional fees from bankruptcy	$	12		$	43

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 10,097 MW of net electric generating capacity. The Company’s net electric generating capacity is located 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.

Share Repurchases

On November 9, 2007, Mirant announced that it planned to return a total of $4.6 billion of excess cash to its stockholders based on four factors: (1) the outlook for the business, (2) preserving the Company’s credit profile, (3) maintaining adequate liquidity, including for capital expenditures and (4) maintaining sufficient working capital. Between November 2007 and September 2008, Mirant returned approximately $3.856 billion of cash to its stockholders through purchases of 110 million shares of its common stock, including 74 million shares that were purchased through open market purchases in 2008 for approximately $2.54 billion. Mirant has repurchased approximately 43% of the 256 million basic shares that it had outstanding when the program began in November 2007. On September 22, 2008, Mirant announced that it had suspended its program to return excess cash to its stockholders based on the Company’s evaluation of the four factors, that were set out upon commencement of the share repurchase program. On November 7, 2008, Mirant announced that it is resuming its program of returning excess cash to its stockholders and will purchase an additional $200 million of shares through open market purchases. This $200 million is in addition to the previous $3.856 billion of cash returned to stockholders. See Note I for further discussion of the share repurchases.

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 2007 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 VIEs 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 in their respective countries of operation. All significant intercompany accounts and transactions have been eliminated in consolidation. As of September 30, 2008, all of Mirant’s subsidiaries are wholly-owned. 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 K 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 and 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.

In preparing the Company’s consolidated statement of cash flows for the year ended December 31, 2007, the Company discovered that capitalized interest for projects under construction had been included in cash flows from operating activities, rather than cash flows from investing activities. The result of the misstatement was an understatement of cash provided by operating activities and an understatement of cash used in investing activities of approximately $15 million for the nine months ended September 30, 2007. The misstatement had no effect on cash, net income or stockholders’ equity. The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2007, has been adjusted to reflect the correction of this immaterial misstatement.

All amounts are presented in U.S. dollars unless otherwise noted. In accordance with SFAS 144, the results of operations of the Company’s businesses and facilities that have been disposed of and have met the criteria for such classification have been reclassified to discontinued operations. Certain prior period amounts have been reclassified to conform to the current period financial statement presentation.

Inventory

Inventory consists primarily of oil, coal, purchased emissions allowances and materials and supplies. 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 when they are used for repairs, maintenance or capital projects.

Purchased emissions allowances are recorded in inventory at the lower of cost or market value. Cost is computed on an average cost basis. Purchased emissions allowances for SO2 and NOx 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 against emissions volumes that exceed the allowances granted to the Company by the EPA.

Inventory at September 30, 2008 and December 31, 2007, consisted of (in millions):


	At September 30, 2008		At December 31, 2007
Fuel stock	$	209	$	280
Materials and supplies		62		67
Emissions allowances		1		10

Total inventory	$	272	$	357

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 nine months ended September 30, 2008 and 2007, the Company incurred the following interest costs (in millions):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Total interest costs	$	58		$	66		$	181		$	206
Capitalized and included in property, plant and equipment, net		(12	)		(6	)		(35	)		(16	)

Interest expense	$	46		$	60		$	146		$	190

The amounts of capitalized interest above include interest accrued. For the three and nine months ended September 30, 2008, cash paid for interest was $11 million and $151 million, respectively, of which $4 million and $27 million, respectively, was capitalized. For the three and nine months ended September 30, 2007, cash paid for interest was $67 million and $258 million, respectively, of which $7 million and $15 million, respectively, was capitalized.

Pension and Other Postretirement Benefits

Pension Plan Assets Values

Mirant uses a mix of equities and fixed income investments with the objective of maximizing the long-term return of pension plan assets at a prudent level of risk. The Company’s risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. Primarily as a result of declines in the overall market of equity securities during the first nine months of 2008, the fair value of Mirant’s pension plan assets has declined to $166 million at September 30, 2008, from $205 million at the Company’s most recent measurement date of September 30, 2007. The Company currently expects to contribute $50 million to $60 million to its pension plans in the fourth quarter of 2008.

Curtailments

During the fourth quarter of 2006, Mirant amended its postretirement benefit plan covering non-union employees to eliminate all employer-provided subsidies through a gradual phase-out by 2011. This action occurred after the Company’s September 30 annual measurement date for actuarial purposes used for measuring its December 31, 2006, obligation. The Company recognized a curtailment gain of approximately $32 million in the first quarter of 2007. This gain is included as a reduction of operations and maintenance expense on the unaudited condensed consolidated statement of operations for the nine months ended September 30, 2007.

During the second quarter of 2008, Mirant severed certain employees as a result of the shutdown of the Lovett facility. As a result, the Company recognized a curtailment gain on pension and postretirement benefits of approximately $5 million. This gain is included as a reduction of operations and maintenance expense on the unaudited condensed consolidated statement of operations for the nine months ended September 30, 2008.

Recently Adopted Accounting Standards

SFAS 157. On September 15, 2006, the FASB issued SFAS 157, which established a framework for measuring fair value under GAAP and expanded its disclosure about fair value measurement. SFAS 157 required companies to disclose the fair value of their financial instruments according to a fair value hierarchy (i.e., Levels 1, 2 and 3 as defined). Additionally, companies are required to provide enhanced disclosure regarding fair value measurements in the

Level 3 category, including a reconciliation of the beginning and ending balances separately for each major category of assets and liabilities accounted for at fair value. SFAS 157 was effective at the beginning of the first fiscal year after November 15, 2007. Mirant adopted the provisions of SFAS 157 on January 1, 2008, for financial instruments and nonfinancial assets and liabilities recognized or disclosed at fair value in the financial statements on a recurring basis.

SFAS 157 clarified that fair value should be measured at the exit price, which is the price to sell an asset or transfer a liability. The exit price may or may not equal the transaction price and the exit price objective applies regardless of a company’s intent or ability to sell the asset or transfer the liability at the measurement date. The Company has historically measured fair value using the approximate mid-point of the bid and ask prices. Upon adoption of SFAS 157, the Company began measuring fair value based on the bid or ask price from independent broker quotes for its price risk management assets and liabilities in accordance with the exit price objective.

SFAS 157 also clarified that non-performance risk, including an issuer’s credit standing, should be considered when measuring liabilities at fair value, precludes the use of a block discount when measuring instruments traded in an actively quoted market at fair value and requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred. SFAS 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.

SFAS 157 nullified a portion of the guidance in EITF 02-3. Under EITF 02-3, the transaction price presumption prohibited recognition of a day one gain or loss at the inception of a derivative contract unless the fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs. Day one gains or losses on transactions that had been deferred under EITF 02-3 were recognized in the period that valuation inputs became observable or when the contract performed.

The provisions of SFAS 157 are applied prospectively, except for the initial effect on three specific items: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price presumption under EITF 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price, and (3) blockage factor discounts. Adjustments to these items required under SFAS 157 are recorded as a transition adjustment to beginning retained earnings in the year of adoption. Upon adoption of SFAS 157, the Company recognized a gain of approximately $1 million as a cumulative-effect adjustment to accumulated deficit on January 1, 2008. The cumulative-effect adjustment relates entirely to the recognition of inception gains and losses formerly deferred under EITF 02-3. See Note C for further discussion of SFAS 157.

FSP FAS 157-3. On October 10, 2008, the FASB issued FSP FAS 157-3, which clarifies the application of SFAS 157 in determining the fair value of a financial asset when the market for that asset is not active. FSP FAS 157-3 provides clarity in determining the fair value of a financial asset in a dislocated market, including the use of internal assumptions when relevant observable market inputs do not exist. Additionally, it clarified that the use of broker quotes in a market that is not active may not be the best indication of fair value, and that the nature of the quote should also be considered in the fair value measurement. FSP FAS 157-3 is effective immediately, including with respect to prior periods for which financial statements have not been issued. The Company adopted FSP FAS 157-3 effective September 30, 2008. The adoption of FSP FAS 157-3 did not affect the Company’s statements of operations, financial position or cash flows.

SFAS 159. On February 15, 2007, the FASB issued SFAS 159, which permitted an entity to measure many financial instruments and certain other items at fair value by electing a fair value option. Once elected, the fair value option may be applied on an instrument by instrument basis,

is irrevocable and is applied only to entire instruments. SFAS 159 also requires companies with trading and available-for-sale securities to report the unrealized gains and losses for which the fair value option has been elected within earnings for the period presented. SFAS 159 was effective at the beginning of the first fiscal year after November 15, 2007. The Company adopted SFAS 159 on January 1, 2008. The adoption of SFAS 159 did not affect the Company’s statements of operations, financial position or cash flows because the Company did not elect the fair value option for any of its financial instruments.

FSP FIN 39-1. On April 30, 2007, the FASB issued FSP FIN 39-1, which amended FIN 39, to indicate that the following fair value amounts could be offset against each other if certain conditions of FIN 39 are otherwise met: (a) those recognized for derivative instruments executed with the same counterparty under a master netting arrangement and (b) those recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. In addition, a reporting entity is not precluded from offsetting the derivative instruments if it determines that the amount recognized upon payment or receipt of cash collateral is not a fair value amount. FSP FIN 39-1 was effective at the beginning of the first fiscal year after November 15, 2007. In March 2008, the FASB issued SFAS 161 which, upon adoption, requires the presentation of disclosures for derivative and hedging activities on a gross basis. In SFAS 161, the FASB expressed the view that disclosing the fair value amounts of derivative instruments on a gross basis provides better information about how companies are managing risks. As a result, the Company reevaluated its policy related to the net presentation of the price risk management assets and liabilities and related receivables and payables subject to master netting agreements. The Company elected to discontinue the net presentation of assets and liabilities subject to master netting agreements upon adoption of FSP FIN 39-1 on January 1, 2008. As required by FSP FIN 39-1, amounts at December 31, 2007, are also presented on a gross basis in the unaudited condensed consolidated balance sheet for consistent presentation. As a result, total assets and total liabilities as of December 31, 2007, both increased by $1.086 billion. The change to gross presentation had no effect on net income, earnings per share or stockholders’ equity.

The following table sets forth the amounts as previously reported and the currently reported amounts at December 31, 2007 (in millions):


	December 31, 2007 (as previously reported)		Adjustment for gross presentation		December 31, 2007 (as currently reported)
Receivables, net	$	297	$	292	$	589
Price risk management assets, current		173		514		687
Price risk management assets, noncurrent		30		123		153
Deferred income taxes, noncurrent		83		157		240

Accounts payable and accrued liabilities	$	426	$	292	$	718
Price risk management liabilities, current		196		513		709
Deferred income taxes, current		83		157		240
Price risk management liabilities, noncurrent		137		124		261

At September 30, 2008, the Company had approximately $50 million of cash collateral posted with counterparties under master netting agreements that was included in funds on deposit on the unaudited condensed consolidated balance sheet. In addition, approximately $3 million of cash collateral payable to counterparties under master netting agreements was included in accounts payable and accrued liabilities on the unaudited condensed consolidated balance sheet.

SAB 110. On December 21, 2007, the SEC issued SAB 110, which amended SAB 107 to allow for the continued use of the simplified method to estimate the expected term in valuing stock options beyond December 31, 2007. The simplified method can only be applied to certain types of stock options for which sufficient exercise history is not available. The Company adopted SAB 110 on January 1, 2008, and will continue to use the simplified method until it has sufficient exercise history.

SFAS 158. On September 29, 2006, the FASB issued SFAS 158, which includes the requirement to measure postretirement plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement. This requirement is effective for fiscal years ending after December 15, 2008. The Company used a September 30 measurement date in 2007 and prior years and will transition to a fiscal year-end measurement date at December 31, 2008. Mirant elected to use the alternative transition method under SFAS 158. This election resulted in an increase to accumulated deficit of approximately $2 million in 2008 that represents approximately one quarter of the annual net periodic benefit cost.

New Accounting Standards Not Yet Adopted

In December 2007, the FASB issued SFAS 141R, which requires an acquirer 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 will become effective for acquisitions completed on or after January 1, 2009; however, the income tax considerations included in SFAS 141R will become effective as of that date for all acquisitions, regardless of the acquisition date. The adoption of SFAS 141R will have no effect on the Company’s statements of operations, financial position or cash flows.

On February 12, 2008, the FASB issued FSP FAS 157-2, which defers the effective date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial liabilities, with the exception of those assets and liabilities that are recognized or disclosed on a recurring basis (at least annually). The Company will adopt FSP FAS 157-2 on January 1, 2009. The Company is currently evaluating the potential effect of adopting FSP FAS 157-2 on its disclosures for certain non-recurring nonfinancial assets and nonfinancial liabilities that are required to be measured at fair value in the Company’s financial statements.

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 contracts to manage exposure to commodity price risks and changes in conversion spreads and for proprietary trading activities. The standard will require the Company to enhance disclosures related to the objectives and strategy for using economic hedges and their effect on the Company’s statements of operations, financial position and cash flows. The Company will adopt SFAS 161 on January 1, 2009. The Company is currently evaluating the potential effect of adopting SFAS 161 on its disclosures in the Company’s financial statements.

C. Commodity Financial Instruments

The Company, through its asset management activities, enters into a variety of exchange-traded and OTC energy and energy-related derivative contracts, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage exposure to commodity price risks and changes in conversion spreads. 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 contracts in markets where the Company has a physical presence to attempt to generate incremental gross margin.

Adoption of SFAS 157

Effective January 1, 2008, the Company adopted SFAS 157 as discussed in Note B, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value. SFAS 157 clarifies that fair value should be measured at the exit price, which is the price to sell an asset or transfer a liability. In applying the exit price objective upon adoption of SFAS 157, the Company measures fair value based on the bid or ask price from independent broker quotes for its price risk management assets and liabilities.

Derivative instruments are recorded at their estimated fair value in the Company’s accompanying condensed consolidated balance sheets as price risk management assets and liabilities except for certain transactions that qualify for the normal purchase or normal sale exception election that allows for accrual accounting treatment. As defined in SFAS 157, fair value is the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company utilizes certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market-corroborated or generally unobservable. The Company utilizes valuation techniques that attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The determination of the fair values considers various factors, including closing exchange or OTC market price quotations, time value, credit quality, liquidity, and volatility factors underlying options and contracts. The fair value of certain derivative contracts is estimated using pricing models based on contracts with similar terms and risks. Modeling techniques assume market correlation and volatility, such as using the prices of one delivery point to calculate the price of the contract’s different delivery point. The nominal value of the transaction is discounted using a LIBOR forward interest rate curve. In addition, by applying a credit reserve which is calculated based on credit default swaps or published default probabilities for the actual and potential asset value, the fair value of Mirant’s derivative contracts reflects the risk that the counterparties to these contracts may default on the obligations. Likewise, by applying a reserve for non-performance which is calculated based on the probability of Mirant defaulting, Mirant adjusts its price risk management liabilities to reflect the price at which a potential market participant would be willing to assume Mirant’s liabilities.

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. Changes in the fair value and settlements of derivative contracts for proprietary trading activities are recorded on a net basis as operating revenue in the accompanying unaudited condensed consolidated statements of operations. As of September 30, 2008, the Company does not have any derivative instruments for which hedge accounting, as defined by SFAS 133, has been elected.

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 Mirant uses vary from readily observable prices for exchange-traded instruments to price curves

that cannot be validated through external pricing sources. Mirant’s financial assets and liabilities carried at fair value in the financial statements are classified in three categories based on the inputs used. The high-level guidelines described below are used to determine the appropriate classification of inputs within the fair value hierarchy.

Level 1 inputs—Unadjusted quoted prices available in active markets for identical assets or liabilities that the Company has the ability to access and transact upon as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of natural gas and crude oil futures traded on the NYMEX and swaps cleared against NYMEX prices.

Level 2 inputs—Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using quotes from independent brokers or other valuation methodologies. These include widely-accepted methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as OTC forwards, swaps and options.

Level 3 inputs—Pricing inputs that are generally less observable than those from objective sources. These inputs may be used with internally developed methodologies or methodologies utilizing significant inputs that represent management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored. Inputs such as assumptions for market prices, supply and demand market data, correlation and volatility are used for modeling with internally developed methodologies or methodologies utilizing significant inputs that represent management’s best estimate of fair value. At each balance sheet date, the Company performs an analysis of all instruments subject to SFAS 157 and includes in Level 3 all those whose fair value is based on significant unobservable inputs.

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 considers 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 September 30, 2008, by category and tenor, respectively. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of 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 requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. At September 30, 2008, the Company’s only financial assets and liabilities measured at fair value on a recurring basis are price risk management derivative financial instruments.

The following table presents financial assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2008, by category (in millions):


	Quoted Prices in Active Markets for Identical Instruments (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
Total assets	$	253		$	1,898		$	21		$	2,172
Total liabilities		(256	)		(1,827	)		(2	)		(2,085	)

Total	$	(3	)	$	71		$	19		$	87

The following table presents financial assets and liabilities, net accounted for at fair value on a recurring basis as of September 30, 2008, by tenor (in millions):


	Quoted Prices in Active Markets for Identical Instruments (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
2008	$	(12	)	$	11		$	5	$	4
2009		9			24			13		46
2010		—			(28	)		1		(27	)
2011		—			(8	)		—		(8	)
2012		—			(2	)		—		(2	)
Thereafter		—			74			—		74

Total	$	(3	)	$	71		$	19	$	87

The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at September 30, 2008 and December 31, 2007, was approximately 27 months and 12 months, respectively. The net notional amount, or net short position, of the price risk management assets and liabilities at September 30, 2008 and December 31, 2007, was approximately 41 million equivalent MWh and 26 million equivalent MWh, 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 earnings for the nine months ended September 30, 2008 (in millions):


Fair value of assets and liabilities categorized in Level 3 at January 1, 2008	$	12
Total gains or losses (realized/unrealized):
Included in earnings of existing contracts (or changes in net assets or liabilities)¹		(26	)
Purchases, issuances and settlements²		16
Transfers in and/or out of Level 3³		17

Fair value of assets and liabilities categorized in Level 3 at September 30, 2008	$	19

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 September 30, 2008								Nine Months Ended September 30, 2008
	Operating Revenues		Cost of Fuel			Total			Operating Revenues		Cost of Fuel			Total
Gains (losses) included in earnings	$	1	$	(9	)	$	(8	)	$	19	$	(12	)	$	7
Gains (losses) included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at September 30, 2008	$	2	$	(9	)	$	(7	)	$	21	$	(7	)	$	14

D. Debt

Long-term debt is as follows (in millions):


	At September 30, 2008			At December 31, 2007			Interest Rate	Secured/ Unsecured
Long-term debt:
Mirant Americas Generation:
Senior notes:
Due 2011	$	611		$	811		8.30%	Unsecured
Due 2021		450			450		8.50%	Unsecured
Due 2031		400			400		9.125%	Unsecured
Unamortized debt premium/discount		(3	)		(3	)
Mirant North America:
Senior secured term loan, due 2008 to 2013		416			555		LIBOR + 1.75%	Secured
Senior notes, due 2013		850			850		7.375%	Unsecured
Capital leases, through 2008 to 2015		31			32		7.375% - 8.19%

Total		2,755			3,095
Less: current portion of long-term debt		(59	)		(142	)

Total long-term debt, excluding current portion	$	2,696		$	2,953

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. In the nine months ended September 30, 2008, the Company purchased and retired $200 million of Mirant Americas Generation senior notes due in 2011.

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 and a senior secured revolving credit facility. The senior secured term loan had an initial principal balance of $700 million, which has amortized to $416 million as of September 30, 2008. 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 the nine months ended September 30, 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 September 30, 2008, there were approximately $132 million of letters of credit outstanding under the senior secured revolving credit facility. At September 30, 2008, a total of $623 million was available under the senior secured revolving credit facility and the senior secured term loan for cash draws or for the issuance of letters of credit.

In addition to quarterly principal installments of $1.32 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, 2008, Mirant North America made a mandatory principal prepayment of approximately $135 million on the term loan. Based on projections for 2008, the current estimate of the mandatory principal prepayment of the term loan in March 2009 is approximately $49 million. This amount has been reclassified from long-term debt to current portion of long-term debt at September 30, 2008. The majority of the difference between the March 2008 prepayment and the expected March 2009 prepayment results from the significant increase in expected capital expenditures in 2008 compared to 2007.

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.

E. Discontinued Operations

The Company has reclassified amounts for prior periods in the financial statements to report separately, as discontinued operations, the revenues and expenses of components of the Company that were sold in 2007.

The Company completed the following sales in 2007:

•

Six U.S. natural gas-fired facilities on May 1, 2007;

•

Mirant NY-Gen on May 7, 2007;

•

The Philippine business on June 22, 2007; and

•

The Caribbean business on August 8, 2007.

As part of the sale of the Philippine business, Mirant retained the rights to future insurance recoveries related to outages of the Sual generating facility that occurred prior to the sale. In 2007, the Company received a total of $23 million related to these recoveries. In the second quarter of 2008, the Company entered into a settlement pursuant to which it received approximately $50 million in additional insurance recoveries which is included in income from discontinued operations for the nine months ended September 30, 2008. Of this amount, $41 million related to business interruption recoveries and $9 million related to property insurance recoveries.

For the nine months ended September 30, 2008, income from discontinued operations also included final working capital adjustments related to the 2007 sale of the Caribbean business.

For the three and nine months ended September 30, 2007, income from discontinued operations included the results of operations and gain on sale of assets of the sales completed in 2007.

The following summarizes certain financial information of the discontinued operations (in millions):


	Three Months Ended September 30, 2007
	U.S.			Philippines			Caribbean			Total
Operating revenues	$	24		$	—		$	107		$	131
Operating expenses:
Loss (gain) on sales of assets		1			6			(62	)		(55	)
Other operating expenses		—			1			98			99

Total operating expenses		1			7			36			44

Operating income (loss)		23			(7	)		71			87
Provision (benefit) for income taxes		—			(49	)		3			(46	)
Other expense (income), net		(3	)		(1	)		4			—

Net income	$	26		$	43		$	64		$	133


	Nine Months Ended September 30, 2007
	U.S.			Philippines			Caribbean			Total
Operating revenues	$	82		$	200		$	514		$	796
Operating expenses:
Gain on sales of assets		(38	)		(2,004	)		(62	)		(2,104	)
Other operating expenses		65			67			432			564

Total operating expenses (income)		27			(1,937	)		370			(1,540	)

Operating income		55			2,137			144			2,336
Provision for income taxes		—			704			13			717
Other expense, net		1			33			32			66

Net income	$	54		$	1,400		$	99		$	1,553

F. Impairments on Assets Held and Used

In accordance with SFAS 144, an asset classified as held and used shall be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An asset impairment charge must be recognized if the sum of the undiscounted expected future cash flows from a long-lived asset is less than the carrying value of that asset. The amount of any impairment charge is calculated as the excess of the carrying value of the asset over its fair value. Fair value is estimated based on the discounted future cash flows from that asset or determined by other valuation techniques.

In 2000, the State of New York issued an NOV to the previous owner of the Company’s Lovett facility alleging NSR violations associated with the operation of that facility prior to its acquisition by the Company. On June 11, 2003, Mirant New York, Mirant Lovett and the State of New York entered into a consent decree (the “2003 Consent Decree”). The 2003 Consent Decree was approved by the Bankruptcy Court on October 15, 2003. Under the 2003 Consent Decree, Mirant Lovett had three options: (1) install emissions controls on the Lovett facility’s two coal-fired units (units 4 and 5); (2) shut down unit 4 and convert unit 5 to natural gas; or (3) shut down unit 5 in 2007 and unit 4 in 2008. The Company concluded that the installation of the required emissions controls was uneconomic. The Company also concluded that operating unit 5 on natural gas was uneconomic.

On October 19, 2006, Mirant Lovett notified the New York Public Service Commission, the NYISO, Orange and Rockland and certain other affected transmission and distribution companies

in New York of its intent to discontinue operation of units 3 and 5 of the Lovett facility in April 2007.

On May 10, 2007, Mirant Lovett entered into an amendment to the 2003 Consent Decree with the State of New York that switched the deadlines for shutting down units 4 and 5 so that the deadline for compliance by unit 5 was extended until April 30, 2008, and the deadline for unit 4 was shortened. The Company discontinued operation of unit 4 as of May 7, 2007. In addition, the Company discontinued operation of unit 3 because it was uneconomic to run the unit.

In the second quarter of 2007, the Company performed an impairment analysis of the Lovett facility and, as a result of this analysis, recorded an impairment loss of $175 million to reduce the carrying value of the Lovett facility to its estimated fair value. The carrying value of the Lovett facility prior to the impairment was approximately $185 million. The remaining depreciable life for the Lovett facility was also adjusted to April 30, 2008, based on the high likelihood of a shutdown of unit 5 on that date.

On October 20, 2007, Mirant Lovett submitted notices of its intent to discontinue operations of unit 5 of the Lovett generating facility as of midnight on April 19, 2008, to the New York Public Service Commission, the NYISO, Orange and Rockland and several other potentially affected transmission and distribution companies in New York. The Company ceased operation of unit 5 on April 19, 2008, and is dismantling the Lovett facility.

G. 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 expressed 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 September 30, 2008, that met the recognition requirements under FIN 45.

For the nine months ended September 30, 2008, Mirant had net increases to its guarantees of approximately $9 million. These increases were primarily attributable to increases in certain commercial purchase and sale agreements. For the nine months ended September 30, 2008, Mirant had net decreases to its letters of credit issued of approximately $26 million. In addition, during the third quarter of 2008, Mirant posted a $25 million surety bond as credit support for the RGGI auction that was held in September 2008.

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 2007 Annual Report on Form 10-K.

H. Stock-based Compensation

During the first quarter of 2008, 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 five-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 $37.02, the Company’s closing stock price on the day of the grant, and a grant date fair value of $9.50. The restricted stock units have a grant date fair value of $37.02, the Company’s closing stock price on the day of the grant.

During the second quarter of 2008, 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 have a grant date fair value of $38.88, the Company’s closing stock price on the day of the grant.

During the third quarter of 2008, the Company granted an immaterial number of stock options and issued restricted stock units to certain new employees under the Mirant Corporation 2005 Omnibus Incentive Compensation Plan.

During the three and nine months ended September 30, 2008, the Company recognized approximately $6 million and $19 million, respectively, of compensation expense related to stock options, restricted shares and restricted stock units compared to approximately $9 million and $23 million, respectively, for the same periods in 2007. These amounts are included in operations and maintenance expense in the unaudited condensed consolidated statements of operations. As of September 30, 2008, there was approximately $28 million of total unrecognized compensation cost, excluding estimated forfeitures, related to non-vested stock-based awards.

Stock-based compensation activity for the nine months ended September 30, 2008, is as follows:

Stock Options—Service-based


	Number of Options			Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions)
Outstanding at January 1, 2008		2,904,044		$	27.25
Granted		751,511		$	36.87
Exercised or converted		(659,804	)	$	25.63
Forfeited		(92,733	)	$	36.13

Outstanding at September 30, 2008		2,903,018		$	29.82	$	—

Exercisable or convertible at September 30, 2008		1,270,359		$	26.45	$	—

Cash proceeds from exercise of options for the nine months ended September 30, 2008	$	16,914,034

Stock Options—Performance-based


	Number of Options			Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions)
Outstanding at January 1, 2008		830,000		$	28.89
Exercised or converted		(44,507	)	$	28.89
Forfeited		(55,493	)	$	28.89

Exercisable or convertible at September 30, 2008		730,000		$	28.89	$	—

Cash proceeds from exercise of options for the nine months ended September 30, 2008	$	1,285,807

Restricted Stock Units and Restricted Stock Shares—Service-based


	Number of Units/ Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2008	629,973		$	32.54
Granted	403,300		$	36.90
Vested	(268,115	)	$	31.61
Forfeited	(66,597	)	$	37.00

Outstanding at September 30, 2008	698,561		$	34.99

Restricted Stock Units—Performance-based


	Number of Units		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2008	246,990		$	29.22
Vested	(246,990	)	$	29.22

Outstanding at September 30, 2008	—		$	—

I. Stockholders’ Equity and Earnings per Share

Stockholders’ Equity

On January 3, 2006, all shares of Mirant’s old common stock were cancelled and 300 million shares of Mirant’s new common stock were issued. At September 30, 2008, approximately one million shares of common stock are reserved for unresolved claims pursuant to Mirant’s emergence from bankruptcy.

•

On November 9, 2007, Mirant announced that the first stage of the cash distribution would be accomplished through an accelerated share repurchase program for $1 billion, plus open

market purchases for up to an additional $1 billion. In the fourth quarter of 2007, the Company repurchased 26.66 million shares of common stock for $1 billion through the accelerated share repurchase program.

•

On February 29, 2008, the Company announced that it had decided to return the remaining $2.6 billion of cash through open market purchases of common stock but that it would continue to evaluate the most efficient method to return the cash to stockholders.

•

On May 15, 2008, the accelerated share repurchase program was completed and Mirant received an additional 682,387 shares, resulting in a total of 27.34 million shares purchased. The final price of shares repurchased under the accelerated share repurchase program was $36.57 per share, which was determined based on a discount to the volume weighted average trading price of Mirant’s common stock over the period of the accelerated share repurchase program.

On September 22, 2008, Mirant announced that it had suspended its program to return excess cash to its stockholders based on the Company’s evaluation of the four factors that were set out upon commencement of the share repurchase program.

On November 7, 2008, Mirant announced that it is resuming its program of returning excess cash to its stockholders and will purchase an additional $200 million of shares through open market purchases. This $200 million is in addition to the previous $3.856 billion of cash returned to stockholders.

During the nine months ended September 30, 2008, there were approximately 8.2 million Series A Warrants and 10.1 million Series B Warrants that were exercised. Substantially all of these exercises were tendered by net share settlement, resulting in the issuance of approximately 8.2 million net shares of common stock. There were approximately 26.8 million Series A Warrants and 7.1 million Series B Warrants outstanding at September 30, 2008.

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 restricted shares, restricted stock units, stock options and warrants.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
Net income from continuing operations	$	1,607	$	642	$	621	$	426
Net income from discontinued operations		—		133		51		1,553

Net income as reported	$	1,607	$	775	$	672	$	1,979


Basic and diluted:
Weighted average shares outstanding—basic		175		256		197		256
Shares from assumed exercise of warrants and options		9		26		19		26
Shares from assumed vesting of restricted stock and restricted stock units		1		1		1		1

Weighted average shares outstanding—diluted		185		283		217		283


Basic EPS
EPS from continuing operations	$	9.18	$	2.51	$	3.15	$	1.66
EPS from discontinued operations		—		0.52		0.26		6.07

Basic EPS	$	9.18	$	3.03	$	3.41	$	7.73


Diluted EPS
EPS from continuing operations	$	8.69	$	2.27	$	2.86	$	1.50
EPS from discontinued operations		—		0.47		0.24		5.49

Diluted EPS	$	8.69	$	2.74	$	3.10	$	6.99

J. 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 5,244 MW. The Northeast segment consists of four generating facilities located in Massachusetts and New York with total net generating capacity of 2,506 MW. 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. Other Operations includes proprietary trading and fuel oil management activities. Other Operations also includes unallocated corporate overhead, interest on debt at Mirant Americas Generation and Mirant North America and interest income on the Company’s invested cash balances. For the three and nine months ended September 30, 2007, Other Operations also included gains and losses related to a long-term PPA with Pepco (the “Back-to-Back Agreement”), which was terminated pursuant to a settlement that became effective in the third quarter of 2007. 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 September 30, 2008:
Operating revenues¹	$	1,799		$	226		$	52		$	91		$	4		$	2,172
Cost of fuel, electricity and other products²		170			171			17			4			(2	)		360

Gross Margin		1,629			55			35			87			6			1,812

Operating Expenses:
Operations and maintenance		96			33			17			4			—			150
Depreciation and amortization		23			5			5			2			—			35
Loss (gain) on sales of assets, net		(7	)		(5	)		(2	)		(1	)		4			(11	)

Total operating expenses		112			33			20			5			4			174

Operating income		1,517			22			15			82			2			1,638
Total other expense (income), net		1			(1	)		—			36			—			36

Income from continuing operations before income taxes		1,516			23			15			46			2			1,602
Benefit for income taxes		—			—			—			(5	)		—			(5	)

Income from continuing operations	$	1,516		$	23		$	15		$	51		$	2		$	1,607


Total assets at September 30, 2008	$	4,902		$	671		$	185		$	6,483		$	(2,405	)	$	9,836

¹	Includes unrealized gains of $1.324 billion, $44 million and $70 million for Mid-Atlantic, Northeast and Other Operations, respectively.

²	Includes unrealized losses of $6 million and $37 million for Mid-Atlantic and Northeast, respectively.


	Mid- Atlantic			Northeast			California			Other Operations			Eliminations			Total
	(in millions)
Nine Months Ended September 30, 2008:
Operating revenues¹	$	1,410		$	480		$	138		$	49		$	4		$	2,081
Cost of fuel, electricity and other products²		422			323			43			(20	)		(2	)		766

Gross Margin		988			157			95			69			6			1,315

Operating Expenses:
Operations and maintenance		306			130			57			26			—			519
Depreciation and amortization		67			15			19			7			—			108
Loss (gain) on sales of assets, net		(9	)		(21	)		(3	)		(1	)		7			(27	)

Total operating expenses		364			124			73			32			7			600

Operating income (loss)		624			33			22			37			(1	)		715
Total other expense (income), net		1			(1	)		—			89			—			89

Income (loss) from continuing operations before income taxes		623			34			22			(52	)		(1	)		626
Provision for income taxes		—			—			—			5			—			5

Income (loss) from continuing operations	$	623		$	34		$	22		$	(57	)	$	(1	)	$	621


Total assets at September 30, 2008	$	4,902		$	671		$	185		$	6,483		$	(2,405	)	$	9,836

¹	Includes unrealized gains of $200 million, $4 million and $21 million for Mid-Atlantic, Northeast and Other Operations, respectively.

²	Includes unrealized losses of $7 million for Northeast.

Operating Segments


	Mid- Atlantic			Northeast		California		Other Operations			Eliminations			Total
	(in millions)
Three Months Ended September 30, 2007:
Operating revenues¹	$	542		$	189	$	45	$	(59	)	$	—		$	717
Cost of fuel, electricity and other products²		167			118		10		(95	)		(5	)		195

Gross Margin		375			71		35		36			5			522

Operating Expenses:
Operations and maintenance		91			46		18		16			—			171
Depreciation and amortization		21			6		3		3			—			33

Total operating expenses		112			52		21		19			—			204

Operating income		263			19		14		17			5			318
Total other income, net		(1	)		—		—		(362	)		—			(363	)

Income from continuing operations before income taxes		264			19		14		379			5			681
Provision for income taxes		—			—		—		39			—			39

Income from continuing operations	$	264		$	19	$	14	$	340		$	5		$	642


Total assets at December 31, 2007	$	4,008		$	696	$	195	$	7,327		$	(1,688	)	$	10,538

¹	Includes unrealized gains of $31 million for Mid-Atlantic and unrealized losses of $4 million and $11 million for Northeast and Other Operations, respectively.

²	Includes unrealized losses of $1 million and $2 million for Mid-Atlantic and Northeast, respectively.


	Mid- Atlantic			Northeast			California			Other Operations			Eliminations			Total
	(in millions)
Nine Months Ended September 30, 2007:
Operating revenues¹	$	889		$	513		$	130		$	78		$	—		$	1,610
Cost of fuel, electricity and other products²		404			331			32			(54	)		(14	)		699

Gross Margin		485			182			98			132			14			911

Operating Expenses:
Operations and maintenance		265			138			54			62			—			519
Depreciation and amortization		60			19			10			8			—			97
Impairment losses		—			175			—			—			—			175
Loss (gain) on sales of assets, net		(2	)		(25	)		(2	)		(5	)		10			(24	)

Total operating expenses		323			307			62			65			10			767

Operating income (loss)		162			(125	)		36			67			4			144
Total other income, net		(4	)		(6	)		(5	)		(274	)		—			(289	)

Income (loss) from continuing operations before reorganization items, net and income taxes		166			(119	)		41			341			4			433
Reorganization items, net		—			(2	)		—			—			—			(2	)
Provision for income taxes		—			—			—			9			—			9

Income (loss) from continuing operations	$	166		$	(117	)	$	41		$	332		$	4		$	426


Total assets at December 31, 2007	$	4,008		$	696		$	195		$	7,327		$	(1,688	)	$	10,538

¹	Includes unrealized losses of $313 million, $67 million and $22 million for Mid-Atlantic, Northeast and Other Operations, respectively.

²	Includes unrealized losses of $10 million for Mid-Atlantic and unrealized gains of $29 million for Northeast.

K. 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 consolidated financial position, results of operations 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 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 late 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 seeks injunctive relief and civil penalties of up to $10,000 per day for each violation. Mirant MD Ash Management and Mirant Mid-Atlantic dispute the claims of the MDE, and on July 23, 2008, filed a motion seeking dismissal of the MDE complaint.

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 enjoin Mirant Lovett from continuing to operate the Lovett generating facility in a manner that allegedly violates the Clean Water Act, 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 has complied with the terms of its water discharge permit, as amended by a Consent Order entered June 29, 2004. On April 20, 2005, the district court approved a stipulation agreed to by the plaintiff and Mirant Lovett that stayed the suit until 60 days after the entry of the order by the Bankruptcy Court confirming the plan of reorganization for Mirant Lovett became final and non-appealable, which stay expired in late 2007. Mirant Lovett intends to file 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 at the 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. Mirant Lovett disputes the allegations made by the NYSDEC staff in its complaint and thinks that it has complied with the June 2, 2006, Consent Order.

Notices of Intent to Sue for Alleged Violations of the Endangered Species Act. Mirant and Mirant Delta have received two letters, one dated September 27, 2007, sent on behalf of the Coalition for a Sustainable Delta, four water districts, and an individual and the second dated October 16, 2007, sent on behalf of San Francisco Baykeeper (collectively with the parties sending the September 27, 2007, letter, the “Noticing Parties”), providing notice that the Noticing Parties intend 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 U.S. Fish and Wildlife Service, the National Marine Fisheries Service and the Army Corps of Engineers 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 Pittsburg and Contra Costa 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. Mirant Delta disputes the allegations made by the Noticing Parties. No lawsuits have been filed to date, and San Francisco Baykeeper on February 1, 2008, withdrew its notice of intent to sue.

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 September 30, 2008, approximately one million 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.

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. Mirant may not reduce such payments for the taxes owed on any net recoveries up to $175 million. If the aggregate recoveries exceed $175 million net of costs, then Mirant may reduce the payments to be made to such unsecured creditors and former holders of equity interests under the Plan by the amount of any taxes it will owe on the amount in excess of $175 million. Most of the actions transferred to MC Asset Recovery remain pending, and through September 30, 2008, those actions had not resulted in recoveries in excess of the fees and costs incurred by MC Asset Recovery.

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 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 creditors and former equity holders as described above.

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.

FERC Show Cause Proceeding Relating to Trading Practices. On June 25, 2003, the FERC issued a show cause order (the “Trading Practices Order”) to more than 50 parties, including Mirant Americas Energy Marketing and subsidiaries of Mirant Americas Generation. The Trading Practices Order identified certain specific trading practices that the FERC indicated could constitute gaming or anomalous market behavior in violation of the CAISO and Cal PX tariffs, and required sellers previously involved in transactions of those types to demonstrate why such transactions were not violations of the CAISO and Cal PX tariffs. On September 30, 2003, and December 19, 2003, the Mirant entities filed with the FERC for approval of a settlement agreement (the “Trading Settlement Agreement”) entered into between certain Mirant entities and the FERC Trial Staff and an amendment to that agreement, under which Mirant Americas Energy Marketing would pay $332,411 and the FERC would have an allowed unsecured claim in Mirant Americas Energy Marketing’s bankruptcy proceeding for $3.67 million to settle the show cause proceeding. The FERC approved the Trading Settlement Agreement, as amended, on June 27, 2005, and the Bankruptcy Court approved it on August 24, 2005. Certain parties filed motions for rehearing with the FERC, which it denied on October 11, 2006. A party to the proceeding has appealed the FERC’s June 27, 2005, order to the Ninth Circuit.

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. On June 25, 2003, the FERC dismissed this proceeding. Southern California Water appealed that dismissal to the United States Court of Appeals for the Ninth Circuit, which on December 19, 2006, reversed the dismissal of the complaint and a number of other similar complaints and remanded the proceedings to the FERC. On June 26, 2008, the United States Supreme Court affirmed the remand of the Southern California Water proceeding and the other similar proceedings to the FERC, concluding that the FERC should analyze further (1) whether the contracts at issue imposed an excessive burden on consumers in the later periods covered by the contracts, not just at their outset, and (2) whether any of the sellers engaged in unlawful market manipulation, which the Court concluded would remove the premise underlying the FERC’s dismissal of the complaints that the rates agreed to in the contracts were based on fair, arm’s length negotiations. 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.

Maryland Public Service Commission Complaint to the FERC re PJM Offer Capping Rules

In certain market conditions, such as where congestion requires the dispatch of a generating facility that bid a higher price for electricity than other available generating facilities, PJM’s market rules (the “Offer Capping Rules”) limit the amount that the owner of a generating facility may bid to sell electricity from that facility to its incremental cost to produce that electricity. As approved by the FERC, the Offer Capping Rules contain exemptions for generating facilities entering service during certain years (none of which are owned by the Company) and for generating facilities (some of which are owned by the Company) that can relieve congestion arising at certain defined transmission interfaces. On January 15, 2008, the Maryland Public Service Commission (the “MD PSC”) filed a complaint with the FERC requesting that the FERC remove all exemptions to the Offer Capping Rules during hours when the PJM market reflects potentially non-competitive conditions, as determined by the PJM Market Monitor. The complaint

alleges that these exemptions to the Offer Capping Rules likely result in higher market clearing prices for electricity in PJM, and higher revenues to the Company and other owners of generation that are selling electricity, during the periods when the exemptions prevent the application of the Offer Capping Rules to one or more generating facilities. The MD PSC requested that the FERC require a recalculation of prices in the PJM energy markets without application of the exemptions to the Offer Capping Rules for each day from January 15, 2008, through the date that the Commission grants the requested relief and that it require owners of generation to refund any revenues received in excess of the amounts that would have been received had the exemptions not been applied.

In addition, the MD PSC alleged that PJM violated its tariff by not publicly disclosing since mid 2006 quarterly analyses performed by the PJM Market Monitor of the potential for the exercise of market power by owners of generation during periods when market conditions caused the exemptions to the Offer Capping Rules to apply. The MD PSC requested the FERC to initiate an investigation of whether owners of generation exercised market power during such periods, and, if so, to order refunds beginning as of September 8, 2006, or the first date that the FERC determines that PJM violated its tariff.

On May 16, 2008, the FERC issued an order eliminating the exemptions to the Offer Capping Rules challenged by the MD PSC in its complaint, denying the MD PSC’s request for refunds, and establishing a proceeding to examine what test should be applied to determine whether a generator should be exempted from the Offer Capping Rules because of lack of market power in circumstances where transmission constraints require the dispatch of a higher priced generating facility in lieu of available lower priced generation. A coalition of electricity generators, of which the Company is a member, has filed a request for rehearing.

Complaint Challenging Capacity Rates Under PJM’s RPM 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 (“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 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 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 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 expects to receive for the periods 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 PJM’s RPM tariff and that the prices determined during the auctions were in accordance with the tariff’s provisions. The RPM Buyers have filed a request for reconsideration.

Stockholder-Bondholder Litigation

Mirant Securities Consolidated Action. Twenty lawsuits filed in 2002 against Mirant and four of its officers have been consolidated into a single action, In re Mirant Corporation Securities Litigation, before the United States District Court for the Northern District of Georgia. In their original complaints, the plaintiffs alleged, among other things, that the defendants violated federal securities laws by making material misrepresentations and omissions to the investing public regarding Mirant’s business operations and future prospects during the period from January 19, 2001, through May 6, 2002, because of potential liabilities arising out of its activities in California during 2000 and 2001. The plaintiffs sought unspecified damages, including compensatory damages, and the recovery of reasonable attorneys’ fees and costs.

In November 2002, the plaintiffs filed an amended complaint that added as defendants the Southern Company (“Southern”), the directors of Mirant immediately prior to its initial public offering of stock and various firms that were underwriters for the initial public offering by the Company. In addition to the claims set out in the original complaint, the amended complaint asserted claims under the Securities Act, alleging that the registration statement and prospectus for the initial public offering in 2000 of Mirant’s old common stock cancelled under the Plan misrepresented and omitted material facts. On December 11, 2003, the plaintiffs filed a proof of claim against Mirant in the Chapter 11 proceedings, but they subsequently withdrew their claim in October 2004. On August 29, 2005, the district court, at the request of the plaintiffs, dismissed Mirant as a defendant in this action. On August 5, 2008, the district court addressed various pending motions to dismiss filed by the remaining defendants by requiring the plaintiffs to submit an amended complaint within thirty days, after which the defendants could refile their motions to dismiss. The plaintiffs filed a second amended complaint on September 5, 2008, and the defendants have filed motions seeking dismissal of that amended complaint.

A master separation agreement between Mirant and Southern entered into in conjunction with Mirant’s spin-off from Southern in 2001 obligates Mirant to indemnify Southern for any losses arising out of any acts or omissions by Mirant and its subsidiaries in the conduct of the business of Mirant and its subsidiaries. Mirant filed to reject the separation agreement in the Chapter 11 proceedings. Any damages determined to be owed to Southern arising from the rejection of the separation agreement will be addressed as a claim in the Chapter 11 proceedings under the terms of the Plan. The underwriting agreements between Mirant and the various firms added as defendants that were underwriters for the initial public offering by the Company in 2000 also provide for Mirant to indemnify such firms against any losses arising out of any acts or omissions by Mirant and its subsidiaries. The underwriters filed a claim against Mirant in the Chapter 11 proceedings that was subordinated to claims of Mirant’s creditors and extinguished under the Plan.

City of Sandy Springs Business and Occupation Taxes Dispute

Mirant’s corporate headquarters and its asset management and energy marketing organization are located in the City of Sandy Springs, Georgia (“Sandy Springs”), which came into existence in late 2005 and includes what had been an unincorporated portion of Fulton County, Georgia. By letter dated June 20, 2008, the city attorney notified Mirant that effective June 23, 2008, Sandy Springs was assessing Mirant $14.4 million for the city’s Business and Occupation Tax for 2006 in addition to the amounts previously paid by Mirant. The $14.4 million included penalties and interest of approximately $5.8 million. On August 15, 2008, Sandy Springs withdrew the assessment for 2006. Sandy Springs subsequently adopted an ordinance capping the amount of Business and Occupation Tax that an entity could owe for any year at $400,000 retroactive to 2006.

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 financial position, results of operations or cash flows.

L. Settlements and Other Charges

Pepco Litigation

In 2000, Mirant purchased power generating facilities and other assets from Pepco, including certain PPAs between Pepco and third parties. Under the terms of the APSA, Mirant and Pepco entered into the Back-to-Back Agreement with respect to certain PPAs, including Pepco’s long-term PPA with Panda-Brandywine, LP, under which (1) Pepco agreed to resell to Mirant all capacity, energy, ancillary services and other benefits to which it was entitled under those agreements and (2) Mirant agreed to pay Pepco each month all amounts due from Pepco to the sellers under those agreements for the immediately preceding month associated with such capacity, energy, ancillary services and other benefits. The Back-to-Back Agreement, which did not expire until 2021, obligated Mirant to purchase power from Pepco at prices that typically were higher than the market prices for power.

In the bankruptcy proceedings, the Mirant Debtors sought to reject the Back-to-Back Agreement or to recharacterize it as pre-petition debt, which efforts, if successful, would have resulted in the Mirant Debtors having no further obligation to perform and in Pepco receiving a claim in the bankruptcy proceedings for its resulting damages. Pending a final determination of the Mirant Debtors’ ability to reject or recharacterize the Back-to-Back Agreement and certain other agreements with Pepco, the Plan provided that the Mirant Debtors’ obligations under the APSA and the Back-to-Back Agreement were interim obligations of Mirant Power Purchase and were unconditionally guaranteed by Mirant.

On May 30, 2006, Mirant and various of its subsidiaries (collectively the “Mirant Settling Parties”) entered into the Settlement Agreement with Pepco (the “Pepco Settlement Agreement”) and various of its affiliates (collectively the “Pepco Settling Parties”). The Pepco Settlement Agreement could not become effective until it had been approved by the Bankruptcy Court and that approval order had become a final order no longer subject to appeal. The Bankruptcy Court entered an order approving the Pepco Settlement Agreement on August 9, 2006. That order was appealed, but the appeal was dismissed by agreement of the parties in August 2007, and the Pepco Settlement Agreement became effective August 10, 2007. The Pepco Settlement Agreement fully resolved the contract rejection motions that remained pending in the bankruptcy proceedings, as well as other matters disputed between Pepco and Mirant and its subsidiaries. Under the Pepco Settlement Agreement, Mirant Power Purchase assumed the remaining obligations under the APSA, and Mirant has guaranteed its performance. The Back-to-Back Agreement was rejected and terminated effective as of May 31, 2006.

The Pepco Settlement Agreement granted Pepco a claim against Old Mirant in Old Mirant’s bankruptcy proceedings that was to result in Pepco receiving common stock of Mirant and cash having a value, after liquidation of the stock by Pepco, equal to $520 million. Shortly after the Pepco Settlement Agreement became effective, Mirant distributed approximately 14 million shares of Mirant common stock from the shares reserved for disputed claims under the Plan to Pepco to satisfy its claim. The Mirant shares in the share reserve, including the shares distributed to Pepco, have been treated as issued and outstanding since Mirant emerged from bankruptcy. Pepco’s liquidation of those shares resulted in net proceeds of approximately $522 million and Pepco paid Mirant the amount in excess of $520 million. Pepco also refunded to Mirant Power

Purchase approximately $36 million Pepco had received under the Back-to-Back Agreement for energy, capacity or other services delivered after May 31, 2006, through the date the Pepco Settlement Agreement became effective. The appeal of the Bankruptcy Court’s August 9, 2006, approval order had resulted in Mirant paying Pepco $70 million under the terms of the Pepco Settlement Agreement shortly after the appeal was filed. Pepco repaid the $70 million once the Pepco Settlement Agreement became fully effective.

Upon the distribution of the shares to Pepco, Mirant recognized a gain of $379 million in the third quarter of 2007. The gain included (1) $341 million representing the fair value of the price risk management liability that was reversed as a result of the rejection of the Back-to-Back Agreement, (2) $36 million refunded by Pepco for payments made under the Back-to-Back Agreement for periods after May 31, 2006, and (3) $2 million for the excess payment Pepco received from liquidation of the shares that were distributed to it. The $341 million and $2 million were included in other income, net and the $36 million was included in gross margin in the unaudited condensed consolidated statement of operations for the three and nine months ended September 30, 2007.

Item 2.

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

The following discussion should be read in conjunction with Mirant’s 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 10,097 MW of net electric generating capacity. Our net electric generating capacity is located 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.

Share Repurchases

On November 9, 2007, we announced that we planned to return a total of $4.6 billion of excess cash to our stockholders based on four factors: (1) the outlook for the business, (2) preserving our credit profile, (3) maintaining adequate liquidity, including for capital expenditures and (4) maintaining sufficient working capital. Between November 2007 and September 2008, we returned approximately $3.856 billion of cash to our stockholders through purchases of 110 million shares of our common stock, including 74 million shares that were purchased through open market purchases in 2008 for approximately $2.54 billion. We have repurchased approximately 43% of the 256 million basic shares that we had outstanding when the program began in November 2007. On September 22, 2008, we announced that we had suspended our program to return excess cash to our stockholders based on our evaluation of the four factors that were set out upon commencement of the share repurchase program. On November 7, 2008, we announced that we are resuming our program of returning excess cash to our stockholders and will purchase an additional $200 million of shares through open market purchases. This $200 million is in addition to the previous $3.856 billion of cash returned to our stockholders. See Note I to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to our share repurchases.

Capital Expenditures and Capital Resources

We expect to incur total capital expenditures of $1.674 billion through the first quarter of 2010 to comply with the requirements for SO2 and NOx emissions under the Maryland Healthy Air Act. At September 30, 2008, we have paid approximately $797 million for capital expenditures related to the Maryland Healthy Air Act. For the nine months ended September 30, 2008, we paid $443 million for capital expenditures, of which $297 million related to the Maryland Healthy Air Act. The following table details our estimated capital expenditures, excluding capitalized interest, for the remainder of 2008 through 2010 (in millions):


	2008		2009		2010
Maryland Healthy Air Act	$	175	$	493	$	209
Other environmental		14		31		35
Maintenance		36		160		129
Construction		2		66		44
Other		6		14		15

Total	$	233	$	764	$	432

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

Emissions Allowances

Primarily as a result of the pollution control equipment we are installing to comply with the requirements of the Maryland Healthy Air Act, we have significant excess emissions allowances in future periods. We plan to continue to maintain some emissions allowances in excess of expected generation in case our actual generation exceeds our current forecasts for future periods and for possible future additions of generating capacity. During the fourth quarter of 2007, we began a program to sell excess emissions allowances dependent upon market conditions. In the first nine months of 2008, there were significant decreases in prices of emissions allowances. At September 30, 2008, the estimated fair value of our excess SO2 emissions allowances exceeded the carrying value.

In July 2008, the United States Court of Appeals for the District of Columbia Circuit (the “DC Circuit”) issued an opinion which would vacate the Clean Air Interstate Rule (“CAIR”). Following this ruling, prices for annual NOx emissions allowances declined significantly, and we recognized a lower of cost or market value adjustment of approximately $1 million related to annual NOx emissions allowances in inventory. See Other Developments for further discussion of the CAIR ruling.

In September 2008, we joined the Chicago Climate Exchange (“CCX”), a voluntary greenhouse gas registry, reduction and trading system. As part of the agreement for membership to CCX, we have committed to meet annual emission reduction targets and reduce our greenhouse gas emissions by six percent below the average of our 1998 to 2001 levels by 2010. We expect to satisfy our reduction targets through previously implemented generating unit retirements, capacity factor reductions and heat rate improvement efforts to increase the efficiency of our generating facilities.

Income Taxes

As a result of our repurchases of 154 million of shares of our common stock since July 11, 2006, and the exercise of a significant number of warrants for Mirant common stock during 2008, we think that during the third quarter of 2008 we experienced an “ownership change” within the meaning of §382 of the Internal Revenue Code of 1986, as amended. Our annual limitation on the amount of taxable income that can be offset by our then existing NOLs must be redetermined as of the date such ownership change occurs. We will not know the precise date of the ownership change until the first quarter of 2009 when certain holders of our shares will file a Schedule 13G under the Securities Exchange Act of 1934 and therefore we cannot currently determine with certainty our ongoing annual limitation.

Consolidated Financial Performance

We reported net income of $1.607 billion and $672 million for the three and nine months ended September 30, 2008, respectively, compared to net income of $775 million and $1.979 billion for the same periods in 2007. The change in net income is detailed as follows (in millions):


	Three Months Ended September 30,						Increase/ (Decrease)			Nine Months Ended September 30,						Increase/ (Decrease)
	2008			2007			Increase/ (Decrease)			2008			2007			Increase/ (Decrease)
Realized gross margin	$	417		$	509		$	(92	)	$	1,097		$	1,294		$	(197	)
Unrealized gross margin		1,395			13			1,382			218			(383	)		601

Total gross margin		1,812			522			1,290			1,315			911			404
Operating expenses:
Operations and maintenance		150			171			(21	)		519			519			—
Depreciation and amortization		35			33			2			108			97			11
Impairment losses		—			—			—			—			175			(175	)
Gain on sales of assets, net		(11	)		—			(11	)		(27	)		(24	)		(3	)

Total operating expenses		174			204			(30	)		600			767			(167	)

Operating income		1,638			318			1,320			715			144			571
Total other expense (income), net		36			(363	)		399			89			(289	)		378

Income from continuing operations before reorganization items, net and income taxes		1,602			681			921			626			433			193
Reorganization items, net		—			—			—			—			(2	)		2
Provision (benefit) for income taxes		(5	)		39			(44	)		5			9			(4	)

Income from continuing operations		1,607			642			965			621			426			195
Income from discontinued operations		—			133			(133	)		51			1,553			(1,502	)

Net income	$	1,607		$	775		$	832		$	672		$	1,979		$	(1,307	)

•

Our realized gross margin decreased $92 million and $197 million in the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007.

•

For the three months ended September 30, 2008, the decrease was principally a result of lower energy gross margin and contracted and capacity gross margin partially offset by higher realized value of hedges. The contracted and capacity gross margin for the three months ended September 30, 2007, included a refund to us of $36 million for payments made under the Back-to-Back Agreement for periods after May 31, 2006, as a result of the Pepco Settlement Agreement becoming fully effective in August 2007.

•

For the nine months ended September 30, 2008, the decrease was principally a result of lower energy gross margin, lower realized value of hedges and a decrease from proprietary trading and fuel oil management activities, partially offset by higher contracted and capacity gross margin in 2008.

•

Our unrealized gross margin increased $1.382 billion and $601 million in the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007. These increases were principally a result of increases in the value of hedge contracts for future periods and the related reversal of unrealized losses recorded in prior periods. Our unrealized gross margin was reduced by increases in the valuation adjustment for counterparty credit risk of $52 million and $60 million for the three and nine months ended September 30, 2008, respectively. See Item 3. Quantitative and Qualitative Disclosures about Market Risk—Counterparty Credit Risk for additional information.

•

Our results for the nine months ended September 30, 2007, include an impairment loss of $175 million on our Lovett facility. See Note F to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to this impairment.

•

For the three and nine months ended September 30, 2007, other expense (income), net included a gain of $343 million as a result of the Pepco Settlement Agreement that became fully effective in August 2007.

Commodity Prices

The prices for power, natural gas and fuel oil increased significantly during the first six months of 2008 and then decreased significantly during the three months ended September 30, 2008. As a result, most of the unrealized losses recognized during the first six months of 2008 reversed during the three months ended September 30, 2008. For the three months ended September 30, 2008, we recognized unrealized gains of $1.395 billion. For the nine months ended September 30, 2008, we recognized unrealized gains of $218 million.

The average market price for the types of coal that we use, however, was approximately 125% higher in the first nine months of 2008 than in the same period in 2007. Global demand for coal to generate electricity has been a significant factor influencing domestic prices for the types of coal that we use. As a result, the energy gross margin earned 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. We enter into contracts of varying terms 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 terms of 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 price risk management assets and liabilities in the accompanying unaudited condensed consolidated balance sheets. As of September 30, 2008, the net fair value of these long-term coal agreements was approximately $694 million.

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.

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, Morgantown, Dickerson and Potomac River facilities. The Northeast region includes our Bowline, Canal, Kendall, Lovett and Martha’s Vineyard facilities. The California region includes our Pittsburg, Contra Costa and Potrero facilities. Other Operations includes proprietary trading and fuel oil management activities. Other Operations also includes unallocated corporate overhead, interest on debt at Mirant Americas Generation and Mirant North America and interest on our invested cash balances. For the three and nine months ended September 30, 2007, Other Operations also includes gains and losses related to the Back-to-Back Agreement with Pepco, which was terminated pursuant to a settlement agreement that became effective in the third quarter of 2007. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for further discussion of the Pepco Settlement Agreement.

Operating Statistics

The following table summarizes Net Capacity Factor by region:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008		2007		Decrease		2008		2007		Decrease
Mid-Atlantic	37	%	41	%	(4	)%	33	%	36	%	(3	)%
Northeast	15	%	25	%	(10	)%	14	%	24	%	(10	)%
California	7	%	9	%	(2	)%	4	%	5	%	(1	)%
Total	25	%	30	%	(5	)%	22	%	26	%	(4	)%

The following table summarizes power generation volumes by region (in gigawatt hours):


	Three Months Ended September 30,		Decrease		Decrease %		Nine Months Ended September 30,		Increase/ (Decrease)		Increase/ (Decrease) %
	2008	2007	Decrease		Decrease %		2008	2007	Increase/ (Decrease)		Increase/ (Decrease) %
Mid-Atlantic:
Baseload	4,046	4,074	(28	)	(1	)%	11,020	11,244	(224	)	(2	)%
Intermediate	168	484	(316	)	(65	)%	352	1,015	(663	)	(65	)%
Peaking	46	188	(142	)	(76	)%	134	282	(148	)	(52	)%

Total Mid-Atlantic	4,260	4,746	(486	)	(10	)%	11,506	12,541	(1,035	)	(8	)%

Northeast:
Baseload	198	686	(488	)	(71	)%	773	2,082	(1,309	)	(63	)%
Intermediate	650	785	(135	)	(17	)%	1,565	2,305	(740	)	(32	)%
Peaking	3	5	(2	)	(40	)%	4	5	(1	)	(20	)%

Total Northeast	851	1,476	(625	)	(42	)%	2,342	4,392	(2,050	)	(47	)%

California:
Intermediate	345	447	(102	)	(23	)%	634	679	(45	)	(7	)%
Peaking	1	3	(2	)	(67	)%	21	18	3		17	%

Total California	346	450	(104	)	(23	)%	655	697	(42	)	(6	)%

Total Mirant	5,457	6,672	(1,215	)	(18	)%	14,503	17,630	(3,127	)	(18	)%

The decrease in power generation volumes for the three and nine months ended September 30, 2008, is primarily the result of the following:

•

a decrease in Mid-Atlantic intermediate and peaking generation volumes as a result of lower demand in the third quarter of 2008. For the nine months ended September 30, 2008, the decrease was also a result of contracting dark spreads and second quarter 2008 planned outages to allow for the installation of emissions control equipment as part of our compliance with the Maryland Healthy Air Act;

•

a decrease in Northeast as a result of higher fuel prices at times making it uneconomic for certain units to generate, the shutdown of units 3 and 4 of the Lovett generating facility in April 2007 and the shutdown of unit 5 of the Lovett generating facility in April 2008.

Our California facilities operate under tolling agreements with PG&E. Therefore, changes in power generation volumes from those facilities, which can be caused by weather, outages, or other factors, do not generally affect our gross margin.

Three Months Ended September 30, 2008 versus Three Months Ended September 30, 2007

Gross Margin Overview

The following table details realized and unrealized gross margin by operating segments (in millions):


	Three Months Ended September 30,
	2008						2007
	Realized		Unrealized		Total		Realized		Unrealized			Total
Mid-Atlantic	$	311	$	1,318	$	1,629	$	345	$	30		$	375
Northeast		48		7		55		77		(6	)		71
California		35		—		35		35		—			35
Other Operations		17		70		87		47		(11	)		36
Eliminations		6		—		6		5		—			5

Total	$	417	$	1,395	$	1,812	$	509	$	13		$	522

Gross margin for the three months ended September 30, 2008 and 2007, is further detailed as follows (in millions):


	Three Months Ended September 30, 2008
	Mid- Atlantic		Northeast			California		Other Operations			Eliminations		Total
Energy	$	148	$	23		$	1	$	17		$	6	$	195
Contracted and capacity		93		23			34		—			—		150
Realized value of hedges		70		2			—		—			—		72

Total realized gross margin		311		48			35		17			6		417
Unrealized gross margin		1,318		7			—		70			—		1,395

Total gross margin	$	1,629	$	55		$	35	$	87		$	6	$	1,812


	Three Months Ended September 30, 2007
	Mid- Atlantic		Northeast			California		Other Operations			Eliminations		Total
Energy	$	232	$	38		$	1	$	12		$	5	$	288
Contracted and capacity		84		21			34		35			—		174
Realized value of hedges		29		18			—		—			—		47

Total realized gross margin		345		77			35		47			5		509
Unrealized gross margin		30		(6	)		—		(11	)		—		13

Total gross margin	$	375	$	71		$	35	$	36		$	5	$	522

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 administered capacity markets, through RMR contracts and from ancillary services. For the three months ended September 30, 2007, contracted and capacity also includes the Back-to-Back Agreement which was terminated on August 10, 2007. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for further discussion of the Pepco Settlement Agreement.

Realized value of hedges represents the actual margin upon the settlement of our power and fuel hedging contracts, including coal supply contracts that qualify for the normal purchases or normal sales exclusion from SFAS 133 and which therefore qualify for the use of accrual accounting. The realized value of hedges includes the difference between market prices and contract costs for coal used to generate electricity in the period.

Unrealized gross margin represents the net unrealized gain or loss on our derivative contracts that are recorded as price risk management assets and liabilities on our condensed consolidated balance sheets, including the reversal of unrealized gains and losses recognized in prior periods and changes in value for future periods.

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 5,244 MW.

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


	Three Months Ended September 30,						Increase/ (Decrease)
	2008			2007			Increase/ (Decrease)
Realized gross margin	$	311		$	345		$	(34	)
Unrealized gross margin		1,318			30			1,288

Total gross margin		1,629			375			1,254

Operating expenses:
Operations and maintenance		96			91			5
Depreciation and amortization		23			21			2
Gain on sales of assets, net		(7	)		—			(7	)

Total operating expenses		112			112			—

Operating income		1,517			263			1,254
Total other expense (income), net		1			(1	)		2

Income from continuing operations before reorganization items and income taxes	$	1,516		$	264		$	1,252

Gross Margin


	Three Months Ended September 30,				Increase/ (Decrease)
	2008		2007		Increase/ (Decrease)
Energy	$	148	$	232	$	(84	)
Contracted and capacity		93		84		9
Realized value of hedges		70		29		41

Total realized gross margin		311		345		(34	)
Unrealized gross margin		1,318		30		1,288

Total gross margin	$	1,629	$	375	$	1,254

The decrease of $34 million in realized gross margin was principally a result of the following:

•

a decrease of $84 million in energy, primarily as a result of a substantial increase in the price of fuel, partially offset by an increase in power prices and a decrease in the cost of emissions allowances. In addition, generation volumes decreased 10% because our intermediate and peaking facilities generated less as a result of lower demand; partially offset by

•

an increase of $41 million in realized value of hedges as a result of a significant increase in the amount by which market prices for coal exceeded the contract prices for the coal that we purchased under our long-term agreements, partially offset by a decrease in the settlement value of power hedges. In 2008, market prices for power exceeded the settlement value of our power contracts. In 2007, the settlement value of our power contracts exceeded market prices; and

•

an increase of $9 million in contracted and capacity primarily related to higher capacity prices for 2008.

The increase of $1.288 billion in unrealized gross margin was comprised of the following:

•

unrealized gains of $1.318 billion in 2008, which included an $1.077 billion net increase in the value of hedge contracts for future periods primarily related to the reversal of unrealized losses recorded in prior periods, and unrealized gains of $241 million from power and fuel contracts that settled during the period for which net unrealized losses had been recorded in prior periods; and

•

unrealized gains of $30 million in 2007 as a result of increases in value associated with forward power and fuel contracts for future periods as a result of decreases in forward power prices in the third quarter of 2007, partially offset by decreases related to the settlement of power and fuel contracts during the period for which net unrealized gains had been recorded in prior periods.

Operating Expenses

The increase of $5 million in operations and maintenance expense was primarily related to increases in allocated corporate overhead costs. With the completion of the disposition of the Caribbean business by Mirant in August 2007, Mirant Mid-Atlantic received a greater allocation of Mirant’s corporate overhead costs in the three months ended September 30, 2008, than in the same period in 2007. The increase of $7 million in gain on sales of assets, net is primarily the result of sales of emissions allowances in 2008.

Northeast

Our Northeast segment is comprised of our four generating facilities located in New York and New England with total net generating capacity of 2,506 MW.

The following tables summarize the results of operations of our Northeast segment (in millions):


	Three Months Ended September 30,						Increase/ (Decrease)
	2008			2007			Increase/ (Decrease)
Realized gross margin	$	48		$	77		$	(29	)
Unrealized gross margin		7			(6	)		13

Total gross margin		55			71			(16	)

Operating expenses:
Operations and maintenance		33			46			(13	)
Depreciation and amortization		5			6			(1	)
Gain on sales of assets, net		(5	)		—			(5	)

Total operating expenses		33			52			(19	)

Operating income		22			19			3
Total other income, net		(1	)		—			(1	)

Income from continuing operations before reorganization items and income taxes	$	23		$	19		$	4

Gross Margin


	Three Months Ended September 30,					Increase/ (Decrease)
	2008		2007			Increase/ (Decrease)
Energy	$	23	$	38		$	(15	)
Contracted and capacity		23		21			2
Realized value of hedges		2		18			(16	)

Total realized gross margin		48		77			(29	)
Unrealized gross margin		7		(6	)		13

Total gross margin	$	55	$	71		$	(16	)

The decrease of $29 million in realized gross margin was principally a result of the following:

•

a decrease of $16 million in realized value of hedges for our generation output primarily as a result of a decrease in the amount by which the settlement value of power contracts exceeded market prices, partially offset by an increase in the amount by which market prices for fuel exceeded the contract prices; and

•

a decrease of $15 million in energy, primarily as a result of the shutdown of the Lovett facility.

The increase of $13 million in unrealized gross margin was comprised of unrealized gains of $7 million in 2008 compared to $6 million of unrealized losses in 2007. The unrealized losses in 2007 related to a decrease in value associated with forward power contracts for future periods as a result of increases in forward power prices and the settlement of power and fuel contracts during the period for which net unrealized gains had been recorded in prior periods.

Operating Expenses

The decrease of $19 million in operating expenses was principally the result of a decrease of $13 million in operations and maintenance expense primarily as a result of the shutdown of unit 5 of the Lovett generating facility in April 2008. See Note F to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the Lovett shutdown. The increase of $5 million in gain on sales of assets, net is primarily the result of sales of emissions allowances in 2008.

California

Our California segment consists of the Pittsburg, Contra Costa and Potrero facilities with total net generating capacity of 2,347 MW.

The following tables summarize the results of operations of our California segment (in millions):


	Three Months Ended September 30,					Increase/ (Decrease)
	2008			2007		Increase/ (Decrease)
Realized gross margin	$	35		$	35	$	—
Unrealized gross margin		—			—		—

Total gross margin		35			35		—

Operating expenses:
Operations and maintenance		17			18		(1	)
Depreciation and amortization		5			3		2
Gain on sales of assets, net		(2	)		—		(2	)

Total operating expenses		20			21		(1	)

Operating income		15			14		1

Income from continuing operations before reorganization items and income taxes	$	15		$	14	$	1

Gross Margin


	Three Months Ended September 30,				Increase/ (Decrease)
	2008		2007		Increase/ (Decrease)
Energy	$	1	$	1	$	—
Contracted and capacity		34		34		—

Total realized gross margin		35		35		—
Unrealized gross margin		—		—		—

Total gross margin	$	35	$	35	$	—

Other Operations

Other Operations includes proprietary trading and fuel oil management activities, unallocated corporate overhead, interest on debt at Mirant Americas Generation and Mirant North America and interest income on our invested cash balances. For the three months ended September 30, 2007, Other Operations also included gains and losses related to the Back-to-Back Agreement, which was terminated pursuant to the Pepco Settlement Agreement that became effective in the third quarter of 2007. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for further discussion of the Pepco Settlement Agreement.

The following tables summarize the results of operations of our Other Operations segment (in millions):


	Three Months Ended September 30,						Increase/ (Decrease)
	2008			2007			Increase/ (Decrease)
Realized gross margin	$	17		$	47		$	(30	)
Unrealized gross margin		70			(11	)		81

Total gross margin		87			36			51

Operating expenses:
Operations and maintenance		4			16			(12	)
Depreciation and amortization		2			3			(1	)
Gain on sales of assets, net		(1	)		—			(1	)

Total operating expenses		5			19			(14	)

Operating income		82			17			65
Total other expense (income), net		36			(362	)		398

Income from continuing operations before reorganization items and income taxes	$	46		$	379		$	(333	)

Gross Margin


	Three Months Ended September 30,					Increase/ (Decrease)
	2008		2007			Increase/ (Decrease)
Energy	$	17	$	12		$	5
Contracted and capacity		—		35			(35	)

Total realized gross margin		17		47			(30	)
Unrealized gross margin		70		(11	)		81

Total gross margin	$	87	$	36		$	51

The decrease of $30 million in realized gross margin was principally a result of the following:

•

a decrease of $35 million in contracted and capacity resulting from the third quarter 2007 refund of $36 million of payments made to Pepco under the Back-to-Back Agreement for periods after May 31, 2006, as a result of the Pepco Settlement Agreement becoming fully effective. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the Pepco Settlement Agreement; partially offset by

•

an increase of $5 million in energy as a result of increases from proprietary trading and fuel oil management activities.

The increase of $81 million in unrealized gross margin was comprised of the following:

•

unrealized gains of $70 million in 2008 related to proprietary trading and fuel oil management activities; and

•

unrealized losses of $11 million in 2007 comprised of $7 million of unrealized losses related to proprietary trading and fuel oil management activities and unrealized losses of $4 million on the Back-to-Back Agreement which was terminated in the third quarter of 2007.

Operating Expenses

The decrease of $14 million in operating expenses was primarily a result of a decrease of $12 million in operations and maintenance expense, which included:

•

a decrease of $4 million related to labor costs, including the bonus plan for dispositions;

•

a decrease of $4 million related to corporate overhead costs included in Other Operations in 2007 but allocated across Mirant’s operating segments in 2008; and

•

a decrease of $3 million related to litigation contingencies.

Other Expense (Income), Net

The increase of $398 million in other expense (income), net was primarily a result of the following:

•

a decrease of $344 million in other, net, which included:

•

a gain of $341 million in 2007 resulting from the termination of the Back-to-Back Agreement and a gain of $2 million for the refund of excess proceeds from the sale of shares distributed to Pepco, both pursuant to the Pepco Settlement Agreement becoming fully effective August 10, 2007. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the Pepco Settlement Agreement; and

•

a loss of approximately $2 million in 2008 related to the purchase of $200 million of Mirant Americas Generation senior notes due in 2011.

•

a decrease of $69 million in interest income primarily related to lower interest rates on invested cash and lower average cash balances; partially offset by

•

a decrease of $15 million in interest expense primarily related to lower debt outstanding and higher interest capitalized on construction projects in 2008.

Other Significant Consolidated Statements of Operations Comparison

Provision (Benefit) for Income Taxes

Provision (benefit) for income taxes decreased $44 million for the three months ended September 30, 2008, compared to the same period in 2007. The decrease was primarily related to a $49 million intra-period tax adjustment in 2007 to the amounts previously recognized in continuing operations relating to the sale of the Philippine business included in discontinued operations. See Overview in this Item 2 for additional information on income taxes.

Discontinued Operations

For the three months ended September 30, 2008, there was no income from discontinued operations. For the three months ended September 30, 2007, income from discontinued operations was $133 million and included:

•

a pre-tax gain of $62 million on the sale of the Caribbean business; and

•

an income tax benefit of $49 million related to the sale of the Philippine business.

See Note E to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the dispositions and discontinued operations.

Nine Months Ended September 30, 2008 versus Nine Months Ended September 30, 2007

Gross Margin Overview

The following table details realized and unrealized gross margin by operating segments (in millions):


	Nine Months Ended September 30,
	2008							2007
	Realized		Unrealized			Total		Realized		Unrealized			Total
Mid-Atlantic	$	788	$	200		$	988	$	808	$	(323	)	$	485
Northeast		160		(3	)		157		220		(38	)		182
California		95		—			95		98		—			98
Other Operations		48		21			69		154		(22	)		132
Eliminations		6		—			6		14		—			14

Total	$	1,097	$	218		$	1,315	$	1,294	$	(383	)	$	911

Gross margin for the nine months ended September 30, 2008 and 2007, is further detailed as follows (in millions):


	Nine Months Ended September 30, 2008
	Mid- Atlantic			Northeast			California		Other Operations			Eliminations		Total
Energy	$	474		$	65		$	3	$	48		$	6	$	596
Contracted and capacity		252			68			92		—			—		412
Realized value of hedges		62			27			—		—			—		89

Total realized gross margin		788			160			95		48			6		1,097
Unrealized gross margin		200			(3	)		—		21			—		218

Total gross margin	$	988		$	157		$	95	$	69		$	6	$	1,315


	Nine Months Ended September 30, 2007
	Mid- Atlantic			Northeast			California		Other Operations			Eliminations		Total
Energy	$	529		$	99		$	3	$	138		$	14	$	783
Contracted and capacity		122			66			95		16			—		299
Realized value of hedges		157			55			—		—			—		212

Total realized gross margin		808			220			98		154			14		1,294
Unrealized gross margin		(323	)		(38	)		—		(22	)		—		(383	)

Total gross margin	$	485		$	182		$	98	$	132		$	14	$	911

Contracted and capacity represents gross margin received from capacity sold in ISO administered capacity markets, through RMR contracts and from ancillary services. For the nine months ended September 30, 2007, contracted and capacity also includes the Back-to-Back Agreement which was terminated on August 10, 2007. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for further discussion of the Pepco Settlement Agreement.

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 5,244 MW.

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


	Nine Months Ended September 30,						Increase/ (Decrease)
	2008			2007			Increase/ (Decrease)
Realized gross margin	$	788		$	808		$	(20	)
Unrealized gross margin		200			(323	)		523

Total gross margin		988			485			503

Operating expenses:
Operations and maintenance		306			265			41
Depreciation and amortization		67			60			7
Gain on sales of assets, net		(9	)		(2	)		(7	)

Total operating expenses		364			323			41

Operating income		624			162			462
Total other expense (income), net		1			(4	)		5

Income from continuing operations before reorganization items and income taxes	$	623		$	166		$	457

Gross Margin


	Nine Months Ended September 30,					Increase/ (Decrease)
	2008		2007			Increase/ (Decrease)
Energy	$	474	$	529		$	(55	)
Contracted and capacity		252		122			130
Realized value of hedges		62		157			(95	)

Total realized gross margin		788		808			(20	)
Unrealized gross margin		200		(323	)		523

Total gross margin	$	988	$	485		$	503

The decrease of $20 million in realized gross margin was principally a result of the following:

•

a decrease of $95 million in realized value of hedges primarily as a result of a decrease in the settlement value of power hedges. In 2008, market prices for power exceeded the settlement value of power contracts. In 2007, the settlement value of power contracts exceeded market prices. The decrease in power hedges was partially offset by an increase in the amount by which market prices for coal exceeded the contract prices for the coal that we purchased under our long-term agreements;

•

a decrease of $55 million in energy, primarily as a result of a substantial increase in the price of fuel, partially offset by an increase in power prices and a decrease in the cost of emissions allowances. In addition, generation volumes decreased 8% because our intermediate and peaking facilities generated less as a result of lower demand, contracting dark spreads and second quarter 2008 planned outages to allow for the installation of emissions control equipment as part of our compliance with the Maryland Healthy Air Act; partially offset by

•

an increase of $130 million in contracted and capacity primarily related to higher capacity revenues for the entire nine months in 2008 as a result of the PJM RPM under which we began to receive revenue in June 2007.

The increase of $523 million in unrealized gross margin was comprised of the following:

•

unrealized gains of $200 million in 2008, which included an increase of $307 million from power and fuel contracts that settled during the period for which net unrealized losses had been recorded in prior periods, partially offset by a $107 million net decrease in the value of hedge contracts for future periods primarily related to increases in forward power and natural gas prices; and

•

unrealized losses of $323 million in 2007 as a result of the settlement of power and fuel contracts during the period for which net unrealized gains had been recorded in prior periods and decreases in value associated with forward power and fuel contracts for future periods as a result of increases in forward power prices in 2007.

Operating Expenses

The increase of $41 million in operating expenses is primarily a result of the following:

•

an increase of $41 million in operations and maintenance expense, which included:

•

an increase of $19 million related to the timing of our planned outages and an increase in labor and chemical costs related to our pollution control equipment; and

•

$20 million in increased allocated corporate overhead costs. With the completion of several dispositions by Mirant in the second and third quarters of 2007 and the shutdown of units 3 and 4 of the Lovett generating facility in the second quarter of 2007, Mirant Mid-Atlantic received a greater allocation of Mirant’s corporate overhead costs in the nine months ended September 30, 2008, than in the same period in 2007;

•

an increase of $7 million in depreciation and amortization expense related to pollution control equipment placed in service as part of our compliance with the Maryland Healthy Air Act, partially offset by

•

an increase of $7 million in gain on sales of assets, net primarily as a result of the sales of emissions allowances in 2008.

Northeast

Our Northeast segment is comprised of our four generating facilities located in New York and New England with total net generating capacity of 2,506 MW.

The following tables summarize the results of operations of our Northeast segment (in millions):


	Nine Months Ended September 30,						Increase/ (Decrease)
	2008			2007			Increase/ (Decrease)
Realized gross margin	$	160		$	220		$	(60	)
Unrealized gross margin		(3	)		(38	)		35

Total gross margin		157			182			(25	)

Operating expenses:
Operations and maintenance		130			138			(8	)
Depreciation and amortization		15			19			(4	)
Impairment losses		—			175			(175	)
Gain on sales of assets, net		(21	)		(25	)		4

Total operating expenses		124			307			(183	)

Operating income (loss)		33			(125	)		158
Total other income, net		(1	)		(6	)		5

Income (loss) from continuing operations before reorganization items and income taxes	$	34		$	(119	)	$	153

Gross Margin


	Nine Months Ended September 30,						Increase/ (Decrease)
	2008			2007			Increase/ (Decrease)
Energy	$	65		$	99		$	(34	)
Contracted and capacity		68			66			2
Realized value of hedges		27			55			(28	)

Total realized gross margin		160			220			(60	)
Unrealized gross margin		(3	)		(38	)		35

Total gross margin	$	157		$	182		$	(25	)

The decrease of $60 million in realized gross margin was principally a result of the following:

•

a decrease of $34 million in energy, primarily as a result of the shutdown of the Lovett facility, lower generation volumes and increased fuel costs, partially offset by higher power prices; and

•

a decrease of $28 million in realized value of hedges for our generation output, primarily as a result of a decrease in the amount by which the settlement value of power contracts exceeded market prices, partially offset by an increase in the settlement value of fuel contracts.

The increase of $35 million in unrealized gross margin was comprised of unrealized losses of $3 million in 2008 compared to $38 million in 2007. The unrealized losses were related to the settlement of power and fuel contracts during the period for which net unrealized gains had been recorded in prior periods, partially offset by increases in value associated with forward power and fuel contracts for future periods primarily as a result of decreases in forward power prices.

Operating Expenses

The decrease of $183 million in operating expenses was principally the result of the following:

•

a decrease of $175 million as a result of the impairment loss on our Lovett facility recognized in the second quarter of 2007. See Note F to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to this impairment;

•

a decrease of $8 million in operations and maintenance expense primarily related to the Lovett facility, which includes a decrease of $23 million in operating costs, partially offset by $15 million of shutdown costs incurred in the nine months ended September 30, 2008. See Note F to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the shutdown of the Lovett facility; and

•

a decrease of $4 million in gain on sales of assets. In 2008, subsidiaries in our Northeast segment recognized a gain of $21 million related to emissions allowances primarily sold to third parties. In 2007, subsidiaries in our Northeast segment recognized a gain of $25 million, of which $10 million related to emissions allowances sold to Mirant Mid-Atlantic that are eliminated in our unaudited condensed consolidated statement of operations.

California

Our California segment consists of the Pittsburg, Contra Costa and Potrero facilities with total net generating capacity of 2,347 MW.

The following tables summarize the results of operations of our California segment (in millions):


	Nine Months Ended September 30,						Increase/ (Decrease)
	2008			2007			Increase/ (Decrease)
Realized gross margin	$	95		$	98		$	(3	)
Unrealized gross margin		—			—			—

Total gross margin		95			98			(3	)

Operating expenses:
Operations and maintenance		57			54			3
Depreciation and amortization		19			10			9
Gain on sales of assets, net		(3	)		(2	)		(1	)

Total operating expenses		73			62			11

Operating income		22			36			(14	)
Total other income, net		—			(5	)		5

Income from continuing operations before reorganization items and income taxes	$	22		$	41		$	(19	)

Gross Margin


	Nine Months Ended September 30,
	2008		2007		Decrease
Energy	$	3	$	3	$	—
Contracted and capacity		92		95		(3	)

Total realized gross margin		95		98		(3	)
Unrealized gross margin		—		—		—

Total gross margin	$	95	$	98	$	(3	)

The decrease of $3 million in contracted and capacity is primarily related to extended outages at unit 3 of the Potrero generating facility in 2008.

Operating Expenses

The increase of $11 million in operating expenses was principally the result of higher development costs and higher depreciation expense in 2008.

Other Operations

Other Operations includes proprietary trading and fuel oil management activities, unallocated corporate overhead, interest on debt at Mirant Americas Generation and Mirant North America and interest income on our invested cash balances. For the nine months ended September 30, 2007, Other Operations also included gains and losses related to the Back-to-Back Agreement, which was terminated pursuant to the settlement agreement that became fully effective in the third quarter of 2007. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for further discussion of the Pepco Settlement Agreement.

The following tables summarize the results of operations of our Other Operations segment (in millions):


	Nine Months Ended September 30,						Increase/ (Decrease)
	2008			2007			Increase/ (Decrease)
Realized gross margin	$	48		$	154		$	(106	)
Unrealized gross margin		21			(22	)		43

Total gross margin		69			132			(63	)

Operating expenses:
Operations and maintenance		26			62			(36	)
Depreciation and amortization		7			8			(1	)
Gain on sales of assets, net		(1	)		(5	)		4

Total operating expenses		32			65			(33	)

Operating income		37			67			(30	)
Total other expense (income), net		89			(274	)		363

Income (loss) from continuing operations before reorganization items and income taxes	$	(52	)	$	341		$	(393	)

Gross Margin


	Nine Months Ended September 30,					Increase/ (Decrease)
	2008		2007			Increase/ (Decrease)
Energy	$	48	$	138		$	(90	)
Contracted and capacity		—		16			(16	)

Total realized gross margin		48		154			(106	)
Unrealized gross margin		21		(22	)		43

Total gross margin	$	69	$	132		$	(63	)

The decrease of $106 million in realized gross margin was principally a result of the following:

•

a decrease of $90 million in energy, comprised of a $66 million decrease from fuel oil management activities and a $24 million decrease from proprietary trading activities; and

•

a decrease of $16 million in contracted and capacity resulting from the termination of the Back-to-Back Agreement in the third quarter of 2007. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the Pepco Settlement Agreement.

The increase of $43 million in unrealized gross margin was comprised of the following:

•

unrealized gains of $21 million in 2008 related to proprietary trading and fuel oil management activities; and

•

unrealized losses of $22 million in 2007 comprised of $111 million of unrealized losses related to proprietary trading and fuel oil management activities, partially offset by unrealized gains of $89 million on the Back-to-Back Agreement which was terminated in the third quarter of 2007.

Operating Expenses

The decrease of $33 million in operating expenses was primarily a result of a decrease of $36 million in operations and maintenance expense, which included:

•

a decrease of $28 million related to corporate overhead costs included in Other Operations in 2007 but allocated across Mirant’s operating segments in 2008;

•

a decrease of $21 million related to litigation contingencies;

•

a decrease of $8 million related to labor costs, including the bonus plan for dispositions; partially offset by

•

an increase of $27 million related to 2007 curtailment gains on pension and postretirement benefits reflected as a reduction of operations and maintenance expense in the nine months ended September 30, 2007.

Other Expense (Income), Net

Other expense (income), net increased $363 million, primarily as a result of the following:

•

a decrease in other, net of $352 million, which included:

•

a gain of $341 million in 2007 resulting from the termination of the Back-to-Back Agreement and a gain of $2 million for the refund of excess proceeds from the sales of

shares distributed to Pepco, both as a result of the Pepco Settlement Agreement becoming fully effective. See Note L to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the Pepco Settlement Agreement; and

•

a loss of approximately $8 million in 2008 related to the purchase of $200 million of Mirant Americas Generation senior notes due in 2011.

•

a decrease of $68 million in interest income primarily related to lower interest rates on invested cash; partially offset by

•

a decrease of $57 million in interest expense related to lower debt outstanding and higher interest capitalized on construction projects in 2008.

Other Significant Consolidated Statements of Operations Comparison

Provision (Benefit) for Income Taxes

Provision (benefit) for income taxes decreased $4 million for the nine months ended September 30, 2008, compared to the same period in 2007. The decrease was attributable to adjustments of various state tax liabilities in 2007.

Discontinued Operations

For the nine months ended September 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, and final working capital adjustments related to the 2007 sale of the Caribbean business.

For the nine months ended September 30, 2007, income from discontinued operations was $1.553 billion and included:

•

a pre-tax gain of $2.004 billion on the sale of the Philippine business, a pre-tax gain of $62 million on the sale of the Caribbean business, a reduction to the previous impairment of the six U.S. natural gas-fired facilities of $31 million and a gain of $8 million on the sale of Mirant NY-Gen; partially offset by

•

an income tax provision of $704 million related to the sale of the Philippine business; and

•

operating results for discontinued operations.

See Note E to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information related to the dispositions and discontinued operations.

Financial Condition

Liquidity and Capital Resources

Sources of Funds

The principal sources of liquidity for our future operations and capital expenditures are expected to be: (1) existing cash on hand and cash flows from the operations of our subsidiaries; (2) letters of credit issued or borrowings made under the Mirant North America senior secured revolving credit facility; and (3) letter of credit capacity available under the Mirant North America senior secured term loan. In addition, our cash and cash equivalents will be reduced by the continued return of cash to stockholders pursuant to our announced plans.

The table below sets forth total cash, cash equivalents and availability under credit facilities of Mirant Corporation and its subsidiaries (in millions):


	At September 30, 2008		At December 31, 2007
Cash and Cash Equivalents:
Mirant Corporation	$	1,691	$	4,232
Mirant Americas Generation		19		1
Mirant North America		316		455
Mirant Mid-Atlantic		233		242
Other		5		31

Total cash and cash equivalents		2,264		4,961
Less: Cash restricted and reserved for other purposes		2		15

Total available cash and cash equivalents		2,262		4,946
Available under credit facilities		623		710

Total cash, cash equivalents and credit facilities availability	$	2,885	$	5,656

We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At September 30, 2008 and December 31, 2007, except for amounts held in bank accounts to cover upcoming payables, all of our cash and cash equivalents were invested in AAA-rated U.S. Treasury money market funds.

Available under credit facilities at September 30, 2008, 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 Mirant North America senior secured revolving credit facility. See Part II, Item 1A. Risk Factors for a description of risks related to the lenders under our credit facility.

Except for existing cash on hand and, in the case of Mirant North America, borrowings and letters of credit under its credit facilities, Mirant Corporation, Mirant Americas Generation and Mirant North America 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 September 30, 2008, 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 $549 million at Mirant North America and its subsidiaries. Of this amount, $233 million was held by Mirant Mid-Atlantic which, as of September 30, 2008, met the tests under the leveraged lease documentation permitting it to make distributions to Mirant North America. After taking into account the financial results of Mirant North America for the nine months ended September 30, 2008, we expect Mirant North America will distribute approximately $109 million to its parent, Mirant Americas Generation, in November 2008.

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 required to keep our generating facilities in operation; (2) debt service and payments under the Mirant Mid-Atlantic leveraged leases; (3) our asset management and proprietary trading activities; and (4) the development of new generating facilities.

Return of Cash to Stockholders. Since November 2007, we returned $3.856 billion of excess cash to our stockholders through repurchases of our common stock. See Overview in this Item 2 for further discussion of our share repurchases.

Capital Expenditures. Our capital expenditures for the nine months ended September 30, 2008, were $443 million. Our estimated capital expenditures for the period October 1, 2008, through December 31, 2010, are $1.43 billion. See Overview 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 trade 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 reserves and for other operating activities. Trade 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 September 30, 2008, we had approximately $153 million of posted cash collateral and $264 million of letters of credit outstanding primarily to support our asset management activities, debt service and rent reserve requirements and other commercial arrangements. 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. In July 2008, we entered into a cash-collateralized letter of credit facility pursuant to which we posted letters of credit in support of our response to a request for proposals for new power generation. In the third quarter of 2008, we posted a $25 million surety bond as credit support for the RGGI auction that was held in September 2008. In September 2008, we placed $34 million in an escrow account to satisfy the conditions of the settlement agreement with the City of Alexandria. See Other Developments for further discussion of that settlement agreement.

The following table summarizes cash collateral posted with counterparties and brokers, letters of credit issued and surety bonds (in millions):


	At September 30, 2008		At December 31, 2007
Cash collateral posted—energy trading and marketing	$	111	$	96
Cash collateral posted—other operating activities		42		14
Letters of credit—energy trading and marketing		67		100
Letters of credit—debt service and rent reserves		75		78
Letters of credit—other operating activities		122		112
Surety bonds—energy trading and marketing		25		—

Total	$	442	$	400

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

Described below are significant changes to our debt obligations, off-balance sheet arrangements and contractual obligations as of September 30, 2008, from those presented in our 2007 Annual Report on Form 10-K.

In the first nine months of 2008, we entered into additional fuel commitments, primarily related to long-term coal agreements. As of September 30, 2008, we have approximately $894 million of fuel commitments. Of this amount, $83 million relates to the remainder of 2008, $331 million relates to 2009, $209 million relates to 2010, $178 million relates to 2011, $58 million relates to 2012 and $35 million relates to 2013. At December 31, 2007, our total estimated fuel commitments were approximately $506 million, of which $314 million related to 2008 and $192 million related to 2009. We have no fuel commitments for periods beyond 2013.

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. Cash provided by operating activities from continuing operations decreased $83 million for the nine months ended September 30, 2008, compared to the same period in 2007, primarily as a result of the following:

•

a decrease in realized gross margin of $197 million in 2008, compared to the same period in 2007. See Results of Operations for additional discussion of our performance in 2008 compared to the same period in 2007;

•

an increase in cash used of $79 million related to changes in net accounts receivable and accounts payable in 2008 compared to 2007, primarily as a result of increases in power prices in 2008 and the net refund of $48 million related to a New York property tax settlement in 2007;

•

a decrease in cash provided of $70 million related to the Pepco Settlement Agreement becoming fully effective in the third quarter of 2007, which is included in other assets in our unaudited condensed consolidated statements of cash flows. Pepco repaid $70 million in 2007 for an advance payment made in the third quarter of 2006 under the Pepco Settlement Agreement; and

•

an increase in cash used of $26 million for interest, net reflecting lower interest income as a result of lower interest rates on invested cash as well as lower cash balances as a result of share repurchases partially offset by lower interest expense from lower outstanding debt and higher capitalized interest.

The increases in cash used by operating activities are partially offset by the following:

•

a decrease in cash used of $152 million because of changes in funds on deposit. In 2008, we had net cash collateral returned to us of $60 million, primarily related to the cash collateral account to support issuance of letters of credit under the Mirant North America senior secured term loan. In 2007, we posted an additional $92 million of cash collateral;

•

a decrease in cash used of $90 million primarily as a result of the reduction of fuel inventory levels;

•

a decrease in operations and maintenance expense of $25 million excluding a non-cash decrease in curtailment gains on pension and postretirement benefits of $27 million; and

•

a decrease in cash used of $23 million for bankruptcy related claims and expenses.

Investing Activities. Net cash used in investing activities from continuing operations increased by $113 million for the nine months ended September 30, 2008, compared to the same period in 2007. This difference was primarily a result of the following:

•

an increase in cash used of $58 million for capital expenditures primarily related to our environmental capital expenditures for our Maryland generating facilities;

•

an increase in cash used of $12 million related to capitalized interest for projects under construction;

•

an increase in cash used of $36 million primarily related to $34 million placed in an escrow account in September 2008 to satisfy the conditions of Mirant Potomac River’s settlement agreement with the City of Alexandria; and

•

a decrease of $7 million in proceeds from the sales of assets in 2008 as compared to 2007. In 2008, we received $27 million of proceeds from the sale of assets, primarily from the sale of emissions allowances. In 2007, we received $34 million of proceeds from the sale of assets, which included approximately $30 million from the sale of ancillary equipment included in the sale of the six U.S. natural gas-fired facilities.

Financing Activities. Net cash used in financing activities from continuing operations increased by $2.741 billion for the nine months ended September 30, 2008, compared to the same period in 2007. This difference was primarily a result of the following:

•

an increase in cash used of $2.551 billion for share repurchases. See Note I to our unaudited condensed consolidated financial statements contained elsewhere in this report for additional information on share repurchases; and

•

an increase in cash used of $201 million primarily as a result of the retirement of $200 million of Mirant Americas Generation senior notes due in 2011.

Discontinued Operations

Operating Activities. 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 $7 million from the sale of transmission credits from our previously owned Wrightsville facility. In 2007, net cash provided by operating activities from discontinued operations included cash flows from the Philippine and Caribbean businesses, six U.S. natural gas-fired facilities, and Mirant NY-Gen.

Investing Activities. Net cash provided by investing activities from discontinued operations was $25 million for the nine months ended September 30, 2008, compared to $5.263 billion for the same period in 2007. This difference was primarily a result of the following:

•

2007 results included the $5.409 billion in proceeds from the sale of our Caribbean business in the third quarter of 2007 and our Philippine business and six U.S. natural gas-fired facilities in the second quarter of 2007, partially offset by an increase of $20 million primarily related to capital expenditures incurred in 2007 at our Caribbean business prior to its disposition; and

•

2008 results included $25 million in insurance recoveries related to repairs to the Sual generating facility and the Swinging Bridge facility of Mirant NY-Gen.

Financing Activities. In 2007, net cash used in financing activities was $669 million and primarily related to the repayment of long-term debt of $795 million, partially offset by a decrease in debt service reserves of $125 million related to our Philippine business.

Other Developments

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 Northeast regional initiative outlining a cap-and-trade program to reduce CO2 emissions from units of 25 MW or greater. The RGGI program calls for signatory states to stabilize CO2 emissions to current levels from 2009 to 2015, followed by a 2.5% reduction each year from 2015 to 2018. Regulations to implement the RGGI have now been approved in each of Maryland, Massachusetts and New York.

We expect to produce a total of approximately 15.8 million tons of CO2 at our Maryland, Massachusetts and New York generating facilities in 2009. The RGGI regulations require those facilities to obtain allowances to emit CO2 beginning in 2009. No allowances will be granted to existing sources of such emissions. Instead, allowances will be made available for such facilities only by purchase through a periodic auction process conducted regionally or through subsequent purchase from a party that holds allowances sold through the auctions. The Maryland regulations implementing the RGGI also provide that if allowance prices exceed $7 per ton of CO2 in the auctions of allowances that occur during the first three years, we and other Maryland generators will have the option to purchase from the state a portion of the remaining allowances that would have been auctioned in that particular calendar year for our generating facilities located within Maryland at $7 per ton regardless of auction clearing prices. Any such allowances made available at $7 per ton would be allocated among eligible generators based on average heat input during 2003 through 2005.

The first auction of allowances by RGGI states was held on September 25, 2008. The states of Connecticut, Maine, Maryland, Massachusetts, Rhode Island and Vermont offered allowances for sale. The clearing price for the approximately 12.5 million allowances sold in the auction was $3.07 per ton. The allowances sold in this auction can be used for compliance in any of the RGGI states, including the RGGI states that did not participate in this first auction. Further auctions will occur on a quarterly basis through 2011, with the next auction scheduled for December 2008. The state of New York is expected to participate in that auction.

We are continuing to evaluate our options to comply with the RGGI, but its implementation 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 the Global Warming Solutions Act (“AB 32”), which requires that greenhouse gas emissions be reduced to 1990 levels by 2020. AB 32 also requires the California Air Resources Board to develop by January 2009 a greenhouse gas reduction plan for all industrial sectors. The California Air Resources Board’s draft scoping plan proposes the implementation of a cap-and-trade program that is to be designed and administered in collaboration with other western states and Canadian provinces that are participating in the Western Climate Initiative, a collaboration initiated in February 2007 by the governors of seven states and the premiers of four Canadian provinces to identify and implement collective ways to reduce emissions of greenhouse gases in the region. The California plan for reducing emissions of greenhouse gasses could have a material effect on how we operate our California facilities and the costs of operating the facilities. The AB 32 implementation plan for greenhouse gas reduction goes into effect in 2012.

In August 2008, Massachusetts also adopted a Global Warming Solutions Act (the “Climate Protection Act”) establishing a program to reduce greenhouse gas emissions significantly over the next 40 years. Under the Climate Protection Act, the Massachusetts Department of Environmental

Protection (“MADEP”) is to establish a reporting and verification system for statewide greenhouse gas emissions, including emissions from generation sources producing all electricity consumed in Massachusetts, and to determine what the state’s greenhouse gas emissions level was in 1990. The Massachusetts Executive Office of Energy and Environmental Affairs (“MAEEA”) is then to establish statewide greenhouse gas emissions limits effective beginning in 2020 that will reduce such emissions from the 1990 levels by 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 effect on how we operate our Massachusetts facilities and the costs of operating those facilities.

Either Congress or the EPA also likely will take action to regulate CO2 within the next 10 years. A number of proposals are currently being considered. 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 the CO2 emitted by our generating facilities. While 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 the future results on our statements of operations, financial position or cash flows.

Canal NPDES and Surface Water Discharge Permits. On August 1, 2008, the EPA issued to Mirant Canal an NPDES renewal permit for the Canal generating facility. The same permit was concurrently issued by MADEP as a state surface water discharge permit. The new permit imposes a requirement upon Mirant Canal to install closed cycle cooling or an alternative technology that will reduce the entrainment of marine organisms by the Canal generating facility to levels equivalent to what would be achieved by closed cycle cooling. On September 2, 2008, Mirant Canal appealed the NPDES permit to the EPA’s Environmental Appeals Board and appealed the surface water discharge permit to the MADEP. While the appeals are pending, the effect of any contested permit provisions will be stayed and the Canal generating facility will continue to operate under its current NPDES permit. We cannot predict the outcome of this proceeding.

NPDES and SPDES Permit Renewals. In addition to the proceeding described above in Canal NPDES and Surface Water Discharge Permits related to the renewal of the NPDES permit for the Canal facility, proceedings are currently pending for renewal of the NPDES permits for the Morgantown and Dickerson facilities leased by Mirant Mid-Atlantic, the Chalk Point facility owned by Mirant Chalk Point, the Company’s three ash disposal sites in Maryland, the Potomac River facility owned by Mirant Potomac River, the Pittsburg and Contra Costa facilities owned by Mirant Delta, the Potrero facility owned by Mirant Potrero, and the Kendall facility owned by Mirant Kendall. A proceeding is also pending for renewal of the State Pollutant Discharge Elimination System (“SPDES”) permit for the Bowline facility owned by Mirant Bowline. In general, the EPA and the state agencies responsible for implementing the provisions of the Clean Water Act applicable to the intake of water and discharge of effluent by electric generating facilities have been making the requirements imposed upon such facilities more stringent over time. For example, with respect to the Potrero facility, the California Regional Water Quality Control Board has previously stated its intent not to renew the facility’s NPDES permit unless Mirant Potrero can demonstrate that the operation of the facility does not adversely affect the San Francisco Bay. With respect to each of these permit renewal proceedings, the agency or agencies involved could impose requirements upon the Mirant entity owning the facility that require

significant capital additions, limit the times at which the facility can operate, or increase operations and maintenance costs materially. In each case, the permit renewal proceeding could take several years to resolve, and the Mirant facility for which the permit renewal is sought will continue to operate under its current NPDES permit or SPDES permit (in the case of Mirant Bowline) until a final decision has been reached in the permit renewal proceeding.

Mirant Potomac River State Operating Permits. On May 23, 2007, the Virginia State Air Pollution Control Board directed the Virginia DEQ to issue a state operating permit for the Potomac River facility 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 can operate at one time. The Virginia DEQ issued the permit as directed on June 1, 2007. In June 2007, Mirant Potomac River filed a petition for appeal in the Circuit Court of the City of Richmond, Virginia, seeking to set aside the Virginia State Air Pollution Control Board’s directive of May 23, 2007, and the permit issued by the Virginia DEQ on June 1, 2007. In March 2008, the Circuit Court of the City of Richmond upheld the Virginia State Air Pollution Control Board’s directive and the permit. Mirant Potomac River appealed that decision, but filed to dismiss that appeal, as discussed below, and the appeal has now been dismissed.

On November 30, 2007, the Virginia State Air Pollution Control Board directed the Virginia DEQ to develop an alternative and more comprehensive state operating permit that would allow completion of a proposed project to merge the stacks of certain of the units at the Potomac River facility, set SO2 emissions limits for the facility and allow for greater operating flexibility. On December 21, 2007, the Virginia DEQ published a draft of this alternative state operating permit for public comment. In early July 2008, the City of Alexandria, Virginia (in which the Potomac River generating facility is located) and Mirant Potomac River entered into an agreement that proposed certain terms to be included in the proposed comprehensive permit and committed Mirant Potomac River to spend $34 million over several years to reduce particulate emissions. The $34 million commitment was collateralized and is included in our estimated capital expenditures presented earlier in this section. 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. After the permit issued July 31, 2008, became final and nonappealable, Mirant Potomac River filed a motion seeking to dismiss its pending appeal of the permit issued June 1, 2007, by the Virginia DEQ.

The June 1, 2007, permit will be supplanted by the more comprehensive permit issued on July 31, 2008, after completion of a project to merge the stacks for units 3, 4, and 5 at the Potomac River generating facility, which we expect to occur in late 2008. We will then separately merge the stacks for units 1 and 2. Once both stack mergers have been completed, which we expect to occur in early 2009, the permit issued July 31, 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 operations by not allowing trading of emissions allowances, as described below in Virginia CAIR Implementation. Mirant Potomac River has challenged those regulations in court, and their continued effectiveness is uncertain because of the decision issued by the DC Circuit on July 11, 2008, in State of North Carolina v. Environmental Protection Agency vacating the CAIR.

Clean Air Interstate Rule (CAIR). In 2005, the EPA promulgated the CAIR, which established in the eastern United States SO2 and NOx cap-and-allowance trading programs applicable directly to states and indirectly to generating facilities. These cap-and-trade programs were to be implemented in two phases, with the first phase going into effect in 2009 for NOx and 2010 for SO2 and more stringent caps going into effect in 2015. Various parties appealed the

EPA’s adoption of the CAIR, and on July 11, 2008, the DC Circuit in State of North Carolina v. Environmental Protection Agency issued an opinion that would vacate the CAIR, finding that it had several fatal flaws. Among other things, the DC Circuit found that the regional cap-and-allowance trading programs established by the CAIR did not achieve the intended purpose of ensuring that upwind states did not prevent attainment of NAAQS in downwind states because emitters in upwind states could potentially buy large quantities of emissions allowances. Second, the DC Circuit opinion found that the criteria used by the EPA in setting caps for SO2 emissions and in allocating NOx emissions were inconsistent with the statutory criteria and with Title IV of the Clean Air Act. Various parties have filed requests for rehearing with the DC Circuit, and the court’s ruling has not yet become effective. At this time, we cannot predict what action the court may take on the motions for reconsideration or the EPA’s action on remand.

Massachusetts CAIR Implementation. The MADEP promulgated regulations to take effect in 2009 to reduce NOx emissions from certain generating facilities. The Massachusetts regulations will require our Canal and Kendall generating facilities during the Ozone Season to reduce their emissions of NOx or utilize emissions allowances greater than currently utilized. The continued effectiveness of the Massachusetts regulations is at this time uncertain because of the decision issued by the DC Circuit on July 11, 2008, in State of North Carolina v. Environmental Protection Agency that would vacate the CAIR.

New York CAIR Implementation. The New York State Department of Environmental Conservation promulgated regulations implementing the NOx and SO2 emissions reductions required by the federal CAIR beginning in 2009. Those regulations will limit NOx emissions through both an annual cap-and-trade program and through a seasonal cap-and-trade program during the Ozone Season, which will require our Bowline generating facility to reduce its emissions of NOx by running less or to increase its utilization of emissions allowances. The regulations also provide for an SO2 emissions program beginning in 2010 that will mandate increased utilization of federal SO2 allowances for every ton of SO2 emitted. The continued effectiveness of the New York regulations is at this time uncertain because of the decision issued by the DC Circuit on July 11, 2008, in State of North Carolina v. Environmental Protection Agency that would vacate the CAIR.

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 an area that is not in compliance with a particular NAAQS (“non-attainment area”), from purchasing SO2 and NOx allowances to achieve compliance under the CAIR. In the fourth quarter of 2007, the Virginia State Air Pollution Control Board approved regulations that it interprets as prohibiting the trading of SO2 and NOx allowances by facilities in non-attainment areas to satisfy the requirements of the CAIR as implemented by Virginia. Our Potomac River facility is located in a non-attainment area for ozone and PM2.5, and Mirant Potomac River has appealed these regulations in Virginia state court. In late July 2008, the Virginia state court issued a ruling dismissing our appeal, which decision we have appealed. We have also petitioned (a) the EPA to reconsider and (b) the United States Court of Appeals for the Fourth Circuit (“Fourth Circuit”) to review the EPA’s final rule approving Virginia’s CAIR program. The continued effectiveness of the Virginia regulations is uncertain at this time because of the decision issued by the DC Circuit on July 11, 2008, in State of North Carolina v. Environmental Protection Agency that would vacate the CAIR. On October 9, 2008, the Fourth Circuit at the request of the EPA ruled that Mirant Potomac River’s petition seeking review of the EPA’s approval of Virginia’s CAIR program would be held in abeyance pending the outcome of the petitions for reconsideration filed in State of North Carolina v. Environmental Protection Agency.

Critical Accounting Estimates

The sections below contain material 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 2007 Annual Report on Form 10-K.

Fair Value Measurements

Nature of Estimates Required. We 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 activities. We use a variety of derivative contracts, such as forwards, futures, swaps and option contracts, in the management of our business. Such derivative contracts have varying terms and durations, or tenors, which range from a few days to years, depending on the instrument.

Pursuant to SFAS 133, derivative contracts are reflected in our financial statements at fair value, with changes in fair value recognized currently in earnings 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 contracts is included in price risk management assets and liabilities in our condensed consolidated balance sheets. Transactions that do not qualify for fair value accounting under SFAS 133 are either not derivatives or qualify for a scope exception and are accounted for under accrual accounting. With the adoption of SFAS 157 on January 1, 2008, we no longer defer unobservable inception gains and losses.

Key Assumptions and Approach Used. Determining the fair value of our derivatives is based largely on quoted prices from exchanges and independent brokers in active markets. Our view is 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. We determine the fair value of our derivative instruments as the difference in the transaction price and the market price, multiplied by quantity for each transaction. Since the adoption of SFAS 157 on January 1, 2008, we utilize for the market price the quoted bid or ask price for our derivative instruments.

If no active market exists, we estimate the fair value of certain derivative contracts using price extrapolation, interpolation and other quantitative methods. 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. Our assets and liabilities classified as Level 3 in the fair value hierarchy represent approximately 1% of our total assets and 0% of our total liabilities measured at fair value at September 30, 2008. See Note C to our unaudited condensed consolidated financial statements contained elsewhere in this report for an explanation of the fair value hierarchy.

The fair value of price risk management assets and liabilities in our condensed consolidated balance sheets is also affected by our assumptions as to time value, credit risk and nonperformance 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 price risk management assets is reduced to reflect the estimated default risk of counterparties on their contractual obligations to us. The fair value of our price risk management liabilities is reduced to reflect our estimated risk of default on our contractual obligations to counterparties. The credit risk reflected in the fair value of our price risk management assets and the nonperformance risk reflected in the fair value of our price risk management 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 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 Note C to our unaudited condensed consolidated financial statements contained elsewhere in this report for further information on 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 income statement 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 Mirant’s own implied volatility of its 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 the lack of exercise history for the Company, the simplified method for estimating expected term has been used in accordance with SAB 107, to the extent applicable. In accordance with SAB 110, the simplified method can continue to be applied to stock option grants after December 31, 2007. 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 U.S. Treasury yield curve in effect at the time of the grant.

We have determined that all of the awards granted in 2008 and 2007 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 cost has been adjusted based on estimated forfeitures. During the three and nine months ended September 30, 2008, we recognized approximately $6 million and $19 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 result in an increase of $1 million and $4 million, respectively, in recognized compensation expense for the three and nine months ended September 30, 2008. 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 nine months ended September 30, 2008. 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 where further discussed.

Asset Retirement Obligations

Nature of Estimates Required. We account for asset retirement obligations under SFAS 143 and under FIN 47. SFAS 143 and FIN 47 require an entity to recognize the fair value of a liability for conditional and unconditional asset retirement obligations in the period in which they are incurred. Retirement obligations associated with long-lived assets included within the scope of SFAS 143 and FIN 47 are those obligations for which a requirement exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel. Asset retirement obligations are estimated using the estimated current cost to satisfy the retirement obligation, increased for inflation through the expected period of retirement and discounted back to present value at our credit-adjusted risk free rate. We have identified certain retirement obligations within our power generating operations and have a noncurrent liability of $39 million recorded as of September 30, 2008. These asset retirement obligations are primarily related to asbestos abatement at some of our generating facilities, the removal of oil storage tanks, equipment on leased property and environmental obligations related to the closing of ash disposal sites. In the third quarter of 2008, we revised our current cost assumption for asbestos abatement at our generating facilities based on the actual costs we have incurred as part of the decommissioning of the Lovett facility. The revision resulted in an increase to our asset retirement obligation of approximately $2 million.

Key Assumptions and Approach Used. The fair value of liabilities associated with the initial recognition of asset retirement obligations is estimated by applying a present value calculation to current engineering cost estimates of satisfying the obligations. Significant inputs to the present value calculation include current cost estimates, estimated asset retirement dates and appropriate discount rates. Where appropriate, multiple cost and/or retirement scenarios have been probability weighted.

Effect if Different Assumptions Used. We update liabilities associated with asset retirement obligations as significant assumptions change or as relevant new information becomes available. A 1% increase in our rate of inflation would result in an approximate $5 million increase to the asset retirement obligation recorded on our unaudited condensed consolidated balance sheet as of September 30, 2008, and a 1% increase or decrease in our discount rate would result in an approximate $4 million change.

Litigation

See Note K 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.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

Fair Value Measurements

We are exposed to market risks associated with commodity prices, interest rates and credit risk. We adopted SFAS 157 on January 1, 2008, which affected our presentation and disclosure of derivative financial instruments used to mitigate our commodity price risk. See Note C to our unaudited condensed consolidated financial statements contained elsewhere in this report for further information on the adoption of SFAS 157. We also adopted FSP FIN 39-1 on January 1, 2008, and elected to discontinue the net presentation of assets and liabilities subject to master netting agreements. See Note B to our unaudited condensed consolidated financial statements contained elsewhere in this report for further information on the adoption of FSP FIN 39-1. The election to present our price risk management assets and price risk management liabilities on a gross basis does not affect our credit risk or value at risk at September 30, 2008.

The estimated net fair value of our price risk management assets and liabilities was a net asset of $87 million at September 30, 2008. The following table provides a summary of the factors affecting the change in fair value of the price risk management asset and liability accounts for the nine months ended September 30, 2008 (in millions):


Fair value of portfolio of assets and liabilities at January 1, 2008, net¹	$	(129	)
Gains (losses) recognized in the period, net:
New contracts and other changes in fair value²		54
Roll off of previous values³		337
Purchases, issuances and settlements⁴		(175	)

Fair value of portfolio of assets and liabilities at September 30, 2008, net	$	87

Reflects the Company’s portfolio of price risk management 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 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.

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

⁴

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

The table above does 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 price risk management assets and liabilities in the accompanying condensed consolidated balance sheets. As of September 30, 2008, these coal agreements had an estimated net fair value of approximately $694 million, which includes a credit reserve of $27 million for the default risk of our coal suppliers. See Long-Term Coal Agreement Risk for further discussion later in this section.

As discussed in Note B to our unaudited condensed consolidated financial statements contained elsewhere in this report, 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 price risk management 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 price risk management assets, related to counterparty credit risk of $58 million and $4 million at September 30, 2008 and December 31, 2007, respectively.

We have historically calculated the credit reserve for all of our price risk management 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 market observable inputs, when available. In the third quarter of 2008, we changed the methodology used to calculate our credit reserve for our non-collateralized power hedges entered into by Mirant Mid-Atlantic with our major trading partners, which represents 84% of our net notional position at September 30, 2008. These transactions are senior unsecured obligations of Mirant Mid-Atlantic 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, considering our current exposure and potential loss exposure from the financial commitments in our risk management portfolio. We apply a similar approach to calculate the fair value of our coal contracts that are not included in price risk management 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. The change in our methodology resulted in an increase to our credit reserve at September 30, 2008, of approximately $55 million on our price risk management assets. 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 $6 million in our credit reserve as of September 30, 2008. An increase of 10% in the spread of credit default swaps of our coal suppliers would result in an increase of $3 million in our credit reserve of our long-term coal agreements that are not included in price risk management assets and liabilities in the accompanying condensed consolidated balance sheets as of September 30, 2008.

For the remainder of our portfolio, we will continue to use published historical default probabilities to calculate a credit reserve considering our current exposure, net of the effect of credit enhancements, and potential loss exposure from the financial commitments in our risk management portfolio. 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 September 30, 2008.

Mirant Credit Risk

In valuing our price risk management 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. We recognized a non-performance adjustment related to our credit risk of $1 million at September 30, 2008. A downgrade of one notch in our credit rating would result in a gain of $1 million in our unaudited condensed consolidated statement of operations as of September 30, 2008.

Broker Quotes

In determining the fair value of our price risk management 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 market inputs such as broker quotes. In accordance with the exit price objective under SFAS 157, the fair value of our price risk management 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 September 30, 2008, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.

Inactive markets are considered to be 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. 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 price risk management 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. Our assets and liabilities classified as Level 3 in the fair value hierarchy represent approximately 1% of our total assets and 0% of our total liabilities measured at fair value at September 30, 2008. 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

We are also subject to interest rate risk when determining the fair value of our price risk management assets and liabilities. The nominal value of our price risk management 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 $7 million to our price risk management assets and a decrease of $7 million to our price risk management liabilities at September 30, 2008.

Credit Concentration Risk

We also monitor credit concentration risk on both an individual basis and a group counterparty basis. The following table highlights the credit quality and the balance sheet settlement exposures related to these activities as of September 30, 2008 (dollars in millions):


Credit Rating Equivalent	Exposure Before Collateral¹		Credit Collateral²		Exposure Net of Collateral		% of Net Exposure
Investment Grade
Financial Institutions	$	173	$	1	$	172	41	%
Energy Companies		192		11		181	43	%
Other		4		—		4	1	%
Non-Investment Grade
Financial Institutions		—		—		—	—
Energy Companies		—		—		—	—
Other		—		—		—	—
No External Ratings:
Internally-rated Investment Grade		51		—		51	12	%
Internally-rated Non-Investment Grade		11		—		11	3	%
Not Internally Rated		—		—		—	—	%

Total	$	431	$	12	$	419	100	%

The table excludes amounts related to contracts classified as normal purchase/normal sales and non-derivative contractual commitments that are not recorded in our condensed consolidated balance sheets, except for any related accounts receivable. Such contractual commitments contain credit and economic risk if a counterparty does not perform.

²	Collateral includes cash and letters of credit offset by any cash collateral posted by us to a counterparty which is in excess of the amount currently owed to that counterparty.

Long-Term Coal Agreement Risk

As noted above, the credit concentration table excludes amounts related to contracts classified as normal purchase/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 or power in the market to meet our needs. 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 and other collateral arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers. Nonperformance 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 Value at Risk to measure some of these risks, see Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2007 Annual Report on Form 10-K.

Item 4.

Controls and Procedures

Inherent Limitations in Control Systems

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements because of error or fraud may occur and not be detected. As a result, our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures, or our internal control over financial reporting, will prevent all error and all fraud.

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 September 30, 2008. Based upon this assessment, our management concluded that, as of September 30, 2008, 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 nine month period ended September 30, 2008, 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 K 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 2007 Annual Report on Form 10-K includes a discussion of our risk factors. The information presented below updates, and should be read in conjunction with, the risk factors and information disclosed in our 2007 Annual Report on Form 10-K. Except as presented below, there have been no material changes in our risk factors since those reported in our 2007 Annual Report on Form 10-K.

The global financial crisis may have an effect on our business and financial condition in ways that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system has had and may continue to have an effect on our business and our financial condition. For example, in October 2008, Lehman Commercial Paper, Inc., a subsidiary of Lehman Brothers Holdings, Inc. and a lender under the senior secured revolving credit facility of our subsidiary, Mirant North America, filed for bankruptcy. As a result of the Lehman Commercial Paper, Inc. bankruptcy, we expect that the total availability under our senior secured revolving credit facility has decreased from $800 million to $755 million assuming that Lehman Commercial Paper, Inc. does not honor its $45 million commitment. While we do not expect that the Lehman Commercial Paper, Inc. bankruptcy will have a material adverse effect on Mirant, the credit crisis could negatively affect availability under the Mirant North America senior secured revolving credit facility if other lenders under such facility are forced to file for bankruptcy or are otherwise unable to perform their obligations. Absent significant non-performance of lenders under the existing Mirant North America senior secured revolving credit facility, we think that we have sufficient liquidity for future operation (including potential working capital requirements) and capital expenditures as discussed in “Management’s Discussion and Analysis—Liquidity and Capital Resources.” However, in the event of significant non-performance of lenders under the existing Mirant North America senior secured revolving credit facility, the credit crisis could have a negative effect on our ability to obtain new lines of credit if financial institutions are unwilling or unable to enter into new revolving credit facilities.

In addition to the potential effect on our liquidity that could arise from the global financial crisis, the crisis could have a negative effect on the markets in which we sell power, purchase fuel and perform other trading and marketing activities. In recent years, global financial institutions have been active participants in such markets. As such financial institutions consolidate and operate under more restrictive capital constraints in response to the financial crisis, there could be less liquidity in the energy and commodity markets, which could have a negative effect on our ability to hedge and transact with creditworthy counterparties. In addition, we are exposed to credit risk resulting from the possibility that a loss may occur from the failure of a counterparty to perform according to the terms of a contractual arrangement with us. Deterioration in the financial condition of our counterparties as a result of the global financial crisis and the resulting failure to pay amounts owed to us or to perform obligations or services owed to us beyond collateral posted could have a negative effect on our business and financial condition.

Because of the current market design in California our generating facilities may have a limited life unless we make significant capital expenditures to increase their commercial and environmental performance.

Our generating facilities in California depend almost entirely on payments in support of system reliability. The energy and capacity markets, as currently constituted, will not support the capital expenditures necessary to repower or reconstruct our facilities to make them commercially viable in a merchant market. If a commercially reasonable capacity market were to be instituted by the CAISO or we could obtain a long-term contract with a creditworthy buyer, it is possible that we could obtain the necessary capital support for repowering or reconstructing our facilities. Absent that, our generating facilities will be commercially viable only as long as they are necessary for reliability.

Item 2.

Share Repurchases

•

On November 9, 2007, we announced that the first stage of the cash distribution would be accomplished through an accelerated share repurchase program for $1 billion, plus open market purchases for up to an additional $1 billion. In the fourth quarter of 2007, we repurchased 26.66 million shares of common stock for $1 billion through the accelerated share repurchase program.

•

On February 29, 2008, we announced that we had decided to return the remaining $2.6 billion of cash through open market purchases of common stock but that we would continue to evaluate the most efficient method to return the cash to stockholders.

•

On May 15, 2008, the accelerated share repurchase program was completed and we received an additional 682,387 shares, resulting in a total of 27.34 million shares purchased. The final price of shares repurchased under the accelerated share repurchase program was $36.57 per share, which was determined based on a discount to the volume weighted average trading price of our common stock over the period of the accelerated share repurchase program.

On September 22, 2008, we announced that we had suspended our program to return excess cash to our stockholders based on our evaluation of the four factors that were set out upon commencement of the share repurchase program.

On November 7, 2008, we announced that we are resuming our program of returning excess cash to our stockholders and will purchase an additional $200 million of shares through open market purchases. This $200 million is in addition to the previous $3.856 billion of cash returned to our stockholders.

The following table sets forth information regarding open market repurchases of our common stock during the three-month period ended September 30, 2008:


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
	(in millions)			(in millions)	(in millions)
July 1, 2008—July 31, 2008	—		—	—	$	1,549.41
August 1, 2008—August 31, 2008	12.78	$	28.89	12.78	$	1,180.29
September 1, 2008—September 30, 2008	16.98	$	25.67	16.98	$	—

Total	29.76			29.76

Item 6.

Exhibits

(a) Exhibits.


Exhibit No.		Exhibit Name
3.1*		Amended and Restated Certificate of Incorporation of Registrant (Designated on Form 8-K filed January 3, 2006 as Exhibit 3.1)
3.2*		Amended and Restated Bylaws of Registrant (Designated on Form 8-K filed November 6, 2008 as Exhibit 3.2)
4.1*		Form of Warrant Agreement between Registrant and Mellon Investor Services LLC, as Warrant Agent (Designated on Form 8-K filed January 3, 2006 as Exhibit 4.1)
10.1		Mirant Corporation 2006 Non-Employee Directors Compensation Plan
31.1		Certification of Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Chief Financial Officer Pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
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))

*	Asterisk indicates exhibits incorporated by reference.

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: November 7, 2008	By:	/S/ THOMAS E. LEGRO
		Thomas E. Legro
		Senior Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)