Edgar Filing: MIRANT CORP

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Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the Fiscal Year Ended December 31, 2007

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

For the Transition Period from to

Mirant Corporation

(Exact name of registrant as specified in its charter)


Delaware	001 16107	20-3538156
(State or other jurisdiction of Incorporation or Organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

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

(678) 579 5000
(Registrant’s Telephone Number, Including Area Code)

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


Title of each class		Name of each exchange on which registered
Common Stock, par value $0.01 per share		New York Stock Exchange
Series A Warrants		New York Stock Exchange
Series B Warrants		New York Stock Exchange

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

None

Indicate by check mark whether the registrant is a well-known seasoned issuer (as defined by Rule 405 of the Securities Act). ¨ Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. ¨ Yes x No

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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


Large Accelerated Filer x		Accelerated Filer ¨

Non-accelerated Filer ¨ (Do not check if a smaller reporting company)		Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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

Aggregate market value of voting stock held by non-affiliates of the registrant was approximately $10,915,832,854 on June 30, 2007 (based on $42.65 per share, the closing price in the daily composite list for transactions on the New York Stock Exchange that day). As of February 25, 2008, there were 213,989,279 shares of the registrant’s Common Stock, $0.01 par value per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s proxy statement for the 2008 Annual Meeting of Stockholders are incorporated by reference in Part III of this Form 10-K to the extent described herein.

TABLE OF CONTENTS


		Page
	Glossary of Certain Defined Terms	i - v

	PART I
Item 1.	Business	5
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	31
Item 3.	Legal Proceedings	31
Item 4.	Submission of Matters to a Vote of Security Holders	31

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	37
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	73
Item 8.	Financial Statements and Supplementary Data	F-1
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	77
Item 9A.	Controls and Procedures	77
Item 9B.	Other Information	78

	PART III
Item 10.	Directors and Executive Officers of the Registrant	79
Item 11.	Executive Compensation	79
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	79
Item 13.	Certain Relationships and Related Transactions	79
Item 14.	Principal Accountant Fees and Services	79

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	80

Glossary of Certain Defined Terms

APB—Accounting Principles Board.

APB 18—APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stocks.

APB 22—APB Opinion No. 22, Disclosure of Accounting Policies.

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

Bankruptcy Code—United States Bankruptcy Code.

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

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

CAIR—Clean Air Interstate Rule.

CAISO—California Independent System Operator.

Cal PX—California Power Exchange.

CAMR—Clean Air Mercury Rule.

CERCLA—Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980.

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.

DOE—United States Department of Energy.

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.

EITF 06-3—EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).

EOB—California Electricity Oversight Board.

EPA—United States Environmental Protection Agency.

EPAct 2005—Energy Policy Act of 2005.

EPS—Earnings per share.

ERISA—Employee Retirement Income Security Act of 1974.

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.

FIN 48—FIN No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.

FSP—FASB Staff Position.

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

FSP FIN 46R-6—FSP FIN No. 46R-6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46R.

FSP FIN 48-1—FSP FIN No. 48-1, Definition of Settlement in FASB Interpretation No. 48 (FIN 48).

GAAP—Generally accepted accounting principles in the United States.

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

Hudson Valley Gas—Hudson Valley Gas Corporation.

IBEW—International Brotherhood of Electrical Workers.

InterContinental Exchange—InterContinental Exchange, Inc.

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

ISO—Independent System Operator.

ISO-NE—Independent System Operator-New England.

JPS—Jamaica Public Service Company Limited.

kW—Kilowatt.

LIBOR—London InterBank Offered Rate.

LTSA—Long-term service agreement.

MAAC—Mid-Atlantic Area Council.

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—Mirant Americas, Inc.

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

Mirant Americas Generation—Mirant Americas Generation, LLC.

Mirant Asia-Pacific—Mirant Asia-Pacific Limited.

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 Mid-Atlantic—Mirant Mid-Atlantic, LLC and its subsidiaries.

Mirant New York—Mirant New York, Inc.

Mirant North America—Mirant North America, LLC.

Mirant NY-Gen—Mirant NY-Gen, LLC.

Mirant Pagbilao—Mirant Pagbilao Corporation.

Mirant Potomac River—Mirant Potomac River, LLC.

Mirant Power Purchase—Mirant Power Purchase, LLC.

Mirant Services—Mirant Services, LLC.

Mirant Sual—Mirant Sual Corporation.

Mirant Trinidad Investments—Mirant Trinidad Investments, LLC.

MISO—Midwest Independent Transmission System Operator.

MW—Megawatt.

MWh—Megawatt hour.

NAAQS—National ambient air quality standards.

NEPOOL—New England Power Pool.

NERC—North American Electric Reliability Council.

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.

NPCC—Northeastern Power Coordinating Council.

NSR—New source review.

NYISO—Independent System Operator of New York.

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 to September 30 of each year, during which ozone levels are reported to the EPA.

iii

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

Pension Protection Act—Pension Protection Act of 2006.

Pepco—Potomac Electric Power Company.

Petition Date—July 14, 2003, the date Mirant and certain of its subsidiaries filed voluntary petitions for relief with the Bankruptcy Court.

PG&E—Pacific Gas & Electric Company.

PJM—Pennsylvania-New Jersey-Maryland 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.

PUHCA—Public Utility Holding Company Act of 1935.

Reserve Margin—Excess capacity over peak demand.

RMR—Reliability-must-run.

RTO—Regional Transmission Organization.

SAB—SEC Staff Accounting Bulletin.

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

SAB 108—SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.

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.

SFAS—Statement of Financial Accounting Standards.

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

SFAS 109—SFAS No. 109, Accounting for Income Taxes.

SFAS 123—SFAS No. 123, Accounting for Stock-Based Compensation.

SFAS 123R—SFAS No. 123R, Share-Based Payment.

SFAS 132R—SFAS No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements Nos. 87, 88 and 106.

SFAS 133—SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.

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 153—SFAS No. 153, Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.

SFAS 155—SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements Nos. 133 and 140.

SFAS 156—SFAS No. 156, Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140.

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.

Shady Hills—Shady Hills Power Company, L.L.C.

SO2—Sulfur dioxide.

SOP 90-7—Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code.

The Tokyo Electric Power Company—The Tokyo Electric Power Company, Incorporated.

UWUA—Utility Workers Union of America.

VaR—Value-at-risk.

VIE—Variable interest entity.

Virginia DEQ—Virginia Department of Environmental Quality.

WECC—Western Electric Coordinating Council.

West Georgia—West Georgia Generating Company, L.L.C.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In addition to historical information, the information presented in this Form 10-K 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,” “plan,” “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 failure 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;

•

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 inability to enter into intermediate and long-term contracts to sell power and procure fuel, including its transportation, 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;

•

our ability to obtain adequate supply and delivery of fuel for our facilities;

•

curtailment of operations due to transmission constraints;

•

environmental regulations that restrict our ability or render it uneconomic to operate our business, including regulations related to the emission of carbon dioxide 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;

•

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 flow of those subsidiaries to make debt service and other payments; and

•

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

Many of these risks 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 consolidated financial statements, other factors that could affect our future performance (business, financial condition or results of operations and cash flows) are set forth under Item 1A. Risk Factors.

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, as further discussed in Item 1. Business.

PART I

Item 1.

Business

Overview

We are a competitive energy company that produces and sells electricity in the United States. We own or lease 10,280 MW of electric generating capacity located in markets in the Mid-Atlantic (5,244 MW) and Northeast regions (2,689 MW) and in California (2,347 MW). We also operate an integrated asset management and energy marketing organization based in Atlanta, Georgia. Our customers are ISOs, investor-owned utilities, municipal systems, aggregators, electric cooperative utilities, producers, generators, marketers and large industrial customers. Our generating portfolio is diversified across fuel types, power markets and dispatch types and serves customers located near many major metropolitan load centers. Our total net generating capacity is approximately 31% baseload, 57% intermediate and 12% peaking.

Mirant Corporation was incorporated in Delaware on September 23, 2005. Pursuant to the Plan for Mirant and certain of its subsidiaries, on January 3, 2006, New Mirant emerged from bankruptcy and acquired substantially all of the assets of Old Mirant, a corporation that was formed in Delaware on April 3, 1993, and that had been named Mirant Corporation prior to January 3, 2006. The Plan provides that New Mirant has no successor liability for any unassumed obligations of Old Mirant. Old Mirant was then renamed and transferred to a trust, which is not affiliated with New Mirant.

In the third quarter of 2006, we commenced separate auction processes to sell our Philippine (2,203 MW) and Caribbean (1,050 MW) businesses and six U.S. natural gas-fired facilities totaling 3,619 MW, consisting of the Zeeland (903 MW), West Georgia (613 MW), Shady Hills (469 MW), Sugar Creek (561 MW), Bosque (546 MW) and Apex (527 MW) facilities. On May 1, 2007, we completed the sale of the six U.S. natural gas-fired facilities. On June 22, 2007, we completed the sale of our Philippine business. On August 8, 2007, we completed the sale of our Caribbean business. In addition, on May 7, 2007, we completed the sale of Mirant NY-Gen (121 MW). After transaction costs and repayment of debt, the net proceeds to us from dispositions completed for the year ended December 31, 2007, were approximately $5.071 billion. See Note 11 to our consolidated financial statements contained elsewhere in this report for additional information regarding the accounting for these businesses and facilities as discontinued operations.

On April 9, 2007, we announced that our Board of Directors had decided to explore strategic alternatives to enhance stockholder value. In the exploration process, the Board of Directors considered whether the interests of stockholders would be best served by returning excess cash from the sale proceeds to stockholders, with us continuing to operate our retained businesses or, alternatively, whether greater stockholder value would be achieved by entering into a transaction with another company, including a sale of the Company in its entirety. On November 9, 2007, we announced the conclusion of the strategic review process. We plan to return a total of $4.6 billion of excess cash to our stockholders. The first stage of the cash distribution is being 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, in conjunction with the accelerated share repurchases, we repurchased approximately 26.66 million shares of our common stock for $1 billion. See Note 13 to our consolidated financial statements contained elsewhere in this report for further discussion. In addition, we purchased approximately 8.27 million shares of our common stock for approximately $316 million through open market purchases. Between January 1, 2008 and February 25, 2008, we purchased an additional 7.9 million shares in open market purchases for approximately $286 million. 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.

The annual, quarterly and current reports, and any amendments to those reports, that we file with or furnish to the SEC, are available free of charge on our website at www.mirant.com as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. General information about us, including our

Corporate Governance Guidelines, the charters for our Audit, Compensation, and Nominating and Governance Committees, and our Code of Ethics and Business Conduct, can also be found at www.mirant.com. We will provide print copies of these documents to any stockholder upon written request to Corporate Secretary, Mirant Corporation, 1155 Perimeter Center West, Suite 100, Atlanta, Georgia 30338-5416. Information contained on our website is not incorporated into this Form 10-K.

Business Segments

We have four operating segments: Mid-Atlantic, Northeast, California and Other Operations. The Mid-Atlantic segment consists of four generating facilities located in Maryland and Virginia. The Northeast segment consists of five generating facilities located in Massachusetts and New York. The California segment consists of three generating facilities located in or near the City of San Francisco. Other Operations includes proprietary trading, fuel oil management, and gains and losses related to a long-term PPA with Pepco (the “Back-to-Back Agreement”), which was terminated pursuant to a settlement agreement that became effective in the third quarter of 2007. See Note 19 to our consolidated financial statements contained elsewhere in this report for further discussion of the Back-to-Back Agreement. Other Operations also includes unallocated corporate overhead, interest on debt at Mirant Americas Generation and Mirant North America and interest income on our invested cash balances.

The table below presents our power generating performance metrics for the year ended December 31, 2007:


Region	Total (MW)	Net Capacity Factor
Mid-Atlantic	5,244	37	%
Northeast	2,689	22	%
California	2,347	4	%

The table below summarizes selected financial information of our continuing operations by business segment for the year ended December 31, 2007 (dollars in millions):


	Revenues		%		Gross Margin		%		Operating Income (Loss)			%
Business Segment:
Mid-Atlantic	$	1,133	56	%	$	605	55	%	$	164		116	%
Northeast		664	33	%		237	21	%		(93	)	(66	)%
California		177	9	%		135	12	%		50		36	%
Other Operations		45	2	%		112	10	%		13		9	%
Eliminations		—	—	%		18	2	%		7		5	%

Total	$	2,019	100	%	$	1,107	100	%	$	141		100	%

Eliminations are primarily related to intercompany sales of emissions allowances. For selected financial information about our business segments, see Note 15 to our consolidated financial statements contained elsewhere in this report. See Item 2. Properties for a complete list of our plants.

Commercial Operations

Our commercial operations consist primarily of procuring fuel, dispatching electricity, hedging the production and sale of electricity by our generating facilities, managing fuel oil and providing logistical support for the operation of our facilities (for example, by procuring transportation for coal). We typically sell the electricity we produce into the wholesale market at prices in effect at the time we produce it (the “spot price”).

Spot prices for electricity are volatile, as are prices for fuel and emissions allowances, and in order to reduce the risk of that volatility and achieve more predictable financial results, it is our strategy to enter into hedges—forward sales of electricity into the wholesale market and forward purchases of fuel and emissions allowances to allow us to produce and sell the electricity—for various time periods. In addition, given the high correlation between natural gas prices and electricity prices, we enter into forward sales of natural gas to hedge our exposure to changes in the price of electricity. We procure our hedges in OTC transactions or on exchanges where electricity, fuel and emissions allowances are broadly traded, or through specific transactions with buyers and sellers, using futures, forwards, swaps and options. We also sell capacity and ancillary services where there are markets for such products and when it is economic to do so. In addition to selling the electricity we produce and buying the fuel and emissions allowances we need to produce electricity (“asset management”), we buy and sell some electricity, fuel and emissions allowances as part of our proprietary trading and fuel oil management activities. Proprietary trading is a small part of our commercial operations. We engage in proprietary trading to gain information about the markets to support our asset management and to take advantage of selected opportunities that we identify from time to time. All of our commercial activities are governed by a comprehensive Risk Management Policy, which requires that our hedging activities with respect to our assets be risk-reducing and sets limits on the size of positions and VaR in our proprietary trading and fuel oil management activities.

We use dispatch models to assist us in making daily decisions regarding the quantity and price of the power our facilities will generate and sell into the markets. We bid the energy from our generating facilities into the day-ahead energy market and sell ancillary services through the ISO markets. We sell capacity either bilaterally or through auction processes in each ISO in which we participate. We work with the ISOs and RTOs in real time to ensure that our generating facilities are dispatched economically to meet the reliability needs of the market.

We economically hedge a substantial portion of our Mid-Atlantic coal-fired baseload generation and certain of our Northeast coal, gas and oil-fired generation through OTC transactions. A significant portion of our hedges are financial swap transactions that are senior unsecured obligations of Mirant Mid-Atlantic and do not require the posting of cash collateral either for initial margin or for securing exposure as a result of changes in power or natural gas prices. However, we generally do not hedge our intermediate and peaking units for tenors greater than 12 months. At February 25, 2008, we were economically hedged as follows:


	Aggregate Hedge Levels Based on Expected Generation
	2008		2009		2010		2011		2012
Power	98	%	53	%	38	%	21	%	20	%
Fuel	95	%	79	%	31	%	29	%	5	%
SO2/NOx	100	%	100	%	100	%	100	%	100	%

Our commercial operations manage the acquisition and utilization of emissions allowances for our generating facilities. Primarily as a result of the pollution control equipment we are installing to comply with the requirements of the Maryland Healthy Air Act, we anticipate that we will 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. We sold approximately $24 million of excess emissions allowances and recognized a gain of $22 million, which is included in gain on sales of assets in the consolidated statement of operations for the year ended December 31, 2007. At December 31, 2007, the estimated fair value of our excess emissions allowances exceeded the carrying value recorded on our consolidated balance sheet by approximately $200 million.

While OTC transactions make up a substantial portion of our economic hedge portfolio, at times we sell non-standard, structured products to customers. Additionally, our California facilities operate under long-term contracted capacity and RMR contracts.

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 2012. Our hedged percentages for fuel include transactions for which commercial terms have been negotiated but for which contracts have not yet been executed. Individual transactions may or may not be binding prior to execution of a contract. For our gas-fired units, we typically purchase fuel under short-term contracts with a variety of suppliers on a day-ahead or monthly basis.

Our coal supply comes primarily from the Central Appalachian and Northern Appalachian coal regions. All of our coal is delivered by rail; however, we are in the process of constructing a barge unloading facility at our Morgantown station that is expected to become operational in the third quarter of 2008. The barge unloader will enable us to receive coal from international locations as well. We monitor coal supply and delivery logistics carefully and, despite occasional interruptions of scheduled deliveries, to date we have managed to avoid any significant effects on our operations. We maintain an inventory of coal at our coal-fired facilities for this purpose. Interruptions of scheduled deliveries can result from a variety of disruptions, including strikes, rail system disruptions or severe weather.

Mid-Atlantic Region

We own or lease four generating facilities in the Mid-Atlantic region with total net generating capacity of 5,244 MW. Our Mid-Atlantic region had a combined 2007 net capacity factor of 37%.

Power generated by our Mid-Atlantic facilities is sold into the PJM market. For a discussion of the PJM market, see “Regulatory Environment” below. We have participated in standard offer service auctions in Maryland and Washington, D.C. Power sales, either directly through these auctions or indirectly through subsequent market transactions that are a result of the auction process, serve as economic hedges for the Mid-Atlantic facilities.

The following table presents the details of our Mid-Atlantic generating facilities:


Facility	Total Net Generating Capacity (MW)	Primary Fuel Type	Dispatch Type	Location	NERC Region
Chalk Point	2,417	Natural Gas/Coal/Oil	Intermediate/ Baseload/Peaking	Maryland	MAAC

Morgantown	1,492	Coal/Oil	Baseload/Peaking	Maryland	MAAC

Dickerson	853	Natural Gas/Coal/Oil	Baseload/Peaking	Maryland	MAAC

Potomac River	482	Coal	Intermediate/ Baseload	Virginia	MAAC


Total Mid-Atlantic	5,244

The Chalk Point facility is our largest generating facility. It consists of two coal-fired baseload units, two dual-fueled (oil and gas) intermediate units and two oil-fired and five dual-fueled (oil and gas) peaking units. Our next largest facility is the Morgantown facility. It consists of two dual-fueled (coal and oil) baseload units and six oil-fired peaking units. The Dickerson facility has three coal-fired baseload units, and one oil-fired and two dual-fueled (oil and gas) peaking units. The Potomac River station has three coal-fired baseload units and two coal-fired intermediate units.

On May 23, 2007, the Virginia State Air Pollution Control Board directed the Virginia DEQ to issue a state operating permit (the “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. We think these limits and constraints are unreasonable and arbitrary. 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. The Virginia State Air Pollution Control Board stated that the Permit is intended to be supplanted by a more comprehensive permit that it expects to issue. On October 19, 2007, the Virginia DEQ published a draft of this more comprehensive permit to solicit comments from the public. If adopted as proposed, this comprehensive permit would also impose stringent limits on SO2 emissions that would continue to limit Mirant Potomac River to operating no more than three of the five units of the Potomac River generating facility at any one time. On November 30, 2007, the Virginia State Air Pollution Control Board directed the Virginia DEQ to develop an alternative state operating permit that would require completion of a proposed project to merge the stacks of certain of the units at the Potomac River facility, set a single SO2 emissions limit 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. If approved as currently drafted with some minor modifications, this alternative state operating permit would enable Mirant Potomac River to operate all five units of the facility at one time. We anticipate that the Virginia State Air Pollution Control Board will consider the proposed permit in March 2008.

Northeast Region

We own generating facilities in the Northeast region with total net generating capacity of 2,689 MW. Our Northeast region had a combined 2007 net capacity factor of 22%. The Northeast region is comprised of our facilities located in New York and New England. Generation is sold from our Northeast facilities through a combination of bilateral contracts, spot market transactions and structured transactions.

The following table presents the details of our facilities in the Northeast Region:


Facility	Total Net Generating Capacity (MW)	Primary Fuel Type	Dispatch Type	Location	NERC Region
Bowline	1,124	Natural Gas/Oil	Intermediate/ Peaking	New York	NPCC

Lovett	183	Natural Gas/Coal	Baseload	New York	NPCC

Canal	1,112	Natural Gas/Oil	Intermediate	Massachusetts	NPCC

Kendall	256	Natural Gas/Oil/Jet Fuel	Baseload/Peaking	Massachusetts	NPCC

Martha’s Vineyard	14	Diesel	Peaking	Massachusetts	NPCC


Total Northeast Region	2,689

New York. The capacity, energy and ancillary services from our New York generating facilities are sold into the bilateral markets and into the markets administered by the NYISO. For a discussion of NYISO, see “Regulatory Environment” below.

The New York generating facilities consist of the Bowline and Lovett facilities. The Bowline facility is a dual-fueled (natural gas and oil) facility comprised of two intermediate/peaking units. The Lovett facility consists of one baseload unit capable of burning coal and gas.

Significant developments related to these generating facilities in 2007 were as follows:

•

On January 26, 2007, Mirant New York, Mirant Bowline (which owns the Bowline facility) and Hudson Valley Gas (collectively the “Emerging New York Entities”) filed their Supplemental Joint Chapter 11 Plan of Reorganization with the Bankruptcy Court and subsequently filed amendments to that plan (as subsequently amended, the “Supplemental Plan”). The Supplemental Plan was confirmed by the Bankruptcy Court on March 23, 2007, and became effective on April 16, 2007.

•

In the second quarter of 2007, we shut down units 3 and 4 at the Lovett facility. On October 20, 2007, Mirant Lovett submitted notices of its intent to discontinue operation of unit 5 at 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.

•

On July 13, 2007, Mirant Lovett (which owns the Lovett facility) filed a plan of reorganization (the “Mirant Lovett Plan”) with the Bankruptcy Court. The Mirant Lovett Plan was confirmed by the Bankruptcy Court on September 19, 2007, and became effective on October 2, 2007. As a result of Mirant Lovett’s emergence from bankruptcy, we do not have any subsidiaries remaining in bankruptcy. See Note 12 to our consolidated financial statements contained elsewhere in this report for additional information regarding the emergence from bankruptcy of Mirant Lovett and the Emerging New York Entities.

New England. The Canal facility consists of one oil-fired intermediate unit and one dual-fueled (oil and gas) intermediate unit. The Kendall facility consists of one combined cycle dual-fueled (oil and gas) baseload unit, two 1,300 pound steam boilers and one simple cycle jet engine peaking unit. The Martha’s Vineyard facility consists of five diesel peaking units.

The capacity, energy and ancillary services from our New England generating units are sold into the NEPOOL bilateral markets and into the markets administered by the ISO-NE. For a discussion of the NEPOOL and the ISO-NE, see “Regulatory Environment” below.

California

We own three generating facilities in California with total net generating capacity of 2,347 MW. Our California facilities had a combined 2007 net capacity factor of 4%. The following table presents the details of our California facilities:


Facility	Total Net Generating Capacity (MW)	Primary Fuel Type	Dispatch Type	Location	NERC Region

Pittsburg	1,311	Natural Gas	Intermediate	California	WECC

Contra Costa	674	Natural Gas	Intermediate	California	WECC

Potrero	362	Natural Gas/Oil	Intermediate/ Peaking	California	WECC


Total California	2,347

The Pittsburg and Contra Costa facilities are located in Contra Costa County and the Potrero facility is located in the City of San Francisco. Through the end of 2006, the majority of our California units were subject to RMR arrangements with the CAISO. These agreements are described further under “Regulatory Environment” below. Pittsburg unit 7 and Contra Costa unit 6 were not subject to an RMR arrangement, and thus functioned solely as merchant facilities in the CAISO. In 2006, we either sold the output of Pittsburg unit 7 and Contra

Costa unit 6 into the market through bilateral transactions with utilities and other merchant generators, or dispatched the units in the CAISO clearing markets.

On July 28, 2006, we signed two tolling agreements with PG&E to provide electricity from all our natural gas-fired units in service at Pittsburg and Contra Costa, including Pittsburg unit 7 and Contra Costa unit 6. The agreements are for 100% of the capacity from these units. The contracts have varying tenors for each unit covering from one to five years, and include capacity of 1,985 MW for 2008 and 2009, 1,303 MW for 2010 and 674 MW for 2011. The contracted capacity for 2007 was 1,985 MW. We receive monthly capacity payments with bonuses and/or penalties based on guaranteed heat rate and availability tolerances. As a result of these contracts, the Pittsburg and Contra Costa units are no longer subject to the RMR agreements. All of our Potrero units continue to be subject to RMR arrangements that continue through 2008 and are then renewable annually.

Competitive Environment

The power generating industry is capital intensive and highly competitive. Our competitors include regulated utilities, merchant energy companies, financial institutions and other companies, including companies owned by hedge funds and private equity funds. For a discussion of competitive factors and the effects of seasonality on our business see Item 1A. Risk Factors. Coal-fired generation, natural gas-fired generation and nuclear generation currently account for approximately 48%, 22% and 19%, respectively, of the electricity produced in the United States. Hydroelectric and other energy sources account for the remaining 11% of electricity produced.

While the demand for electricity is increasing, supply has not appreciably increased. Given the substantial time necessary to permit and construct new power plants, we think that the markets in which we operate need to begin the process now of adding generating capacity to meet growing demand. A number of ISOs, including those in markets in which we operate, have implemented capacity markets as a way to encourage such construction of additional generation, but it is not clear whether and when independent power producers will be sufficiently incented to build this required new generation.

Falling reserve margins, as well as high electricity prices as a result of high natural gas prices, have led to renewed interest in new coal-fired or nuclear plants. However, the costs to construct new generation facilities are rising and there is substantial environmental opposition to building either coal-fired or nuclear plants.

Regulatory Environment

The electricity industry is subject to comprehensive regulation at the federal, state and local levels. At the federal level, the FERC has exclusive jurisdiction under the Federal Power Act over sales of electricity at wholesale and the transmission of electricity in interstate commerce. Each of our subsidiaries that owns a generating facility selling at wholesale or that markets electricity at wholesale is a “public utility” subject to the FERC’s jurisdiction under the Federal Power Act. These subsidiaries must comply with certain FERC reporting requirements and FERC-approved market rules and are subject to FERC oversight of mergers and acquisitions, the disposition of FERC-jurisdictional facilities and the issuance of securities. In addition, under the Natural Gas Act, the FERC has limited jurisdiction over certain resales of natural gas, but does not regulate the prices received by our subsidiary, Mirant Energy Trading, that markets natural gas.

The FERC has authorized our subsidiaries that constitute public utilities under the Federal Power Act to sell energy, capacity and certain ancillary services for wholesale at market based rates. The majority of the output of the generating facilities owned by our subsidiaries is sold pursuant to this authorization, although certain of our facilities sell their output under cost based RMR agreements, as explained below. The FERC may revoke or limit our market based rate authority if it determines that we possess undue market power in a regional electricity market. Under the Natural Gas Act, our subsidiary that sells natural gas for resale is deemed by the FERC to have blanket certificate authority to undertake these sales at market based rates. The FERC requires that our public

utility subsidiaries with market based rate authority, as well as the subsidiary deemed to have blanket certificate authority to sell natural gas, adhere to certain market behavior rules and codes of conduct, respectively. If any of our subsidiaries violates the market behavior rules or codes of conduct, the FERC may require a disgorgement of profits or revoke its market based rate authority or blanket certificate authority. If the FERC were to revoke market based rate authority, our affected public utility subsidiary would have to file a cost based rate schedule for all or some of its sales of electricity at wholesale. If the FERC revoked the blanket certificate authority of any of our subsidiaries, certain sales of natural gas would be prohibited.

Our facilities operate in ISO/RTO markets. In areas where ISOs or RTOs control the regional transmission systems, market participants have access to broader geographic markets compared to regions without ISOs and RTOs. ISOs operate real-time and day-ahead energy and ancillary services markets, typically governed by FERC-approved tariffs and market rules. Some ISOs and RTOs also operate capacity markets. Changes to the applicable tariffs and market rules may be requested by market participants, state regulatory agencies and the system operator, and such proposed changes, if approved by the FERC, could have a significant effect on our operations and business plan. While participation by transmission-owning public utilities in ISOs and RTOs has been and is expected to continue to be voluntary, the majority of such public utilities in New England, New York, the Mid-Atlantic and California have joined the applicable ISO/RTO.

Our subsidiaries owning generating facilities were exempt wholesale generators under the PUHCA, as amended. With the repeal of the PUHCA and the adoption of the Public Utility Holding Company Act of 2005, the FERC adopted new regulations effective February 8, 2006, that allow our subsidiaries owning generating facilities to retain their exempt wholesale generator status.

State and local regulatory authorities have historically overseen the distribution and sale of electricity at retail to the ultimate end user, as well as the siting, permitting and construction of generating and transmission facilities. Our existing generating facilities are subject to a variety of state and local regulations, including regulations regarding the environment, health and safety, maintenance and expansion of the facilities.

Mid-Atlantic Region. Our Mid-Atlantic facilities sell electricity into the markets operated by PJM, which the FERC approved to operate as an ISO in 1997 and as an RTO in 2002. We have access to the PJM transmission system pursuant to PJM’s Open Access Transmission Tariff. PJM operates the PJM Interchange Energy Market, which is the region’s spot market for wholesale electricity, provides ancillary services for its transmission customers, performs transmission planning for the region and economically dispatches generating facilities. PJM administers day-ahead and real-time single clearing price markets and calculates electricity prices based on a locational marginal pricing model. A locational marginal pricing model determines a price for energy at each node in a particular zone taking into account the limitations on transmission of electricity and losses involved in transmitting energy into the zone, resulting in a higher zonal price when less expensive energy cannot be imported from another zone. Generation owners in PJM are subject to mitigation, which limits the prices that they may receive under certain specified conditions.

Load-serving entities within PJM are required to have adequate sources of generating capacity. Our facilities located in the Mid-Atlantic region that sell electricity into the PJM market participate in the reliability pricing model (the “RPM”) forward capacity market. The RPM capacity auctions are designed to provide forward prices for capacity that are intended to ensure that adequate resources are in place to meet the region’s demand requirements. PJM has conducted four RPM capacity auctions and we began receiving payments in June 2007 as a result of the first auction. The FERC’s orders approving and implementing the PJM RPM capacity auctions are pending review with the United States Court of Appeals. We cannot predict what, if any, effect the appeal process will have on the RPM forward capacity market and the capacity payments that we receive from that market.

The results of the PJM RPM capacity auctions for the delivery area where our facilities are located were as follows:


Auction Date	Capacity Period	Resource Clearing Price per MW-day
April 2007	June 1, 2007 to May 31, 2008	$	188.54
July 2007	June 1, 2008 to May 31, 2009	$	210.11
October 2007	June 1, 2009 to May 31, 2010	$	237.33
January 2008	June 1, 2010 to May 31, 2011	$	174.29

Hereafter, annual auctions will be conducted to procure capacity three years prior to each delivery period. The first such auction will take place in May 2008, for the provision of capacity from June 1, 2011 to May 31, 2012.

In addition, PJM and the MISO have been directed by the FERC to establish a common and seamless market. The development of a joint market is contingent on the approval of the internal costs to both entities to develop and operate the infrastructure necessary for joint operations. It is unclear at this time if either the respective entities or the FERC will approve such costs to achieve a common and seamless market.

Northeast Region. Our New York facilities participate in a market controlled by the NYISO, which replaced the New York Power Pool. The NYISO provides statewide transmission service under a single tariff and interfaces with neighboring market control areas. To account for transmission congestion and losses, the NYISO calculates energy prices using a locational marginal pricing model. The NYISO also administers a spot market for energy, as well as markets for installed capacity and services that are ancillary to transmission service, such as operating reserves and regulation service (which balances resources with load). The NYISO’s locational capacity market rules use a demand curve mechanism to determine for every month the required amount of installed capacity as well as installed capacity prices to be paid for three locational zones: New York City, Long Island and Rest of State. Our facilities operate in the Rest of State locational zone. On April 21, 2005, the FERC issued an order accepting the NYISO’s demand curves for 2005/2006, 2006/2007 and 2007/2008 with minor modifications to the NYISO’s proposal. On November 20, 2007, the NYISO filed demand curves for 2008/2009, 2009/2010 and 2010/2011. On January 29, 2008, the FERC issued an order accepting the NYISO’s proposal without modification. The demand curves approved by the FERC may result in increased prices within the NYISO for capacity in those years.

Our New England facilities participate in a market administered by ISO-NE. Mirant Energy Trading is a member of NEPOOL, which is a voluntary association of electric utilities and other market participants in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont, and which functions as an advisory organization to ISO-NE. The FERC approved ISO-NE as the RTO for the New England region effective on February 1, 2005, making ISO-NE responsible for market rule filings at the FERC, in addition to its responsibilities for the operation of transmission systems and administration and settlement of the wholesale electric energy, capacity and ancillary services markets. ISO-NE utilizes a locational marginal pricing model similar to that used in PJM and NYISO.

On March 6, 2006, a settlement proposal was filed with the FERC among ISO-NE and multiple market participants for a forward capacity market (the “FCM”) under which annual capacity auctions would be conducted for supply three years in advance of provision. The settlement provided for a four-year transition period during which capacity suppliers receive a set price for their capacity commencing on December 1, 2006, and continuing with price escalators through May 31, 2010. The first auction took place in February 2008 for the period June 1, 2010 to May 31, 2011. The clearing price was $4.50 per kW-month, which was the price floor established as part of the FCM settlement. Our generating facilities will receive $4.50 per kW-month based on our pro-rata amount of the generation that was sold in the auction. The next auction for the period June 1, 2011 to May 31, 2012, will be held in December 2008. Beginning December 1, 2006, our generating facilities began

receiving capacity revenues under the FCM transition period. The FERC’s orders approving and implementing the FCM are pending review with the United States Court of Appeals. We cannot predict what, if any, effect the appeal process will have on the FCM and the capacity payments we receive under the FCM.

California. Our California facilities are located inside the CAISO’s control area. The CAISO schedules transmission transactions, arranges for necessary ancillary services and administers a real-time balancing energy market. Most sales in California are pursuant to bilateral contracts, but a significant percentage of electrical energy is sold in the real-time market. The CAISO does not operate a forward market like those described for PJM and other eastern ISO markets, nor does it currently operate a capacity market.

Mirant Potrero is party to a PPA with PG&E that from 2006 through 2012 allows PG&E to dispatch and purchase the power output of our Potrero units that have been designated RMR units which for 2008 includes all of the Potrero units. Under the PPA, through 2008, PG&E is paying us charges equivalent to the rates we charged during 2004 when the units were designated RMR Contract Condition 2 reduced by $1.4 million for each year since 2004. For 2009 through 2012, the charges for the units that are then subject to the PPA will be determined annually by the FERC pursuant to the cost based formula rates set forth in the RMR agreement.

The CAISO has proposed changes to its market design to mirror more closely the eastern ISO markets, but not including a capacity market. Although the CAISO has delayed the market redesign several times, it now expects to fully implement it in 2008. The CPUC has begun a proceeding to develop, together with the CAISO, a wholesale capacity market. FERC approval would be required for any such capacity market to become effective. We cannot at this time predict the outcome of the CPUC proceeding or the timing or structure of a wholesale capacity market in California.

Environmental Regulation

Our business is subject to extensive environmental regulation by federal, state and local authorities. We must comply with applicable laws and regulations, and obtain and comply with the terms of government issued permits. Our costs of complying with environmental laws, regulations and permits are substantial, including significant environmental capital expenditures.

The following table details our estimated environmental capital expenditures, excluding capitalized interest (in millions):


	2008		2009		2010
Maryland Healthy Air Act	$	689	$	286	$	125
Other environmental		63		35		28

Total environmental capital expenditures	$	752	$	321	$	153

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

Air Emissions Regulations

Our most significant environmental requirements generally fall under the Clean Air Act and similar state laws. Under the Clean Air Act, we are required to comply with a broad range of mandates concerning air emissions, operating practices and pollution control equipment. Most of our facilities are located in or near metropolitan areas, including New York City, Boston, San Francisco and Washington D.C., which are classified by the EPA as not achieving certain NAAQS. As a result of the NAAQS classification of these areas, our operations are subject to more stringent air pollution requirements than applicable to plants located elsewhere. Various states where we have facilities also have other air quality laws and regulations with increasingly

stringent limitations and requirements that will become effective in future years for our facilities and operations. In the future, we expect increased regulation of our air emissions. Significant air regulatory programs to which we are subject are described below.

Clean Air Interstate Rule (CAIR). In 2005, the EPA promulgated the CAIR, which established in the eastern United States an SO2 and NOx cap-and-allowance trading program applicable directly to states and indirectly to generating facilities. These cap-and-trade programs will 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. We are installing pollution control equipment at certain of our coal-fired facilities in Maryland to address the requirements under the Maryland Healthy Air Act, which will also enable us to satisfy the requirements of the first phase of the CAIR without purchasing additional allowances. The costs of that equipment are included in our estimate of anticipated environmental capital expenditures from 2008 through 2010.

Maryland Healthy Air Act. The Maryland Healthy Air Act was enacted in April 2006 and requires reductions in NOx, SO2 and mercury emissions from large coal-fired power facilities. The state law also requires Maryland to join the Regional Greenhouse Gas Initiative (the “RGGI”), which is discussed below. On August 3, 2006, we announced a plan to comply with the requirements of the Maryland Healthy Air Act by reducing SO2 emissions by as much as 95% at our Maryland power facilities. The Maryland Healthy Air Act prohibits power facilities from purchasing emissions allowances instead of installing pollution control equipment. We are installing flue gas desulphurization (“FGD”) emissions controls at our Chalk Point, Dickerson and Morgantown coal-fired units. In addition, we are installing selective catalytic reduction (“SCR”) systems at the Morgantown and Chalk Point coal-fired units, which will reduce NOx emissions by approximately 80%. Together, the FGDs and the SCRs will reduce the emissions of ionic mercury from the three Maryland power facilities.

The Maryland Healthy Air Act imposes tonnage limits for (i) emissions of NOx in 2009 with further reductions in 2012 (including sublimits during the Ozone Season) and (ii) emissions of SO2 in 2010 with further reductions in 2013. The Maryland Healthy Air Act also imposes restrictions on emissions of mercury beginning in 2010 with further reductions in 2013. The control equipment we plan to install to meet Maryland state standards will allow our Maryland facilities to comply with the first phase of the CAIR without having to purchase allowances.

We expect to incur total capital expenditures of $1.6 billion through the first quarter of 2010 to comply with the requirements for SO2 and NOx emissions under the Maryland Healthy Air Act. On July 30, 2007, our indirect subsidiaries Mirant Mid-Atlantic and Mirant Chalk Point entered into an agreement with Stone & Webster, Inc. for engineering, procurement and construction services relating to the installation of air quality control systems at the Morgantown, Dickerson and Chalk Point coal-fired units. The expected cost under the agreement is approximately $1.1 billion and is a part of the capital expenditures that we expect to incur to comply with the Maryland Healthy Air Act. We will have extended planned outages during equipment installation. During those outages, we also will perform routine maintenance activities. As of December 31, 2007, we have paid approximately $500 million for capital expenditures related to the Maryland Healthy Air Act.

Clean Air Mercury Rule (CAMR). In 2005, the EPA issued the CAMR, which would have limited total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program. The first phase was to have begun in 2010 and the second phase was to have begun in 2018. On February 8, 2008, The United States Court of Appeals for the District of Columbia Circuit (the “DC Circuit”) issued its opinion vacating and remanding two rules regarding mercury emissions from Electric Generating Units (“EGUs”). First, the DC Circuit’s opinion vacated the rule by which the EPA removed EGUs from the list of sources with emissions of hazardous air pollutants subject to regulation under section 112 of the Clean Air Act which requires maximum achievable control standards. Second, the DC Circuit’s opinion vacated the EPA’s CAMR. At this time, we cannot predict the EPA’s action on remand. We expect many of our coal-fired facilities to emit less mercury as a result of the NOx and SO2 controls that are, or will soon be, installed.

NSR Enforcement Initiative. In 2001, the EPA requested information concerning some of our facilities in Maryland and Virginia covering a time period that pre-dates our acquisition or lease of those facilities in December 2000. We responded fully to this request. Under the APSA, Pepco is responsible for fines and penalties arising from any violation associated with operations prior to our subsidiaries’ acquisition or lease of the facilities. If a violation is determined to have occurred at any of the facilities, our subsidiary owning or leasing the facilities may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. Our subsidiaries owning or leasing the Chalk Point, Dickerson and Morgantown facilities in Maryland are installing a variety of emissions control equipment on those facilities to comply with the Maryland Healthy Air Act, but that equipment may not include all of the pollution 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 our subsidiaries acquired or leased the facilities or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, our subsidiary owning or leasing the facility at issue 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, 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 us and our subsidiaries that own or lease these facilities.

Massachusetts CAIR Implementation. The Commonwealth of Massachusetts Department of Environmental Protection promulgated regulations to take effect in 2009 to implement the requirements under the federal CAIR 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 what are currently utilized.

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, the regulations 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 implement an SO2 emissions program beginning in 2010 that mandates increased utilization of federal SO2 allowances for every ton of SO2 emitted.

Virginia CAIR Implementation. In April 2006, Virginia enacted legislation, which 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 NAAQ standard (“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. The only generating facility in Virginia currently affected is our Potomac River facility which is located in a non-attainment area for ozone and PM2.5. Mirant Potomac River has appealed these regulations in Virginia State Court. We have also petitioned (a) the EPA to reconsider and (b) the United States Court of Appeals for the Fourth Circuit to review the EPA’s final rule approving Virginia’s CAIR program. Application of these regulations, if not modified or waived, will reduce our flexibility in complying with the CAIR in Virginia beginning in 2009 and could result in operating restrictions for our Potomac River generating facility.

Massachusetts Emissions Standards for Power Plants. The Commonwealth of Massachusetts Department of Environmental Protection promulgated regulations affecting certain generating facilities, including our Canal facility, that established emissions output limits beginning in 2006 for NOx and SO2 and beginning in 2008 for CO2 and an annual cap on CO2 emissions beginning in 2008. We are achieving compliance with the NOx and SO2 emissions limits by utilizing lower sulfur fuels and natural gas and by optimizing the operation of our unit with selective catalytic reduction capability. Under our current operating profile, we are in compliance with the output limit on CO2, and we plan to comply with the annual CO2 cap by purchasing offsets or by making payments into a newly-established Greenhouse Gas Expendable Trust, which is expected to be finalized during the first quarter of 2008.

New York Consent Decree. In 2000, the State of New York issued an NOV to the previous owner of our Lovett facility alleging NSR violations associated with the operation of that facility prior to its acquisition by us. 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 has three options: (1) install emissions controls on Lovett’s two coal-fired units; (2) shut down unit 5 and convert unit 4 to natural gas; or (3) shut down both coal-fired units in 2007 and 2008. We have concluded that the installation of the required emissions controls is 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. The 2003 Consent Decree imposed similar requirements with respect to unit 4 that had to be met by April 30, 2008.

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. Unit 4 discontinued operation as of May 7, 2007. In addition, unit 3 discontinued operation because it was uneconomic for the unit to continue to run.

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. Barring a new agreement with the State of New York, unit 5 will shut down as required under the amendment to the 2003 Consent Decree.

State Regulation of Greenhouse Gases, including the Regional Green House Gas Initiative (RGGI). Concern over climate change has led to significant legislative and regulatory efforts at the state 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. In August 2006, seven states including New York signed the RGGI Memorandum of Understanding (“MOU”), which puts forth a model set of regulations to guide the states in structuring their individual programs. Both Massachusetts and Maryland joined the RGGI in 2007. Our generating facilities in Maryland, Massachusetts and New York will be affected by the implementation of the RGGI. In August 2007, the Massachusetts Department of Environmental Protection and the Massachusetts Department of Energy Resources proposed regulations to implement the RGGI. In October 2007, the NYSDEC and the New York State Energy Research and Development Authority issued proposed regulations to implement the RGGI. In January 2008, the MDE issued for public comment proposed regulations to implement the RGGI. The proposed Maryland regulations include a mechanism such that in the event of carbon credit prices exceeding $7 per ton, we and other Maryland generators will have the option to purchase up to 50% of our needs at $7 per ton regardless of auction clearing prices.

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. If adopted in their current form, the proposed and draft RGGI regulations would require those facilities to obtain allowances to emit CO2. No allowances would be granted to existing sources of such emissions. Instead, allowances would be made available for such facilities only by purchase through an auction process conducted regionally or through subsequent purchase from a party that held the allowances that had been sold through the auction. We and a number of other parties have submitted comments on the proposed regulations in Massachusetts and New York, and we expect to comment on the proposed rules to be issued in Maryland. The final form and timing of the regulations in each state are uncertain. 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 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. That plan could have a material effect on how we operate our California facilities and the costs of operating the facilities.

Federal Regulation of Greenhouse Gases. At the federal level, various bills have been proposed to govern CO2 emissions from generating facilities. We do not know how any law, if ultimately enacted, would affect the state laws and regulations described. We expect that any federal law governing CO2 emissions would significantly affect our generating facilities.

Water Regulations

We are required under the Clean Water Act to comply with intake and discharge requirements, requirements for technological controls and operating practices. To discharge water, we must have permits under the Clean Water Act. Such permits typically are subject to review every five years. As with air quality regulations, federal and state water regulations are expected to impose additional and more stringent requirements or limitations in the future. This is particularly the case for regulatory requirements governing cooling water intake structures, which are subject to regulation under section 316(b) of the Clean Water Act. A 2007 decision by the United States Court of Appeals for the Second Circuit in Riverkeeper Inc. et al v. EPA, in which the court remanded to the EPA for reconsideration numerous provisions of the EPA’s section 316(b) regulations for existing power plants, has created substantial uncertainty about exactly what technologies or other measures will be needed to satisfy section 316(b) requirements in the future and when any new requirements will be imposed.

Endangered Species Acts. Mirant Delta’s use of water from the Sacramento-San Joaquin Delta at its Contra Costa and Pittsburg generating facilities potentially affects certain fish species protected under the Federal Endangered Species Act and the California Endangered Species Act. Mirant Delta therefore must maintain authorization under both statutes to engage in operations that could result in a take of (i.e., harm to) fish of the protected species. In January and February 2006, Mirant Delta received correspondence from the U.S. Fish and Wildlife Service and the Army Corps of Engineers expressing the view that the Federal Endangered Species Act take authorization for the Contra Costa and Pittsburg facilities was no longer in effect due to changed circumstances. Mirant Delta disagreed with the agencies’ characterization of its take authorization as no longer being in effect. 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 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.

Mirant and Mirant Delta 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 the take authorizations, 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 U.S. 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, Mirant Delta received the correspondence described above from the U.S. Fish and Wildlife Service, the National Marine Fisheries Service and the Army Corps of Engineers clarifying that Mirant Delta continues to be authorized to take the four species of fish protected under the federal Endangered Species Act. 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.

Additionally, in September 2007, Mirant Delta signed an amendment to a Memorandum of Agreement with the California Department of Fish and Game. The amendment requires Mirant Delta to initiate monitoring of the effects on fish of the operations of the Pittsburg and Contra Costa facilities, to prepare an environmental impact report, and to submit within 24 months an application for a new permit authorizing Mirant Delta to take the protected fish species affected by the operation of its facilities. The amendment extends Mirant Delta’s authorization for take of fish species protected under the California Endangered Species Act until the California Department of Fish and Game completes its consideration of the application for the new permit.

National Pollution Discharge Elimination System. On June 8, 2006, Bayview-Hunters Point Community Advocates and Communities for a Better Environment filed a petition challenging the issuance of the National Pollution Discharge Elimination System (“NPDES”) permit for our Potrero facility. On February 8, 2007, Bayview-Hunters Point Community Advocates and Communities for a Better Environment filed another petition with a request to amend their initial petition. On March 21, 2007, the California State Water Resources Control Board notified the parties that petitioners requested that as of March 19, 2007, the two petitions be moved from active status to abeyance. Those petitions currently remain in abeyance. Additionally, on June 15, 2007, Bayview-Hunters Point Community Advocates and Communities for a Better Environment and San Francisco Baykeeper filed a third petition requesting that the NPDES permits for Potrero and Mirant Delta’s Pittsburg facility be reopened. The State Water Resources Control Board denied that petition on November 27, 2007.

Kendall NPDES and Surface Water Discharge Permit. On September 26, 2006, the Massachusetts Department of Environmental Protection and the EPA jointly issued to Mirant Kendall a Surface Water Discharge Permit (“SWDP”), a water quality certificate and an NPDES permit for the Kendall generating facility. The new permits impose new temperature limits at various points in the Charles River, an extensive temperature, water quality and biological monitoring program and a requirement to develop and install a barrier net system to reduce fish impingement and entrainment. The provisions regulating the thermal discharge could cause substantial curtailments of the operations of the Kendall facility. Mirant Kendall has appealed the permits in three proceedings: (1) appeal of the NPDES permit to the Environmental Appeals Board; (2) appeal of the SWDP to the Massachusetts Department of Environmental Protection; and (3) appeal of the Water Quality Certification to the Massachusetts Department of Environmental Protection. The effect of the permits has been stayed pending the outcome of these appeals. The two appeals to the Massachusetts Department of Environmental Protection have been stayed pending the outcome of the appeal to the Environmental Appeals Board. On September 28, 2007, the Environmental Appeals Board stayed the appeal proceedings until April 18, 2008, in order for the EPA to address the sections of the permit that are affected by the EPA’s suspension of the 316(b) regulations as described above under “Water Regulations.” We are unable to predict the outcome of these proceedings.

Wastes, Hazardous Materials and Contamination

Our facilities are subject to laws and regulations governing waste management. The federal Resource Conservation and Recovery Act of 1976 contains comprehensive requirements for the handling of solid and hazardous wastes. The generation of electricity produces non-hazardous and hazardous materials, and we incur substantial costs to store and dispose of waste materials. The EPA and the states in which we operate coal-fired

units may develop new regulations that impose additional requirements on facilities that store or dispose of fossil fuel combustion materials, including types of coal ash. If so, we may be required to change the current waste management practices at some facilities and incur additional costs for increased waste management requirements. The MDE has proposed new regulations to govern the disposal of coal ash and we expect these regulations to become final in 2008. We do not expect any significant effect on the operations of our coal ash disposal facilities as a result of these new regulations.

Additionally, CERCLA, also known as the Superfund law, establishes a federal framework for dealing with the cleanup of contaminated sites. Many states have enacted similar state superfund statutes as well as other laws imposing obligations to investigate and clean up contamination. Our Pittsburg, Contra Costa and Potrero facilities have areas of soil and groundwater contamination subject to CERCLA and the California Health and Safety Code. Prior to our acquisition of those facilities from PG&E in 1998, PG&E conducted soil and groundwater investigations at those facilities which revealed contamination. The consultants conducting the investigation estimated the aggregate cleanup costs at those facilities could be as much as $60 million. Pursuant to the terms of the Purchase and Sale Agreement with PG&E, PG&E has responsibility for the containment or capping of all soil and groundwater contamination and the disposition of up to 60,000 cubic yards of contaminated soil from the Potrero generating facility and the remediation of any groundwater or solid contamination identified at the Pittsburg and Contra Costa generating facilities, in each case with respect to contamination existing at those facilities in 1999 when they were purchased by our subsidiaries. Pursuant to our requests, PG&E has disposed of 807 cubic yards of contaminated soil from the Potrero generating facility. We are not aware of soil or groundwater conditions for which we expect remediation costs to be material that are not the responsibility of other parties.

Employees

At December 31, 2007, we employed 1,740 people, which included approximately 1,175 employees at our generating facilities, 70 employees at our regional offices and 495 employees at our corporate headquarters in Atlanta, Georgia. The following details the employees subject to collective bargaining agreements:


Union	Location	Number of Employees Covered	Contract Expiration Date
Mid-Atlantic Region
IBEW Local 1900	Maryland and Virginia	503	6/1/2010

Northeast Region
IBEW Local 503	New York	122	6/1/2008
UWUA Local 369	Cambridge, Massachusetts	33	2/28/2009
UWUA Local 480	Sandwich, Massachusetts	51	6/1/2011

California
IBEW Local 1245	California	124	10/31/2008


Total		833

Item 1A.

Risk Factors

The following are factors that could affect our future performance:

Our revenues are unpredictable because most of our facilities operate without long-term power sales agreements, and our revenues and results of operations depend on market and competitive forces that are beyond our control.

We sell capacity, energy and ancillary services from most of our generating facilities into competitive power markets on a short-term fixed price basis or through power sales agreements. Since mid-2007, our revenues from selling capacity have become a significant part of our overall revenues. We are not guaranteed recovery of our costs or any return on our capital investments through mandated rates. The market for wholesale electric energy and energy services reflects various market conditions beyond our control, including the balance of supply and demand, the marginal and long run costs incurred by our competitors and the effect of market regulation. Being concentrated in a few geographic markets results in concentrated exposure to those markets, especially PJM. The price for which we can sell our output may fluctuate on a day-to-day basis. The markets in which we compete remain subject to one or more forms of regulation that limit our ability to raise prices during periods of shortage to the degree that would occur in a fully deregulated market and may thereby limit our ability to recover costs and an adequate return on our investment. Our revenues and results of operations are influenced by factors that are beyond our control, including:

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the failure of market regulators to develop and maintain efficient mechanisms to compensate merchant generators for the value of providing capacity needed to meet demand;

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actions by regulators, ISOs, RTOs and other bodies that may prevent capacity and energy prices from rising to the level necessary for recovery of our costs, our investment and an adequate return on our investment;

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

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the possibility that appellate courts considering the pending appeals of the FERC’s rulings that approved the RPM and FCM tariffs do not affirm the FERC’s approval of those tariffs, resulting in modifications to the capacity payments made under those tariffs in the future and possibly refunds for past periods;

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the ability of wholesale purchasers of power to make timely payment for energy or capacity, which may be adversely affected by factors such as retail rate caps, refusals by regulators to allow utilities to recover fully their wholesale power costs and investments through rates, catastrophic losses and losses from investments by utilities in unregulated businesses;

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the fact that increases in prevailing market prices for fuel oil, coal, natural gas and emissions allowances may not be reflected in prices we receive for sales of energy;

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increases in supplies due to actions of our current competitors or new market entrants, including the development of new generating facilities or alternative energy sources that may be able to produce electricity less expensively than our generating facilities and improvements in transmission that allow additional supply to reach our markets;

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decreases in energy consumption resulting from demand-side management programs such as automated demand response, which may alter the amount and timing of consumer energy use;

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the competitive advantages of certain competitors including continued operation of older power plants in strategic locations after recovery of historic capital costs from ratepayers;

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existing or future regulation of our markets by the FERC, ISOs and RTOs, including any price limitations and other mechanisms to address some of the price volatility or illiquidity in these markets or the physical stability of the system;

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regulatory policies of state agencies that affect the willingness of our customers to enter into long-term contracts generally, and contracts for capacity in particular;

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weather conditions that depress demand or increase the supply of hydro power; and

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changes in the rate of growth in electricity usage as a result of such factors as national and regional economic conditions and implementation of conservation programs.

In addition, unlike most other commodities, electric energy can only be stored on a very limited basis and generally must be produced at the time of use. As a result, the wholesale power markets are subject to substantial price fluctuations over relatively short periods of time and can be unpredictable.

Changes in commodity prices may negatively affect our financial results by increasing the cost of producing power or lowering the price at which we are able to sell our power.

Our generating business is subject to changes in power prices and fuel costs, and these commodity prices are influenced by many factors outside of our control, including weather, market liquidity, transmission and transportation inefficiencies, availability of competitively priced alternative energy sources, demand for energy commodities, production of natural gas, crude oil and coal, natural disasters, wars, embargoes and other catastrophic events, and federal, state and environmental regulation and legislation. Significant fluctuations in commodity prices may affect our financial results and financial position by increasing the cost of producing power and decreasing the amounts we receive from the sale of power.

Our use of derivative contracts in our asset management activities will not fully protect us from fluctuations in commodity prices and our risk management policy cannot eliminate the risks associated with these activities.

We engage in asset management activities related to sales of electricity and purchases of fuel. The income and losses from these activities are recorded as operating revenues and fuel costs. We may use forward contracts and other derivative financial instruments to manage market risk and exposure to volatility in prices of electricity, coal, natural gas, emissions and oil. We cannot provide assurance that these strategies will be successful in managing our price risks, or that they will not result in net losses to us as a result of future volatility in electricity, fuel and emissions markets. Actual power prices and fuel costs may differ from our expectations.

Our asset management activities include natural gas derivative instruments that we use to hedge power prices for our baseload generation. The effectiveness of these hedges is dependent upon the correlation between power and natural gas prices in the markets where we operate. If those prices are not sufficiently correlated, our financial results and financial position could be adversely affected.

Additionally, we expect to have an open position in the market, within our established guidelines, resulting from the management of our portfolio. To the extent open positions exist, fluctuating commodity prices can affect our financial results and financial position, either favorably or unfavorably. Furthermore, the risk management procedures we have in place may not always be followed or may not always work as planned. Unauthorized hedging and related activities by our employees could result in significant penalties and financial losses. As a result of these and other factors, we cannot predict the outcome that risk management decisions may have on our businesses, operating results or financial position. Although management devotes a considerable amount of attention to these issues, their outcome is uncertain.

We are exposed to the risk of fuel and fuel transportation cost increases and volatility and interruption in fuel supply because our facilities generally do not have long-term agreements for the supply of natural gas, coal and oil.

Although we attempt to purchase fuel based on our expected fuel requirements, we still face the risks of supply interruptions and fuel price volatility. Our cost of fuel may not reflect changes in energy and fuel prices in part because we must pre-purchase inventories of coal and oil for reliability and dispatch requirements, and thus

the price of fuel may have been determined at an earlier date than the price of energy generated from it. The price we can obtain from the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel costs. This may have a material adverse effect on our financial performance. The volatility of fuel prices could adversely affect our financial results and operations.

Our asset management and proprietary trading activities may increase the volatility of our quarterly and annual financial results.

We engage in asset management activities to hedge economically our exposure to market risk with respect to: (1) electricity sales from our generating facilities; (2) fuel used by those facilities; and (3) emissions allowances. We generally attempt to balance our fixed-price purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. We also use derivative contracts with respect to our limited proprietary trading and fuel oil management activities, through which we attempt to achieve incremental returns by transacting where we have specific market expertise. Derivatives from our asset management and proprietary trading activities are recorded on our balance sheet at fair value pursuant to SFAS 133. None of our derivatives recorded at fair value are designated as hedges under SFAS 133 and changes in their fair values are therefore recognized currently in earnings as unrealized gains or losses. As a result, our financial results—including gross margin, operating income and balance sheet ratios—will, at times, be volatile and subject to fluctuations in value primarily due to changes in forward electricity and fuel prices. For a more detailed discussion of the accounting treatment of our asset management and proprietary trading activities, see Note 4 to our consolidated financial statements contained elsewhere in this report.

Operation of our generating facilities involves risks that may have a material adverse effect on our cash flows and results of operations.

The operation of our generating facilities involves various operating risks, including, but not limited to:

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the output and efficiency levels at which those generating facilities perform;

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interruptions in fuel supply;

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disruptions in the delivery of electricity;

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adverse zoning;

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breakdowns or equipment failures (whether due to age or otherwise);

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restrictions on emissions;

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violations of our permit requirements or changes in the terms of or revocation of permits;

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releases of pollutants and hazardous substances to air, soil, surface water or groundwater;

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shortages of equipment or spare parts;

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labor disputes;

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operator errors;

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curtailment of operations due to transmission constraints;

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failures in the electricity transmission system which may cause large energy blackouts;

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implementation of unproven technologies in connection with environmental improvements; and

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catastrophic events such as fires, explosions, floods, earthquakes, hurricanes or other similar occurrences.

A decrease in, or the elimination of, the revenues generated by our facilities or an increase in the costs of operating such facilities could materially affect our cash flows and results of operations, including cash flows available to us to make payments on our debt or our other obligations.

Our operating results are subject to quarterly and seasonal fluctuations.

Our operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including seasonal variations in demand and fuel prices.

We compete to sell energy and capacity in the wholesale power markets against some competitors that enjoy competitive advantages, including the ability to recover fixed costs through rate base mechanisms and a lower cost of capital.

Regulated utilities in the wholesale markets generally enjoy a lower cost of capital than we do and often are able to recover fixed costs through regulated retail rates including, in many cases, the costs of generation, allowing them to build, buy and upgrade generating facilities without relying exclusively on market clearing prices to recover their investments. The competitive advantages of such participants could adversely affect our ability to compete effectively and could have an adverse impact on the revenues generated by our facilities.

Our business and activities are subject to extensive environmental requirements and could be adversely affected by such requirements, including future changes to them.

Our business is subject to extensive environmental regulations promulgated by federal, state and local authorities, which, among other things, restrict the discharge of pollutants into the air, water and soil, and also govern the use of water from adjacent waterways. Such laws and regulations frequently require us to obtain operating permits and remain in continuous compliance with the conditions established by those operating permits. To comply with these legal requirements and the terms of our operating permits, we must spend significant sums on environmental monitoring, pollution control equipment and emissions allowances. If we were to fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. We may be required to shut down facilities if we are unable to comply with the requirements, or if we determine the expenditures required to comply are uneconomic.

From time to time we may not be able to obtain necessary environmental regulatory approvals. Such approvals could be delayed or subject to onerous conditions. If there is a delay in obtaining environmental regulatory approval or if onerous conditions are imposed, the operation of our generating facilities or the sale of electricity to third parties could be prevented or become subject to additional costs. Such delays or onerous conditions could have a material adverse effect on our financial performance and condition.

In addition, environmental laws, particularly with respect to air emissions, wastewater discharge and cooling water systems, are generally becoming more stringent, which may require us to make expensive facility upgrades or restrict our operations. With the trend toward stricter standards, greater regulation and more extensive permitting requirements, we expect our environmental expenditures to be substantial in the future. Although we have budgeted for significant expenditures to comply with these requirements, actual expenditures may be greater than budgeted amounts. We may have underestimated the cost of the environmental work we are planning or the air emissions allowances we anticipate buying. In addition, new environmental laws may be enacted, new or revised regulations under those laws may be issued, the interpretation of such laws and regulations by regulatory authorities or the courts may change, or additional information concerning the way in which such requirements apply to us may be identified. For example, in April 2006, Maryland enacted the Healthy Air Act, which requires more significant reductions in emissions of NOx, SO2 and mercury than the CAIR. This legislation affects our coal-fired units at Chalk Point, Dickerson and Morgantown. We anticipate that the total capital expenditures to achieve compliance for SO2 and NOx emissions at these facilities will be approximately $1.6 billion through the first quarter of 2010.

Increased public concern and growing political pressure related to global warming has resulted in significant increases in the regulation of greenhouse gases, including CO2 at the state level. Future local, state and federal regulation of greenhouse gases are likely to create substantial environmental costs for us in the form of taxes or purchases of emissions allowances. Many of the states where we own generating facilities, including California, Maryland, Massachusetts and New York, have recently committed to mandatory reductions in statewide CO2 emissions through a regional cap-and-trade program. Some of these programs include proposals that would not allocate emissions allowances to existing sources of emissions and instead require all allowances to be purchased initially through an auction process. This could decrease the amount of available allowances and substantially increase their prices. Because our generating facilities emit CO2, these regulations and similar future laws may significantly increase our operating costs.

Certain environmental laws, including CERCLA and comparable state laws, impose strict and, in many circumstances, joint and several liability for costs of remediating contamination in soil, groundwater and elsewhere. Some of our facilities have areas with known soil and/or groundwater contamination. Releases of hazardous substances at our generating facilities, or at locations where we dispose of (or in the past disposed of) hazardous substances and other waste, could require us to spend significant sums to remediate contamination, regardless of whether we caused such contamination. The discovery of significant contamination at our generating facilities, at disposal sites we currently use or have used, or at other locations for which we may be liable, or the failure or inability of parties contractually responsible to us for contamination to respond when claims or obligations regarding such contamination arise, could have a material adverse effect on our financial performance and condition.

Major environmental construction projects planned by 2010 at our Mid-Atlantic coal facilities may not meet their anticipated schedule, which would restrict these units from running at their maximum economic levels. In the event that the operating constraints were sufficiently severe, Mirant Mid-Atlantic may not have sufficient cash flow to permit it to make distributions or, if more severe, to meet its obligations.

Under the Maryland Healthy Air Act, we are required to reduce annual emissions below certain levels by January 2010. The levels established do not allow for the use of emissions allowances to meet the mandated levels. To meet these requirements, we are installing pollution control equipment on all of our Maryland coal facilities. We may not meet this construction schedule by January 2010 due to a number of factors, including:

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failure or delays in obtaining necessary permits and approvals;

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adverse weather conditions;

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unanticipated cost increases;

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engineering problems;

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shortages of equipment, materials or skilled labor;

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unscheduled delays in delivery of materials and equipment; and

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work stoppages.

Any of these factors may significantly increase the estimated costs of our environmental construction projects or result in a loss of cash flows from operations due to reduced unit operations.

The expected decommissioning and/or site remediation obligations of certain of our generating facilities may negatively affect our cash flows.

We expect that certain of our generating facilities and related properties will become subject to decommissioning and/or site remediation obligations that may require material expenditures. For example, we may start decommissioning the Lovett facility if the final operating unit ceases operation on April 19, 2008. We expect the decommissioning of the Lovett facility to cost approximately $20 million. The exact amount and

timing of such expenditures is not presently known. Furthermore, laws and regulations may change to impose material additional decommissioning and remediation obligations on us in the future. If we are required to make material expenditures to decommission or remediate one or more of our facilities, such obligations will affect our cash flows and may adversely affect our ability to make payments on our obligations.

Our consolidated indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting or refinancing our obligations.

As of December 31, 2007, our consolidated indebtedness was $3.095 billion. In addition, the present value of lease payments under the Mirant Mid-Atlantic leveraged leases is approximately $1 billion (assuming a 10% discount rate) and the termination value of the Mirant Mid-Atlantic leveraged leases is $1.4 billion. Our leverage could have important consequences, including the following: (1) it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; (2) a substantial portion of our cash flows from operations must be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities; (3) the debt service requirements of our indebtedness could make it more difficult for us to satisfy or refinance our financial obligations; (4) certain of our borrowings, including borrowings under our senior secured credit facilities, are at variable rates of interest, exposing us to the risk of increased interest rates; (5) it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared with our competitors that have less debt; and (6) we may be more vulnerable in a downturn in general economic conditions or in our business and we may be unable to carry out capital expenditures that are important to our long-term growth or necessary to comply with environmental regulations.

Mirant Corporation and its subsidiaries that are holding companies, including Mirant Americas Generation and Mirant North America, may not have access to sufficient cash to meet their obligations if their subsidiaries, in particular, Mirant Mid-Atlantic, are unable to make distributions.

We and certain of our subsidiaries, including Mirant Americas Generation and Mirant North America, are holding companies and, as a result, we are dependent upon dividends, distributions and other payments from our operating subsidiaries to generate the funds necessary to meet our obligations. The ability of certain of our subsidiaries to pay dividends and distributions is restricted under the terms of their debt or other agreements. In particular, a significant portion of cash from our operations is generated by the power generating facilities of Mirant Mid-Atlantic. Under the Mirant Mid-Atlantic leveraged leases, Mirant Mid-Atlantic is subject to a covenant that restricts its right to make distributions to its immediate parent, Mirant North America. In turn, Mirant North America is subject to covenants that restrict its ability to make distributions to its parent, Mirant Americas Generation. The ability of Mirant North America and Mirant Mid-Atlantic to satisfy the criteria set forth in their respective debt covenants in the future could be impaired by factors which negatively affect the performance of the power generating facilities of Mirant Mid-Atlantic, including interruptions in operation or curtailment of operations to comply with environmental restrictions.

The obligations of Mirant Corporation and its holding company subsidiaries, including the indebtedness of Mirant Americas Generation and Mirant North America, are effectively subordinated to the obligations or indebtedness of their respective subsidiaries, including the Mirant Mid-Atlantic leveraged leases.

We may be unable to generate sufficient liquidity to service our debt and to post required amounts of cash collateral necessary to hedge market risk effectively.

Our ability to pay principal and interest on our debt depends on our future operating performance. If our cash flows and capital resources are insufficient to allow us to make scheduled payments on our debt, we may have to reduce or delay capital expenditures, sell assets, seek additional capital, restructure or refinance. There

can be no assurance that the terms of our debt will allow these alternative measures, that the financial markets will be available to us on acceptable terms or that such measures would satisfy our scheduled debt service obligations.

We seek to manage the risks associated with the volatility in the price at which we sell power produced by our generating facilities and in the prices of fuel, emissions allowances and other inputs required to produce such power by entering into hedging transactions. These asset management activities may require us to post collateral either in the form of cash or letters of credit. As of December 31, 2007, we had approximately $110 million of posted cash collateral and $290 million of letters of credit outstanding primarily to support our asset management activities, debt service reserve requirements and other commercial arrangements. See Note 10 to our consolidated financial statements contained elsewhere in this report for further information on our posted cash collateral and letters of credit. While we seek to structure transactions in a way that reduces our potential liquidity needs for collateral, we may be unable to execute our hedging strategy successfully if we are unable to post the amount of collateral required to enter into and support hedging contracts.

We are an active participant in energy exchange and clearing markets. These markets require a per contract initial margin to be posted, regardless of the credit quality of the participant. The initial margins are determined by the exchanges through the use of proprietary models that rely on a variety of inputs and factors, including market conditions. We have limited notice of any changes to the margin rates. Consequently, we are exposed to changes in the per unit margin rates required by the exchanges and could be required to post additional collateral on short notice.

If our facilities experience unplanned outages, we may be required to procure replacement power in the open market to satisfy contractual commitments. Without adequate liquidity to post margin and collateral requirements, we may be exposed to significant losses and may miss significant opportunities, and we may have increased exposure to the volatility of spot markets.

Our business is subject to complex government regulations. Changes in these regulations, or their administration, by legislatures, state and federal regulatory agencies, or other bodies may affect the costs of operating our facilities or our ability to operate our facilities. Such cost impacts, in turn, may negatively affect our financial condition and results of operations.

We are subject to regulation by the FERC regarding the terms and conditions of wholesale service and rates, as well as by state agencies regarding physical aspects of our generating facilities. The majority of our generation is sold at market prices under market based rate authority granted by the FERC. If certain conditions are not met, the FERC has the authority to withhold or rescind market based rate authority and require sales to be made based on cost-of-service rates. A loss of our market based rate authority could have a materially negative impact on our generating business.

Even where market based rate authority has been granted, the FERC may impose various forms of market mitigation measures, including price caps and operating restrictions, where it determines that potential market power might exist and that the public interest requires such potential market power to be mitigated. In addition to direct regulation by the FERC, most of our facilities are subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, ISOs and RTOs may impose bidding and scheduling rules, both to curb the potential exercise of market power and to ensure market functions. Such actions may materially affect our ability to sell and the price we receive for our energy and capacity.

To conduct our business, we must obtain and periodically renew licenses, permits and approvals for our facilities. These licenses, permits and approvals can be in addition to any required environmental permits. No assurance can be provided that we will be able to obtain and comply with all necessary licenses, permits and

approvals for these facilities. If we cannot comply with all applicable regulations, our business, results of operations and financial condition could be adversely affected.

On August 8, 2005, the EPAct 2005 was enacted. Among other things, the EPAct 2005 provides incentives for various forms of electric generating technologies, which will subsidize certain of our competitors. Regulations that could be issued pursuant to the EPAct 2005 may have an adverse impact on our business.

We cannot predict whether the federal or state legislatures will adopt legislation relating to the restructuring of the energy industry. There are proposals in many jurisdictions both to advance and to roll back the movement toward competitive markets for the supply of electricity, at both the wholesale and retail levels. In addition, any future legislation favoring large, vertically integrated utilities and a concentration of ownership of such utilities could affect our ability to compete successfully, and our business and results of operations could be adversely affected. We cannot provide assurance that the introductions of new laws, or other future regulatory developments, will not have a material adverse impact on our business, operations or financial condition.

Changes in technology may significantly affect our generating business by making our generating facilities less competitive.

We generate electricity using fossil fuels at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in those technologies will reduce their costs to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.

Terrorist attacks, future war or risk of war may adversely affect our results of operations, our ability to raise capital or our future growth.

As power generators, we face heightened risk of an act of terrorism, either a direct act against one of our generating facilities or an inability to operate as a result of systemic damage resulting from an act against the transmission and distribution infrastructure that we use to transport our power. If such an attack were to occur, our business, financial condition and results of operations could be materially adversely affected. In addition, such an attack could affect our ability to service our indebtedness, our ability to raise capital and our future growth opportunities.

Our operations are subject to hazards customary to the power generating industry. We may not have adequate insurance to cover all of these hazards.

Our operations are subject to many hazards associated with the power generating industry, which may expose us to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquake, flood, lightning, hurricane and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in our operations. These hazards can cause significant injury to personnel or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate, but we cannot assure that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on our financial results and our financial condition.

We are currently involved in significant litigation that, if decided adversely to us, could materially adversely affect our results of operations and profitability.

We are currently involved in various litigation matters, which are described in more detail in this Form 10-K. We intend to defend vigorously against those claims that we are unable to settle, but the results of this litigation cannot be determined. Adverse outcomes for us in this litigation could require significant expenditures by us and could have a material adverse effect on our results of operations and profitability.

Item 1B. Unresolved

Staff Comments

None.

Item 2.

Properties

The properties below were owned or leased as of December 31, 2007. Our leasehold or ownership interest is 100% for each property.


Operating Plants	Location	Plant Type	Primary Fuel	Total MW(1)	2007 Net Capacity Factor(2)
Mid-Atlantic Region:
Chalk Point	Maryland	Intermediate/Baseload/ Peaking	Natural Gas/Coal/Oil	2,417	24	%
Dickerson	Maryland	Baseload/Peaking	Natural Gas/Coal/Oil	853	41	%
Morgantown	Maryland	Baseload/Peaking	Coal/Oil	1,492	54	%
Potomac River	Virginia	Intermediate/Baseload	Coal	482	34	%

Total Mid-Atlantic				5,244	37	%


Northeast Region:
Canal	Massachusetts	Intermediate	Natural Gas/Oil	1,112	23	%
Kendall	Massachusetts	Baseload/Peaking	Natural Gas/Oil/ Jet fuel	256	65	%
Martha’s Vineyard	Massachusetts	Peaking	Diesel	14	3	%

Total New England				1,382	30	%

Bowline	New York	Intermediate/Peaking	Natural Gas/Oil	1,124	6	%
Lovett	New York	Baseload	Natural Gas/Coal	183	67	%

Total New York				1,307	15	%

Total Northeast				2,689	22	%


California:
Contra Costa	California	Intermediate	Natural Gas	674	2	%
Pittsburg	California	Intermediate	Natural Gas	1,311	2	%
Potrero	California	Intermediate/Peaking	Natural Gas/Oil	362	16	%

Total California				2,347	4	%

Total Operations				10,280	25	%

(1)	Total MW amounts reflect nominal net dependable capacity.

(2)	Net capacity factor is the average production as a percentage of the potential net dependable capacity used over a year.

We also own an oil pipeline, which is approximately 51.5 miles long and serves the Chalk Point and Morgantown generating facilities.

Item 3. Legal Proceedings—See Note 18 to our consolidated financial statements contained elsewhere in this report for discussion of the material legal proceedings to which we are a party.

Item 4. Submission

of Matters to a Vote of Security Holders

None.

PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock

All shares of Old Mirant’s common stock were cancelled on January 3, 2006, and 276,500,000 shares of New Mirant common stock were distributed to holders of unsecured claims and equity securities. In addition, we reserved 23,500,000 shares for unresolved claims, of which approximately one million shares had not yet been distributed as of December 31, 2007. New Mirant also issued Series A and Series B warrants, expiring January 3, 2011, which entitle their holders to purchase an aggregate of 35,294,118 and 17,647,059 shares of common stock, respectively. The exercise price of the Series A and Series B warrants is $21.87 and $20.54 per share, respectively. On December 31, 2007, there were 35,023,201 Series A warrants and 17,172,929 Series B warrants yet to be exercised. New Mirant is authorized to issue 1,500,000,000 shares of common stock having a par value of $.01 per share and 100,000,000 shares of preferred stock having a par value of $.01 per share.

All of the New Mirant common stock was issued in accordance with Section 1145 of the Bankruptcy Code, and we received no proceeds from such issuance. The issuance of shares of New Mirant common stock was exempt from the registration requirements of the Securities Act, as amended, and equivalent provisions of state securities laws, in reliance upon Section 1145(a) of the Bankruptcy Code.

Our common stock is currently traded on the NYSE under the ticker symbol “MIR.” We have submitted to the NYSE our 2007 annual certificate from our Chief Executive Officer certifying that he is not aware of any violation by the Company of NYSE corporate governance listing standards. The closing price of our stock on December 31, 2007, was $38.98. The following table sets forth the high and low prices for our common stock as reported by the NYSE for the periods indicated.

Price Range of Common Stock


Quarter	High		Low
2006
First	$	29.00	$	23.93
Second	$	26.86	$	23.36
Third	$	29.59	$	26.02
Fourth	$	32.61	$	25.10

2007
First	$	41.70	$	30.41
Second	$	49.00	$	39.61
Third	$	44.20	$	34.77
Fourth	$	44.61	$	36.20

Holders

As of February 25, 2008, there were approximately 58,873 record holders of our common stock, par value $.01 per share.

Dividends

We have not paid or declared any cash dividends on our common stock in the last two fiscal years and we do not anticipate paying any quarterly cash dividends in the foreseeable future.

Return of Cash

On November 9, 2007, we announced the conclusion of the strategic review process that was initiated in April 2007. We plan to return a total of $4.6 billion of excess cash to our stockholders. The first stage of the cash distribution is being 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, in conjunction with the accelerated share repurchases, we repurchased approximately 26.66 million shares of our common stock for $1 billion. See Note 13 to our consolidated financial statements contained elsewhere in this report for further discussion. In addition, we purchased approximately 8.27 million shares of our common stock for approximately $316 million through open market purchases. Between January 1, 2008 and February 25, 2008, we purchased an additional 7.9 million shares in open market purchases for approximately $286 million. 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.

Share Repurchases

The following table sets forth information regarding repurchases by us of our common shares on the NYSE during the three-month period ended December 31, 2007:


Period	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)
Oct 1, 2007—Oct 31, 2007	—	$	—	—	$	—
Nov 1, 2007—Nov 30, 2007	30.56	$	37.50	30.56	$	854.18
Dec 1, 2007—Dec 31, 2007	4.37	$	38.83	4.37	$	684.32

Total	34.93	$	37.67	34.93	$	684.32

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth the compensation plans under which our equity securities were authorized for issuance as of December 31, 2007:


Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities to be issued upon exercise of outstanding options, warrants and rights)
	(in millions)			(in millions)
Equity compensation plans approved by security holders	5.4	$	28.06	13.2
Equity compensation plans not approved by security holders	N/A		N/A	N/A
Total	5.4	$	28.06	13.2

Our 2005 Omnibus Incentive Plan for certain employees and directors of Mirant became effective on January 3, 2006, and is deemed to have been approved by our stockholders by virtue of its approval under the Plan.

Stock Performance Graph

The performance graph below compares the cumulative total stockholder return on our common stock with the Standard & Poor’s 500 Index, the Standard & Poor’s Multi-Utility Index and the Standard & Poor’s Independent Power Producers and Energy Traders Index since the re-issuance of our common stock in connection with our emergence from bankruptcy on January 3, 2006. Our stock was re-listed on the New York Stock Exchange on January 11, 2006. Because all of Old Mirant’s outstanding common stock was cancelled upon emergence from bankruptcy, stock performance prior to 2006 does not provide a meaningful comparison for current stockholders and thus has not been provided. The graph assumes that $100 was invested on January 11, 2006, in our common stock and each of the above indices, and that all dividends are reinvested. The stockholder return shown below may not be indicative of future performance.

LOGO

Total Return to Stockholders

(Includes reinvestment of dividends)

Quarterly Return Percentage

Quarter Ending


Company / Index	3/31/2006		6/30/2006		9/30/2006		12/31/2006
Mirant	0.08	%	7.20	%	1.90	%	15.60	%
S&P 500 Index	0.51	%	(1.44	)%	5.67	%	6.70	%
S&P 500 Multi-Utilities Index	(3.17	)%	3.47	%	4.20	%	10.54	%
S&P 500 Independent Power Producers & Energy Traders	(1.92	)%	19.28	%	7.07	%	(0.18	)%

Company / Index	3/31/2007		6/30/2007		9/30/2007		12/31/2007
Mirant	28.16	%	5.41	%	(4.62	)%	(4.18	)%
S&P 500 Index	0.64	%	6.28	%	2.03	%	(3.33	)%
S&P 500 Multi-Utilities Index	6.96	%	(3.07	)%	1.46	%	5.39	%
S&P 500 Independent Power Producers & Energy Traders	15.55	%	3.30	%	(1.07	)%	6.82	%

Indexed Returns

Quarter Ending


Company / Index	Base Period 1/11/2006		3/31/2006		6/30/2006		9/30/2006		12/31/2006
Mirant	$	100	$	100.08	$	107.29	$	109.33	$	126.38
S&P 500 Index	$	100	$	100.51	$	99.06	$	104.68	$	111.69
S&P 500 Multi-Utilities Index	$	100	$	96.83	$	100.19	$	104.40	$	115.41
S&P 500 Independent Power Producers & Energy Traders	$	100	$	98.08	$	116.99	$	125.26	$	125.03


Company / Index	3/31/2007		6/30/2007		9/30/2007		12/31/2007
Mirant	$	161.97	$	170.74	$	162.85	$	156.04
S&P 500 Index	$	112.40	$	119.46	$	121.89	$	117.82
S&P 500 Multi-Utilities Index	$	123.45	$	119.66	$	121.40	$	127.95
S&P 500 Independent Power Producers & Energy Traders	$	144.47	$	149.24	$	147.64	$	157.71

Item 6.

Selected Financial Data

The following discussion should be read in conjunction with our consolidated financial statements and the notes thereto, which are included elsewhere in this Form 10-K. The following tables present our selected consolidated financial information, which is derived from our consolidated financial statements.

During our bankruptcy proceedings, our consolidated financial statements were prepared in accordance with SOP 90-7. Our Statements of Operations Data for the years ended December 31, 2004 and 2003, do not include interest expense on debt that was subject to compromise subsequent to the Petition Date and include goodwill impairment losses of $582 million and $2.067 billion, respectively. Our Statement of Operations Data for the year ended December 31, 2005, reflects the effects of accounting for the Plan confirmed on December 9, 2005.

Our Statement of Operations Data for the year ended December 31, 2006, reflects significant income tax benefits as discussed in Note 7 to our consolidated financial statements. Our Statement of Operations Data for the year ended December 31, 2007, reflects gains on sales of discontinued operations as discussed in Note 11 to our consolidated financial statements. EPS information for years prior to 2006 has not been presented because the information is not relevant in any material respect for users of our financial statements. See Note 14 to our consolidated financial statements contained elsewhere in this report for additional information.


	Years Ended December 31,
	2007		2006		2005			2004			2003
	(in millions except per share data)
Statements of Operations Data:
Operating revenues	$	2,019	$	3,087	$	2,620		$	3,231		$	3,856
Income (loss) from continuing operations		433		1,752		(1,385	)		(9	)		(3,863	)
Income (loss) from discontinued operations		1,562		112		93			(467	)		57
Cumulative effect of changes in accounting principles		—		—		(15	)		—			(29	)
Net income (loss)		1,995		1,864		(1,307	)		(476	)		(3,835	)
Basic EPS per common share from continuing operations	$	1.72	$	6.15		N/A			N/A			N/A

The consolidated Balance Sheet Data for years 2006, 2005, 2004 and 2003, segregates pre-petition liabilities subject to compromise from those liabilities that were not subject to compromise.


	Years Ended December 31,
	2007		2006		2005		2004			2003
Balance Sheet Data:
Total assets	$	9,452	$	11,496	$	12,912	$	11,424		$	12,123
Total long-term debt		3,095		3,275		2,582		38			43
Liabilities subject to compromise		—		18		18		9,164			9,036
Stockholders’ equity (deficit)	$	5,310	$	4,443	$	3,856	$	(1,318	)	$	(823	)

The debt of Mirant Americas Generation that was reinstated in 2005 is included in liabilities subject to compromise for 2003 and 2004. In 2005, we recorded the effects of the Plan. As a result, liabilities subject to compromise at December 31, 2005 and 2006 only reflect the liabilities of our New York entities that remained in bankruptcy at that time.

Item 7.

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

This section is intended to provide the reader with information that will assist in understanding our financial statements, the changes in those financial statements from year to year and the primary factors contributing to those changes. The following discussion should be read in conjunction with our consolidated financial statements and the notes accompanying those financial statements.

Overview

Dispositions

Exploration of Strategic Alternatives and Share Repurchases

Hedging Activities

the posting of cash collateral either for initial margin or for securing exposure as a result of changes in power prices. However, we generally do not hedge our intermediate and peaking units for tenors greater than 12 months. At February 25, 2008, we were economically hedged as follows:


	Aggregate Hedge Levels Based on Expected Generation
	2008	2009	2010	2011	2012
Power	98%	53%	38%	21%	20%
Fuel	95%	79%	31%	29%	5%
SO2/NOx	100%	100%	100%	100%	100%

Capital Expenditures and Capital Resources

For the year ended December 31, 2007, we paid $560 million of capital expenditures, primarily related to the Maryland Healthy Air Act. The following table details our estimated capital expenditures, excluding capitalized interest, for 2008 through 2010 (in millions)


	2008		2009		2010
Maryland Healthy Air Act	$	689	$	286	$	125
Other environmental		63		35		28
Maintenance		130		142		99
Construction		74		52		18
Other		19		12		14

Total	$	975	$	527	$	284

Through December 31, 2007, we paid approximately $500 million for capital expenditures related to the Maryland Healthy Air Act. We will have extended planned outages during the installation of equipment and, during those outages, we will perform other routine maintenance activities. We expect that available cash and future cash flows from operations will be sufficient to fund these capital expenditures.

Settlement Agreement with Pepco

On August 10, 2007, the Settlement Agreement and Release (the “Settlement Agreement”) with Pepco and the various affiliates of Pepco (collectively the “Pepco Settling Parties”) dated May 30, 2006, became fully effective, and we recognized a gain of $379 million comprised of (1) $341 million representing the fair value of the price risk management liability that was reversed as a result of the rejection of a long-term PPA with Pepco (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 Mirant shares distributed to it. In addition, Pepco repaid Mirant $70 million for an advance payment made in the third quarter of 2006 under the Settlement Agreement.

Consolidated Financial Performance

We reported net income of $1.995 billion and $1.864 billion for the years ended December 31, 2007 and 2006, respectively, and a net loss of $1.307 billion for the year ended December 31, 2005. The change in net income (loss) is detailed as follows (in millions):


	Years Ended December 31,
	2007			2006			Increase/ (Decrease)			2006			2005			Increase/ (Decrease)
Realized gross margin	$	1,643		$	1,281		$	362		$	1,281		$	852		$	429
Unrealized gross margin		(536	)		655			(1,191	)		655			(16	)		671

Total gross margin		1,107			1,936			(829	)		1,936			836			1,100

Operating expenses:
Operations and maintenance		707			592			115			592			683			(91	)
Depreciation and amortization		129			137			(8	)		137			135			2
Impairment losses		175			119			56			119			9			110
Loss (gain) on sales of assets, net		(45	)		(49	)		4			(49	)		17			(66	)

Total operating expenses		966			799			167			799			844			(45	)

Operating income (loss)		141			1,137			(996	)		1,137			(8	)		1,145

Total other expense (income), net		(299	)		99			(398	)		99			1,413			(1,314	)

Income (loss) from continuing operations before reorganization items, net and income taxes		440			1,038			(598	)		1,038			(1,421	)		2,459
Reorganization items, net		(2	)		(164	)		162			(164	)		(18	)		(146	)
Provision (benefit) for income taxes		9			(550	)		559			(550	)		(18	)		(532	)

Income (loss) from continuing operations		433			1,752			(1,319	)		1,752			(1,385	)		3,137
Income from discontinued operations		1,562			112			1,450			112			93			19

Income (loss) before cumulative effect of changes in accounting principles		1,995			1,864			131			1,864			(1,292	)		3,156

Cumulative effect of changes in accounting principles		—			—			—			—			(15	)		15

Net income (loss)	$	1,995		$	1,864		$	131		$	1,864		$	(1,307	)	$	3,171

Results of Operations

The following discussion of our performance is organized by reportable operating segment, which is consistent with the way we manage our business. In 2007, we completed the sales of six U.S. natural gas-fired facilities, our Philippine business, our Caribbean business and Mirant NY-Gen. The sales have resulted in the reclassification of the revenues and expenses of these businesses and facilities to discontinued operations and the reclassification of the related assets and liabilities to assets held for sale for all periods presented through their respective dates of sale.

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, Lovett, Kendall and Martha’s Vineyard facilities. The California region includes our Pittsburg, Contra Costa and Potrero facilities. Other Operations includes proprietary trading, fuel oil management and gains and losses related to a long-term PPA with Pepco, the Back-to-Back Agreement, which was terminated pursuant to a settlement agreement that became effective in the third quarter of 2007. See Note 19 to our consolidated financial statements contained elsewhere in this report for further discussion of the Back-to-Back Agreement. 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.

Operating Statistics

The following table summarizes net capacity factor by region for the years ended December 31, 2007, 2006 and 2005:


	Years Ended December 31,
	2007		2006		Increase/ (Decrease)		2006		2005		Decrease
Mid-Atlantic	37	%	36	%	1	%	36	%	39	%	(3	)%
Northeast	22	%	18	%	4	%	18	%	35	%	(17	)%
California	4	%	6	%	(2	)%	6	%	7	%	(1	)%
Total	25	%	24	%	1	%	24	%	31	%	(7	)%

The following table summarizes power generation volumes by region for the years ended December 31, 2007, 2006 and 2005 (in gigawatt hours):


	Years Ended December 31,
	2007	2006	Increase/ (Decrease)		2006	2005	Decrease
Mid-Atlantic	16,832	16,608	224		16,608	18,201	(1,593	)
Northeast	5,510	4,668	842		4,668	9,041	(4,373	)
California	822	1,136	(314	)	1,136	1,414	(278	)

Total	23,164	22,412	752		22,412	28,656	(6,244	)

2007 versus 2006

Gross Margin Overview

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


	Years Ended December 31,
	2007							2006
	Realized		Unrealized			Total		Realized		Unrealized		Total
Mid-Atlantic	$	1,084	$	(479	)	$	605	$	834	$	484	$	1,318
Northeast		280		(43	)		237		286		61		347
California		135		—			135		112		3		115
Other Operations		126		(14	)		112		11		107		118
Eliminations		18		—			18		38		—		38

Total	$	1,643	$	(536	)	$	1,107	$	1,281	$	655	$	1,936

Gross margin for the years ended December 31, 2007 and 2006, is further detailed as follows (in millions):


	Year Ended December 31, 2007
	Mid- Atlantic			Northeast			California		Other Operations			Eliminations		Total
Energy	$	686		$	128		$	3	$	109		$	18	$	944
Contracted and capacity		196			87			132		17			—		432
Incremental realized value of hedges		202			65			—		—			—		267

Total realized gross margin		1,084			280			135		126			18		1,643
Unrealized gross margin		(479	)		(43	)		—		(14	)		—		(536	)

Total Gross Margin	$	605		$	237		$	135	$	112		$	18	$	1,107


	Year Ended December 31, 2006
	Mid- Atlantic		Northeast		California			Other Operations			Eliminations		Total
Energy	$	532	$	117	$	14		$	71		$	38	$	772
Contracted and capacity		39		44		101			(60	)		—		124
Incremental realized value of hedges		263		125		(3	)		—			—		385

Total realized gross margin		834		286		112			11			38		1,281
Unrealized gross margin		484		61		3			107			—		655

Total Gross Margin	$	1,318	$	347	$	115		$	118		$	38	$	1,936

Energy represents gross margin from the generation of electricity, sales and purchases of emissions allowances, fuel sales, purchases and handling of fuel, 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, ancillary services and from the Back-to-Back Agreement, which was terminated on August 10, 2007.

Incremental realized value of hedges represents the actual margin upon the settlement of our power and fuel hedging contracts.

Unrealized gross margin represents the net unrealized gain or loss on our derivative contracts.

Our gross margin for the year ended December 31, 2007, was $1.107 billion as compared to $1.936 billion for the same period in 2006. The decrease in gross margin, which includes net unrealized gains and losses from our hedging activities, was principally a result of the following:

A decrease of $1.191 billion in unrealized gross margin was comprised of the following:

—

unrealized losses of $536 million in 2007, which include $438 million from the settlement of power and fuel contracts during the period for which net unrealized gains had been recorded in prior periods and a $98 million net decrease in the value of hedge contracts for future periods primarily related to increases in forward power prices in 2007; and

—

unrealized gains of $655 million in 2006, which include a $433 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power prices in 2006 and $222 million from the settlement of power and fuel contracts during the period for which net unrealized losses had been recorded in prior periods.

An increase of $362 million in realized gross margin primarily attributable to: (1) an increase in contracted and capacity of $308 million, which includes the refund by Pepco of $36 million of payments made to it under

the Back-to-Back Agreement for periods after May 31, 2006, as a result of the Settlement Agreement with Pepco becoming fully effective in August 2007; (2) an increase in energy of $172 million as a result of an increase in power prices, a decrease in emissions prices, slightly higher generation volumes and the settlement of favorable fuel oil management positions; partially offset by (3) a decrease of $118 million in incremental realized value of hedges.

Mid-Atlantic

Our Mid-Atlantic segment, which accounts for approximately half of our net generating capacity, includes four generating facilities with total net generating capacity of 5,244 MW. The following tables summarize our Mid-Atlantic segment (in millions):


	Years Ended December 31,						Increase/ (Decrease)
	2007			2006			Increase/ (Decrease)
Realized gross margin	$	1,084		$	834		$	250
Unrealized gross margin		(479	)		484			(963	)

Total gross margin		605			1,318			(713	)

Operating expenses:
Operations and maintenance		360			333			27
Depreciation and amortization		81			74			7
Gain on sales of assets, net		—			(7	)		7

Total operating expenses		441			400			41

Operating income		164			918			(754	)

Total other expense (income), net		(5	)		(4	)		(1	)

Income from continuing operations before reorganization items and income taxes	$	169		$	922		$	(753	)

Gross Margin


	Years Ended December 31,					Increase/ (Decrease)
	2007			2006		Increase/ (Decrease)
Energy	$	686		$	532	$	154
Contracted and capacity		196			39		157
Incremental realized value of hedges		202			263		(61	)

Total realized gross margin		1,084			834		250
Unrealized gross margin		(479	)		484		(963	)

Total gross margin	$	605		$	1,318	$	(713	)

The increase of $250 million in realized gross margin was principally a result of the following:

—

an increase of $154 million in energy, primarily because of an increase in power prices, a decrease in emissions prices and slightly higher generation volumes;

—

an increase of $157 million in contracted and capacity related to higher capacity revenues from the PJM RPM, which became effective in June 2007. See Item 1. “Regulatory Environment” for further discussion of RPM; and

—

a decrease of $61 million in incremental realized value of hedges of our generation output primarily as a result of a decrease in the amount by which the settlement value of power contracts exceeded market prices.

The decrease of $963 million in unrealized gross margin was comprised of the following:

—

unrealized losses of $479 million in 2007, which include $270 million from the settlement of power and fuel contracts during the period for which net unrealized gains had been recorded in prior periods and a $209 million net decrease in the value of hedge contracts for future periods primarily related to increases in forward power prices in 2007; and

—

unrealized gains of $484 million in 2006, which include a $312 million net increase in the value of hedge contracts for future periods primarily as a result of decreases in forward power prices in 2006 and $172 million from the settlement of power and fuel contracts during the year for which net unrealized losses had been recorded in prior periods, particularly during the high energy prices of late 2005.

Operating Expenses

Operating expenses increased $41 million primarily as a result of the following:

—

an increase of $27 million in operations and maintenance expense, of which $18 million was related to higher maintenance performed in conjunction with planned outages for the installation of pollution control equipment and $8 million related to increased corporate overhead allocations as a result of the dispositions in 2007;

—

an increase of $7 million in depreciation and amortization expense primarily related to expenditures on equipment to improve environmental performance; and

—

a decrease of $7 million in gain on sales of assets, net primarily related to a gain of $6 million on the sale of a building in 2006.

Northeast

Our Northeast segment is comprised of our facilities located in New York and New England with total net generating capacity of 2,689 MW. The following tables summarize the operations of our Northeast segment (in millions):


	Years Ended December 31,						Increase/ (Decrease)
	2007			2006			Increase/ (Decrease)
Realized gross margin	$	280		$	286		$	(6	)
Unrealized gross margin		(43	)		61			(104	)

Total gross margin		237			347			(110	)

Operating expenses:
Operations and maintenance		179			116			63
Depreciation and amortization		25			25			—
Impairment losses		175			118			57
Gain on sales of assets, net		(49	)		(46	)		(3	)

Total operating expenses		330			213			117

Operating income (loss)		(93	)		134			(227	)

Total other expense (income), net		(7	)		9			(16	)

Income (loss) from continuing operations before reorganization items and income taxes	$	(86	)	$	125		$	(211	)

Gross Margin


	Years Ended December 31,					Increase/ (Decrease)
	2007			2006		Increase/ (Decrease)
Energy	$	128		$	117	$	11
Contracted and capacity		87			44		43
Incremental realized value of hedges		65			125		(60	)

Total realized gross margin		280			286		(6	)
Unrealized gross margin		(43	)		61		(104	)

Total gross margin	$	237		$	347	$	(110	)

The decrease of $6 million in realized gross margin was principally a result of the following:

—

a decrease of $60 million in incremental realized value of hedges of our generation output, primarily as a result of a decrease in the amount by which the settlement value of power contracts exceeded market prices;

—

an increase of $43 million in contracted and capacity from the implementation of the new FCM in New England. See Item 1. “Regulatory Environment” for further information on the implementation of the new FCM; and

—

an increase of $11 million in energy, primarily because of an increase in power prices and higher generation volumes.

The decrease of $104 million in unrealized gross margin was comprised of the following:

—

unrealized losses of $43 million in 2007, which include $57 million from the settlement of power and fuel contracts during the period for which unrealized gains had been recorded in prior periods, partially offset by a $14 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power prices in 2007; and

—

unrealized gains of $61 million in 2006, which include a $50 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power prices in 2006 and $11 million from the settlement of power and fuel contracts during the year for which unrealized losses had been recorded in prior periods, particularly during the high energy prices of late 2005.

Operating Expenses

Operating expenses increased $117 million primarily as a result of the following:

—

an increase of $63 million in operations and maintenance which included:

—

an increase of $71 million in 2007, which represents that portion of the 2006 New York property tax settlement that reduced operating expenses for 2006, but which related to prior periods. See Note 19 to our consolidated financial statements contained elsewhere in this report for further discussion; and

—

a decrease of $6 million related to a decrease in maintenance costs primarily as a result of the shutdown of Lovett units 3 and 4 in 2007 and repairs on Lovett unit 5 in 2006.

—

an increase of $57 million in impairment losses. In 2007, we recorded an impairment loss of $175 million on our Lovett facility. In 2006, we recorded an impairment loss of $118 million on the Bowline unit 3 suspended construction project. See Note 5 to our consolidated financial statements contained elsewhere in this report for additional information related to these impairments.

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 our California segment (in millions):


	Years Ended December 31,						Increase/ (Decrease)
	2007			2006			Increase/ (Decrease)
Realized gross margin	$	135		$	112		$	23
Unrealized gross margin		—			3			(3	)

Total gross margin		135			115			20

Operating expenses:
Operations and maintenance		74			63			11
Depreciation and amortization		13			13			—
Gain on sales of assets, net		(2	)		—			(2	)

Total operating expenses		85			76			9

Operating income		50			39			11

Total other expense (income), net		(5	)		(34	)		29

Income from continuing operations before reorganization items and income taxes	$	55		$	73		$	(18	)

Gross Margin


	Years Ended December 31,					Increase/ (Decrease)
	2007		2006			Increase/ (Decrease)
Energy	$	3	$	14		$	(11	)
Contracted and capacity		132		101			31
Incremental realized value of hedges		—		(3	)		3

Total realized gross margin		135		112			23
Unrealized gross margin		—		3			(3	)

Total gross margin	$	135	$	115		$	20

The increase in our contracted and capacity gross margin and decrease in our energy gross margin were primarily a result of the commencement of a new tolling agreement in the first quarter of 2007 at our Contra Costa and Pittsburg facilities. See Item 1. “Business Segments” for additional information regarding the tolling agreement.

Operating Expenses

The increase of $9 million in operating expenses includes an increase of $11 million in operations and maintenance expense in 2007, resulting from higher maintenance costs related to outages and a $5 million property tax settlement in 2006.

Other Expense (Income), Net

The decrease of $29 million in other expense (income), net is primarily a result of a gain of $26 million in 2006 related to the transfer of Contra Costa unit 8 to PG&E. See “California Settlement” in Note 19 to our consolidated financial statements contained elsewhere in this report for further discussion.

Other Operations

Other Operations includes proprietary trading, fuel oil management and gains and losses related to the Back-to-Back Agreement, which was terminated pursuant to a settlement that became effective in the third quarter of 2007. See “Pepco Litigation” in Note 19 to our consolidated financial statements contained elsewhere in this report for further discussion of the Back-to-Back Agreement. Other Operations also includes unallocated corporate overhead, interest on debt at Mirant Americas Generation and Mirant North America and interest income on our invested cash balances. The following tables summarize our Other Operations segment (in millions):


	Years Ended December 31,						Increase/ (Decrease)
	2007			2006			Increase/ (Decrease)
Realized gross margin	$	126		$	11		$	115
Unrealized gross margin		(14	)		107			(121	)

Total gross margin		112			118			(6	)

Operating expenses:
Operations and maintenance		94			80			14
Depreciation and amortization		10			25			(15	)
Impairment losses		—			1			(1	)
Gain on sales of assets, net		(5	)		(40	)		35

Total operating expenses		99			66			33

Operating income		13			52			(39	)

Total other expense (income), net		(282	)		128			(410	)

Income (loss) from continuing operations before reorganization items and income taxes	$	295		$	(76	)	$	371

Gross Margin


	Years Ended December 31,						Increase/ (Decrease)
	2007			2006			Increase/ (Decrease)
Energy	$	109		$	71		$	38
Contracted and capacity		17			(60	)		77

Total realized gross margin		126			11			115
Unrealized gross margin		(14	)		107			(121	)

Total gross margin	$	112		$	118		$	(6	)

The increase of $115 million in realized gross margin was principally a result of the following:

—

an increase of $77 million in contracted and capacity related to a decrease in realized losses on the Back-to-Back Agreement and the related hedges of this contract and, as a result of the Settlement Agreement with Pepco becoming fully effective in August 2007, the refund by Pepco of $36 million of payments made to it under the Back-to-Back Agreement for periods after May 31, 2006; and

—

an increase of $38 million in energy related to our proprietary trading and fuel oil management activities as favorable positions entered into prior to 2007 were settled in the current period.

The decrease of $121 million in unrealized gross margin was comprised of the following:

—

unrealized losses in 2007 of $14 million, including:

—

unrealized losses on proprietary trading and fuel oil management activities of $102 million, which include $115 million from the settlement of power and fuel contracts during the period for which unrealized gains had been recorded in prior periods and a $13 million net increase in value associated with contracts for future periods; partially offset by

—

unrealized gains on the Back-to-Back Agreement and related hedges of $88 million primarily as a result of an increase in forward value related to the prices for forward capacity in PJM and the resulting decrease in the fair value of the liability of that agreement.

—

unrealized gains in 2006 of $107 million, which include unrealized gains on proprietary trading and fuel oil management activities of $61 million and unrealized gains on the Back-to-Back Agreement of $46 million.

Operating Expenses

Operating expenses increased $33 million primarily as a result of the following:

—

a decrease of $35 million in gain on sales of assets, net primarily as a result of the 2006 gain on the sale of our remaining claims in the Enron bankruptcy;

—

an increase of $14 million in operations and maintenance expense primarily as a result of the following:

—

an increase of $35 million related to the accrual for costs of MC Asset Recovery that we are required to pay under the terms of the Plan. See Note 18 to our consolidated financial statements contained elsewhere in this report for further discussion;

—

an increase of $27 million related to an increase in incentive compensation, including the dispositions bonus plan;

—

an increase of $9 million in litigation contingency accruals; partially offset by

—

a decrease related to a curtailment gain of $32 million resulting from an amendment to our postretirement benefits plan;

—

a decrease of $19 million in bankruptcy related charges and prepetition disputes; and

—

a decrease of $15 million in depreciation expense as a result of fully depreciated computer equipment.

Other Expense (Income), Net

Other expense (income), net decreased $410 million primarily as a result of the following:

—

a gain of $341 million resulting from the termination of the Back-to-Back Agreement;

—

an increase of $126 million in interest income related to increased cash balances as a result of the proceeds from dispositions completed in 2007; partially offset by

—

a decrease in gain on sales of investments, which included a gain of $54 million in 2006 from the sale of a portion of our investment in InterContinental Exchange and $19 million on the sale of our two New York Mercantile Exchange seats and shares.

Other Significant Consolidated Statements of Operations Comparison

Provision (Benefit) for Income Taxes

The provision for income taxes increased by $559 million for the year ended December 31, 2007, compared to 2006, primarily as a result of the $552 million benefit in 2006 related to the release of the valuation allowance pertaining to deferred tax assets previously recorded including the estimated value of the NOLs that were used to offset the 2007 taxable gain resulting from the sale of the Philippine business.

Discontinued Operations

For the year ended December 31, 2007, we reported net income from discontinued operations of $1.562 billion, which includes the reclassification of the results of operations related to the dispositions. Income from discontinued operations increased $1.450 billion for the year ended December 31, 2007, as compared to 2006 primarily as a result of the following:

—

an increase of $2.479 billion in gain on sales of assets, which included:

—

an increase of $2.003 billion as a result of the sale of the Philippine business in 2007;

—

an increase of $63 million as a result of the gain on the sale of the Caribbean business in 2007;

—

an increase of $405 million as a result of the impairments recorded on six U.S. natural gas-fired facilities. For the year ended December 31, 2006, we recorded total impairments of $375 million. For the year ended December 31, 2007, we recorded a reduction to the impairment of $30 million; and

—

an increase of $8 million as a result of the sale of NY-Gen in 2007.

—

a 2007 gain of $24 million related to the agreement for Wrightsville transmission credits;

—

an increase in the provision for income taxes of $793 million, primarily related to the sale of the Philippine business; and

—

a decrease of $260 million in income from discontinued operations because of the completion of the dispositions, which occurred in the second and third quarters of 2007.

See Note 11 to our consolidated financial statements contained elsewhere in this report for additional information related to discontinued operations.

Reorganization Items, net

Reorganization items, net for the years ended December 31, 2007 and 2006, are comprised of the following (in millions):


	Years Ended December 31,
	2007			2006			Increase/ (Decrease)
Gain on the New York property tax settlement	$	—		$	(163	)	$	163
Professional fees and administrative expense		3			2			1
Interest income, net		(5	)		(3	)		(2	)

Total	$	(2	)	$	(164	)	$	162

Under the terms of the New York property tax settlement, in February 2007 we received refunds totaling approximately $163 million for 1995 through 2003 and paid unpaid but accrued taxes of approximately $115 million for 2003 through 2006. See Note 19 to our consolidated financial statements contained elsewhere in this report for additional information.

2006 versus 2005

Gross Margin

The following table details gross margin by realized and unrealized margin for the year ended December 31, 2006 and 2005 (in millions):


	Years Ended December 31,
	2006						2005
	Realized		Unrealized		Total		Realized			Unrealized			Total
Mid-Atlantic	$	834	$	484	$	1,318	$	552		$	(97	)	$	455
Northeast		286		61		347		206			(11	)		195
California		112		3		115		113			—			113
Other Operations		11		107		118		(34	)		92			58
Eliminations		38		—		38		15			—			15

Total	$	1,281	$	655	$	1,936	$	852		$	(16	)	$	836

Mid-Atlantic

The following table summarizes the operations of our Mid-Atlantic segment for the years ended December 31, 2006 and 2005 (in millions):


	Years Ended December 31,						Increase/ (Decrease)
	2006			2005			Increase/ (Decrease)
Realized Gross Margin	$	834		$	552		$	282
Unrealized Gross Margin		484			(97	)		581

Total Gross Margin		1,318			455			863

Operating expenses:
Operations and maintenance		333			341			(8	)
Depreciation and amortization		74			64			10
Gain on sales of assets, net		(7	)		—			(7	)

Total operating expenses		400			405			(5	)

Operating income		918			50			868

Total other expense (income), net		(4	)		18			(22	)

Income from continuing operations before reorganization items and income taxes	$	922		$	32		$	890

Gross Margin

Gross margin increased by $863 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):


	Years Ended December 31,					Increase/ (Decrease)
	2006		2005			Increase/ (Decrease)
Energy	$	532	$	770		$	(238	)
Contracted and capacity		39		64			(25	)
Incremental realized value of hedges		263		(282	)		545

Total realized gross margin		834		552			282
Unrealized gross margin		484		(97	)		581

Total gross margin	$	1,318	$	455		$	863

Incremental realized value of hedges represents the actual margin upon the settlement of our power and fuel hedging contracts.

Unrealized gross margin represents the unrealized gain or loss on our derivative contracts.

The significant increase in the gross margin for our Mid-Atlantic operations is primarily due to the following:

—

an increase of $581 million related to unrealized gross margin from hedging activities. In 2006, unrealized gains of $484 million are primarily due to $312 million from increased value associated with forward power contracts for future periods as a result of decreases in forward power prices in 2006 and $172 million due to the settlement of power and fuel contracts during the year for which net unrealized losses had been recorded in prior periods, particularly during the high energy prices of late 2005. In 2005, unrealized losses of $97 million were primarily due to increases in power prices as a result of increases in gas prices;

—

an increase of $545 million in incremental realized value of hedges of our generation output. In 2006, the incremental realized value of our hedges contributed $263 million to our gross margin as our power contracts settled at prices higher than market prices for the year. In 2005, our opportunity cost of hedging was $282 million primarily due to the impact of rising energy prices in the latter part of 2005 that resulted in the settlement of power contracts at prices lower than market prices for that year; and

—

a decrease of $238 million in energy primarily related to lower power prices and lower generation volumes on our oil-fired units. Power prices were lower due to significantly lower gas prices in 2006 compared to 2005. Our baseload coal units’ generation decreased slightly and our 9% total decrease in generation volumes was driven by significantly lower volumes generated by our oil-fired units. A sharp decrease in power prices combined with average oil prices that were somewhat higher than in 2005 resulted in our oil-fired units not being able to dispatch economically for much of the year.

Northeast

The following table summarizes the operations of our Northeast segment for the years ended December 31, 2006 and 2005 (in millions):


	Years Ended December 31,						Increase/ (Decrease)
	2006			2005			Increase/ (Decrease)
Realized Gross Margin	$	286		$	206		$	80
Unrealized Gross Margin		61			(11	)		72

Total Gross Margin		347			195			152

Operating expenses:
Operations and maintenance		116			210			(94	)
Depreciation and amortization		25			33			(8	)
Impairment losses		118			—			118
Gain on sales of assets, net		(46	)		(10	)		(36	)

Total operating expenses		213			233			(20	)

Operating income (loss)		134			(38	)		172

Total other expense, net		9			6			3

Income (loss) from continuing operations before reorganization items and income taxes	$	125		$	(44	)	$	169

Gross Margin

Gross margin increased by $152 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):


	Years Ended December 31,					Increase/ (Decrease)
	2006		2005			Increase/ (Decrease)
Energy	$	117	$	214		$	(97	)
Contracted and capacity		44		35			9
Incremental realized value of hedges		125		(43	)		168

Total realized gross margin		286		206			80
Unrealized gross margin		61		(11	)		72

Total gross margin	$	347	$	195		$	152

The increase in gross margin is primarily due to the following:

—

an increase of $72 million related to unrealized gross margin from hedging activities. In 2006, unrealized gains of $61 million are primarily due to $50 million from increased value associated with forward power and fuel contracts for future periods mainly as a result of decreases in forward power prices in 2006 and $11 million due to the settlement of power and fuel contracts during the year for which unrealized losses had been recorded in prior periods, particularly during the high energy prices of late 2005. In 2005, unrealized losses of $11 million were primarily due to increases in power prices as a result of increased gas prices and the settlement of contracts during the year for which unrealized losses had been recorded in prior periods, partially offset by an increase in the value of fuel hedges due to higher fuel prices;

—

an increase of $168 million in incremental realized value of hedges of our generation output. In 2006, the incremental realized value of our hedges contributed $125 million to our gross margin as our power contracts settled at prices higher than market prices for the year, partially offset by hedged fuel costs that were higher than the market. In 2005, our opportunity cost of hedging was $43 million primarily due to the impact of rising energy prices in the latter part of 2005 that resulted in the settlement of power contracts at prices lower than market prices for that year, partially offset by the favorable impact of hedged fuel costs that were generally lower than the market as fuel prices increased in 2005; and

—

a decrease of $97 million in energy primarily related to lower generation volumes. Our decrease in generation volumes was driven by significantly lower volumes generated by our oil-fired units. A decrease in power prices combined with average oil prices that were higher than in 2005 resulted in our oil-fired units not being able to dispatch economically for most of the period.

Operating Expenses

The decrease of $20 million in operating expenses is primarily due to a decrease of $94 million in operations and maintenance, which relates to the New York property tax settlement. Of this amount, $71 million relates to periods prior to 2006. The remaining decrease in property tax expense represents the difference in the 2006 expense under the settlement compared to the 2005 expense that was accrued based on the property tax assessments. Gains on sales of assets increased $36 million due to an increase of $37 million in gains on sales of emissions allowances to affiliates that are eliminated in the consolidated statement of operations. Impairment losses in 2006 represent the impairment of the Bowline unit 3 suspended construction project.

California

The following table summarizes the operations of our California segment for the years ended December 31, 2006 and 2005 (in millions):


	Years Ended December 31,					Increase/ (Decrease)
	2006			2005		Increase/ (Decrease)
Realized Gross Margin	$	112		$	113	$	(1	)
Unrealized Gross Margin		3			—		3

Total Gross Margin		115			113		2

Operating expenses:
Operations and maintenance		63			69		(6	)
Depreciation and amortization		13			5		8

Total operating expenses		76			74		2

Operating income		39			39		—

Total other expense (income), net		(34	)		1		(35	)

Income from continuing operations before reorganization items and income taxes	$	73		$	38	$	35

Gross Margin

Gross margin increased by $2 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):


	Years Ended December 31,						Increase/ (Decrease)
	2006			2005			Increase/ (Decrease)
Energy	$	14		$	—		$	14
Contracted and capacity		101			114			(13	)
Incremental realized value of hedges		(3	)		(1	)		(2	)

Total realized gross margin		112			113			(1	)
Unrealized gross margin		3			—			3

Total gross margin	$	115		$	113		$	2

The increase in our energy gross margin is primarily due to several days of extreme heat in July 2006, which allowed us to earn incremental gross margin on units that were under a tolling agreement for the same period in 2005. The expiration of this tolling agreement is the primary reason for the decrease in our contracted and capacity margin.

Other Expense (Income), net

The decrease of $35 million in other expense, net is primarily due to a gain of $26 million in 2006 related to the transfer of Contra Costa unit 8 to PG&E and an increase of $6 million in interest income. See “California Settlement” in Note 19 to our consolidated financial statements for further discussion.

Other Operations

Other Operations includes proprietary trading, fuel oil management, and gains and losses related to the Back-to-Back Agreement and the transition power agreement with Pepco that expired in January 2005. See “Pepco Litigation” in Note 19 to our consolidated financial statements for further discussion of the Back-to-Back Agreement. The following table summarizes the operations of our Other Operations segment for the years ended December 31, 2006 and 2005 (in millions):


	Years Ended December 31,						Increase/ (Decrease)
	2006			2005			Increase/ (Decrease)
Realized Gross Margin	$	11		$	(34	)	$	45
Unrealized Gross Margin		107			92			15

Total Gross Margin		118			58			60

Operating expenses:
Operations and maintenance		80			64			16
Depreciation and amortization		25			33			(8	)
Impairment losses		1			9			(8	)
Loss (gain) on sales of assets, net		(40	)		19			(59	)

Total operating expenses		66			125			(59	)

Operating income (loss)		52			(67	)		119

Total other expense, net		128			1,414			(1,286	)

Loss from continuing operations before reorganization items and income taxes	$	(76	)	$	(1,481	)	$	1,405

Gross Margin

Gross margin increased by $60 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):


	Years Ended December 31,						Increase
	2006			2005			Increase
Energy	$	71		$	44		$	27
Contracted and capacity		(60	)		(78	)		18

Total realized gross margin		11			(34	)		45
Unrealized gross margin		107			92			15

Total gross margin	$	118		$	58		$	60

The increase in gross margin is primarily due to the following:

—

an increase of $27 million in energy, primarily related to our proprietary trading and fuel oil management activities net of cost or market adjustments on our oil inventory during the third and fourth quarters of 2006;

—

an increase of $18 million in contracted and capacity due to a decrease in realized losses on the Back-to-Back Agreement and the hedges related to this contract, primarily due to the expiration of one of Pepco’s PPAs covered by that agreement; and

—

an increase of $15 million in unrealized gross margin, which includes an increase of $73 million in unrealized gains on our proprietary trading and fuel oil management activities, partially offset by a decrease of $58 million in unrealized gains on the Back-to-Back Agreement and the related hedges.

Operating Expenses

The decrease of $59 million in operating expenses is primarily due to an increase in gain on sales of assets. In 2006, we recognized a $40 million gain from the sale of our remaining claims in the Enron bankruptcy. In 2005, we recognized a $19 million loss on sale of equipment from our Wyandotte suspended construction project.

Other Expense, net

Other expense, net in 2006 includes the interest expense on the debt of Mirant Americas Generation and Mirant North America. The decrease in other expense, net of $1.286 billion is primarily due to the following:

•

in 2005, we recognized $1.2 billion of interest on liabilities subject to compromise for the period from the 2003 petition date through December 2005; and

•

gains on sales of investments increased $31 million. In 2006, we recognized a gain of $54 million related to sales of our investment in InterContinental Exchange and a gain of $19 million on the sale of our two New York Mercantile Exchange seats and shares. In 2005, we recognized a gain of $44 million related to the sale of a portion of our investment in InterContinental Exchange.

Other Significant Consolidated Statements of Operations Comparison

Reorganization Items, net

Reorganization items, net for the years ended December 31, 2006 and 2005, are comprised of the following (in millions):


	Years Ended December, 31,
	2006			2005			Increase/ (Decrease)
Gain on the implementation of the Plan	$	—		$	(285	)	$	285
Gain on the New York property tax settlement		(163	)		—			(163	)
Estimated claims and losses on rejected and amended contracts		—			72			(72	)
Professional fees and administrative expense		2			226			(224	)
Interest income, net		(3	)		(31	)		28

Total	$	(164	)	$	(18	)	$	(146	)

Reorganization items, net decreased by $146 million for the year ended December 31, 2006, compared to 2005, primarily related to the settlement of the New York State property tax disputes. Under the terms of the settlement, in February 2007 we received refunds totaling approximately $163 million for 1995 through 2003 and paid unpaid but accrued taxes of approximately $115 million for 2003 through 2006. For the year ended December 31, 2005, reorganization items, net represent amounts that were recorded in the financial statements as a result of the bankruptcy proceedings.

Estimated claims and losses on rejected and amended contracts relate primarily to rejected energy contracts, such as tolling agreements, gas transportation contracts and electric transmission contracts.

Provision (Benefit) for Income Taxes

The $550 million net benefit for income taxes for the year ended December 31, 2006, is primarily due to the $552 million benefit related to the release of the valuation allowance pertaining to deferred tax assets previously recorded including the estimated value of the NOLs that was used to offset the 2007 taxable gain that resulted

from the sale of the Philippine business in 2007. See Note 7 to the consolidated financial statements for further discussion.

Discontinued Operations

During the third quarter of 2006, we commenced separate auction processes to sell our Philippine and Caribbean businesses and six natural gas-fired facilities in the United States. Accordingly, the results of operations related to the planned sales were reclassified to income (loss) from discontinued operations in our consolidated statements of operations for all periods presented.

For the year ended December 31, 2006, we reported net income from discontinued operations of $112 million, which includes the reclassification of the results of operations related to the planned dispositions and income related to the Wichita Falls facility. Included in income from discontinued operations are the following:

—

an impairment loss of $375 million to write-down the U.S. natural gas-fired assets to estimated fair value;

—

an income tax benefit of $141 million related to the disposition of the Philippine business; and

—

a net tax benefit of $124 million related to the reversal of previously accrued foreign withholding taxes as a result of the decision, based on the pending sale of the Philippine business, to no longer distribute any accumulated earnings in the form of a dividend prior to the closing of the sale.

For the year ended December 31, 2005, we reported net income from discontinued operations of $93 million, which includes the reclassification of the results of operations related to the planned dispositions and income related to the Wichita Falls facility and the Wrightsville generating facility.

At December 31, 2005, we had deferred tax assets of $84 million related to the anticipated future tax benefits of unrealized foreign exchange losses arising from the U.S. dollar denominated borrowings of our Philippine entities. Accordingly, in 2006, we recognized an additional income tax provision of $84 million. We also experienced an increase in the income tax provision of $23 million for the year ended December 31, 2006, related to the effects of the expiration of the Sual tax holiday in 2005, offset by the reversal of a $12 million tax contingency related to prior tax years.

See Note 11 to our consolidated financial statements contained elsewhere in this report for additional information related to discontinued operations.

Liquidity and Capital Resources

Sources of Funds and Capital Structure

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 Mirant North America’s $800 million senior secured revolving credit facility; and (3) $200 million of letter of credit capacity available under the Mirant North America senior secured term loan.

The table below sets forth total cash, cash equivalents and availability of credit facilities of Mirant Corporation and its subsidiaries at December 31, 2007 and 2006 (in millions):


	At December 31,
	2007		2006
Cash and Cash Equivalents:
Mirant Corporation	$	4,232	$	367
Mirant Americas Generation		1		—
Mirant North America		455		675
Mirant Mid-Atlantic		242		75
Other		31		22

Total cash and cash equivalents		4,961		1,139
Less: Cash restricted and reserved for other purposes		15		112

Total available cash and cash equivalents		4,946		1,027
Available under credit facilities		710		796

Total cash, cash equivalents and credit facilities availability	$	5,656	$	1,823

Cash and cash equivalents of discontinued operations	$	—	$	246

We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At 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.

Except for existing cash on hand, Mirant Corporation, Mirant Americas Generation and Mirant North America are dependent on the distributions and dividends of their subsidiaries, or in the case of Mirant Americas Generation and Mirant North America, capital contributions, or in the case of Mirant North America, capacity available under its revolving credit and letter of credit facilities for liquidity. 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 leverage lease documentation, respectively. At December 31, 2007, 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 $697 million at Mirant North America and its subsidiaries. Of this amount, $242 million was held by Mirant Mid-Atlantic which, as of December 31, 2007, met the ratio tests under the leveraged lease documents for distribution of the entire amount to Mirant North America. After taking into account the financial results of Mirant North America for the year ended December 31, 2007, we expect Mirant North America will be able to distribute approximately $65 million to its parent in March 2008.

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

LOGO

A significant portion of cash from our operations is generated by the power generation facilities of Mirant Mid-Atlantic. Under the Mirant Mid-Atlantic leveraged leases, Mirant Mid-Atlantic is subject to a covenant that restricts its right to make distributions to Mirant North America. Mirant Mid-Atlantic’s ability to satisfy the criteria set by that covenant in the future could be impaired by factors which negatively affect the performance of its power generation facilities, including interruptions in operation or curtailment of operations to comply with environmental restrictions.

Mirant North America is an intermediate holding company that is a subsidiary of Mirant Americas Generation and the parent of its indirect subsidiaries, including Mirant Mid-Atlantic. Mirant North America incurred certain indebtedness pursuant to its senior notes and senior secured credit facilities secured by the assets of Mirant North America and its subsidiaries (other than Mirant Mid-Atlantic and Mirant Energy Trading). The indebtedness of Mirant North America includes certain covenants typical in such notes and credit facilities, including restrictions on dividends, distributions and other restricted payments. Further, the notes and senior secured credit facilities include financial covenants that will exclude from the calculation the financial results of any subsidiary that is unable to make distributions or dividends at the time of such calculation. Thus, the ability of Mirant Mid-Atlantic to make distributions to Mirant North America under the leveraged lease transaction could have a material effect on the calculation of the financial covenants under the senior notes and senior secured credit facilities of Mirant North America and on its ability to make distributions to Mirant Americas Generation.

The ability of Mirant Americas Generation to pay its obligations is dependent on the receipt of dividends from Mirant North America, capital contributions from Mirant Corporation and its ability to refinance all or a portion of those obligations as they become due.

Maintaining sufficient liquidity in our business is crucial in order to mitigate the risk of future financial distress to us. Accordingly, we plan on a prospective basis for the expected liquidity requirements of our business considering the factors listed below:

—

expected expenditures with respect to maintenance activities and capital improvements, and related outages;

—

expected collateral posted in support of our business;

—

effects of market price volatility on the amount of collateral posted for economic hedge transactions and risk management transactions;

—

effects of market price volatility on fuel pre-payment requirements;

—

seasonal and intra-month working capital requirements; and

—

debt service obligations.

Our operating cash flows may be affected by, among other things: (1) demand for electricity; (2) the difference between the cost of fuel used to generate electricity and the market value of the electricity generated; (3) commodity prices (including prices for electricity, emissions allowances, natural gas, coal and oil); (4) the cost of ordinary course operations and maintenance expenses; (5) planned and unplanned outages; (6) terms with trade creditors; and (7) cash requirements for capital expenditures relating to certain facilities (including those necessary to comply with environmental regulations).

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) the return of cash to stockholders; (2) capital expenditures required to keep our power generating facilities in operation; (3) debt service; (4) our asset management and proprietary trading activities; and (5) the Mirant Mid-Atlantic operating leases.

Return of Cash to Stockholders. We plan to return a total of $4.6 billion of excess cash to our stockholders. The first stage of the cash distribution is being 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, in conjunction with the accelerated share repurchase program, we repurchased approximately 26.66 million shares of our common stock for $1 billion. See Note 13 to our consolidated financial statements contained elsewhere in this report for further discussion. In addition, we purchased approximately 8.27 million shares of our common stock for approximately $316 million through open market purchases. Between January 1, 2008 and February 25, 2008, we purchased an additional 7.9 million shares in open market purchases for approximately $286 million. 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.

Capital Expenditures. Capital expenditures excluding capitalized interest for our continuing operations were $560 million, $133 million and $101 million for the years ended December 31, 2007, 2006 and 2005, respectively. Our capital expenditures for 2008, 2009 and 2010 are expected to be approximately $975 million, $527 million and $284 million, respectively. This forecast does not assume any construction of new generating units during the forecast period. Instead, the current capital expenditure program, which is expected to be funded by cash on hand and operating cash flow, focuses on efficiency, safety, reliability and compliance with existing environmental laws and obligations under consent decrees to which the Company is a party, including capital expenditures made to comply with the limitations for SO2 and NOx emissions under the Maryland Healthy Air Act. For a more detailed discussion of environmental expenditures we expect to incur in the future, see Item 1. Business.

Debt Service. At December 31, 2007, we had $3.095 billion of long-term debt with expected interest expense of approximately $237 million for 2008. In the fourth quarter of 2007, we purchased and retired $39 million of Mirant Americas Generation senior notes due in 2011.

Under the terms of its senior secured term facility, Mirant North America is required to use 50% of its free cash flow for each fiscal year (less amounts paid to Mirant Americas Generation for the purpose of paying interest on the Mirant Americas Generation senior notes) to pay down its senior secured term loan, in addition to its scheduled amortization of $7 million per year. The percentage of free cash flow that Mirant North America is required to use to pay down its senior secured term loan may be reduced to 25% upon the achievement by it of a net debt to EBITDA ratio of less than 2:1. At December 31, 2007, Mirant North America’s net debt to EBITDA was less than 2:1. As such, it was required to use 25% of its free cash flow to pay down its senior secured term loan. We estimate this prepayment, which will be made during the first quarter of 2008, to be $132 million.

Mirant Mid-Atlantic Operating Leases. Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively. Mirant Mid-Atlantic has an option to extend the leases. Any extensions of the respective leases would be limited to 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. We are accounting for these leases as operating leases. While there is variability in the scheduled payment amounts over the lease term, we recognize rent expense for these leases on a straight-line basis in accordance with the applicable accounting literature. As of December 31, 2007, the total notional minimum lease payments for the remaining term of the leases aggregated approximately $2.1 billion and the aggregate termination value for the leases was approximately $1.4 billion and generally decreases over time. Rent expense under the Mirant Mid-Atlantic leases was $96 million for the years ended December 31, 2007 and 2006 and $99 million for the year ended December 31, 2005. In addition, Mirant Mid-Atlantic is required to post rent reserves in an aggregate amount equal to the greater of the next six months’ rent, fifty percent of the next 12 months’ rent or $75 million.

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 are often required to provide trade credit support to our counterparties or make deposits with brokers. In addition, we are often required to provide cash collateral or letters of credit for access to 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 December 31, 2007, we had approximately $110 million of posted cash collateral and $290 million of letters of credit outstanding primarily to support our asset management activities, debt service and rent reserve requirements and other commercial arrangements. Of the letters of credit outstanding at December 31, 2007, $199 million was posted by Mirant North America under its senior secured term loan and the remainder was issued under Mirant North America’s $800 million senior secured revolving credit facility. Our liquidity requirements are highly dependent on the level of our hedging activity, forward prices for energy, emissions allowances and fuel, commodity market volatility and credit terms with third parties. See Note 10 to our consolidated financial statements contained elsewhere in this report for additional information.

The following table summarizes at December 31, 2007 and 2006, for our continuing operations, cash collateral posted with counterparties and brokers and letters of credit issued (in millions):


	At December 31,
	2007		2006
Cash collateral posted—energy trading and marketing	$	96	$	27
Cash collateral posted—other operating activities		14		13
Letters of credit—energy trading and marketing		100		100
Letters of credit—debt service and rent reserves		78		84
Letters of credit—other operating activities		112		15

Total	$	400	$	239

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

Our debt obligations, off-balance sheet arrangements and contractual obligations as of December 31, 2007, are as follows (in millions):


	Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations by Year
	Total		2008		2009		2010		2011		2012		>5 Years
Operating:
Mirant Mid-Atlantic operating leases	$	2,133	$	121	$	142	$	140	$	134	$	132	$	1,464
Other operating leases		70		10		10		10		9		8		23
Fuel commitments		506		314		192		—		—		—		—
Long-term service agreements		31		2		2		2		2		5		18
Other		153		153		—		—		—		—		—

Investing :
Maryland Healthy Air Act		713		689		24		—		—		—		—

Financing:
Long-term Debt		5,222		379		243		245		1,012		174		3,169

Total payments	$	8,828	$	1,668	$	613	$	397	$	1,157	$	319	$	4,674

Operating leases are off-balance sheet arrangements. These amounts primarily relate to our minimum lease payments associated with our lease of the Morgantown and Dickerson baseload units at our Mid-Atlantic facilities.

Fuel commitments primarily relate to long-term coal agreements and other fuel purchase agreements. As of December 31, 2007, our total estimated fuel commitments were $506 million. In addition, we have transactions for which commercial terms have been negotiated but for which contracts have not yet been executed. Individual transactions may or may not be binding prior to execution of a contract.

As of December 31, 2007, the total estimated commitments under LTSAs associated with turbines were approximately $31 million. These commitments are payable over the terms of the respective agreements, which range from 10 to 20 years. These agreements have terms that allow for cancellation of the contracts by us upon the occurrence of certain events during the term of the contracts. Estimates for future commitments for the LTSAs are based on the stated payment terms in the contracts at the time of execution. These payments are subject to an annual adjustment for inflation.

Other represents open purchase orders less invoices received related to open purchase orders for general procurement of products and services purchased in the ordinary course of business. These include construction, maintenance and labor activities at our generating facilities.

Maryland Healthy Air Act commitments are contracts and open purchase orders related to capital expenditures that we will incur to comply with the limitations for SO2 and NOx emissions under the Maryland Healthy Air Act.

Long-term debt includes the current portion of long-term debt and long-term debt on the consolidated balance sheets. Long-term debt also includes estimated interest on debt based on the U.S. Dollar LIBOR curve as of December 31, 2007.

Cash Flows

The changes in our cash flows are detailed as follows (in millions):


	Years Ended December 31,
	2007			2006			Increase/ (Decrease)			2006			2005			Increase/ (Decrease)
Cash and cash equivalents, beginning of period	$	1,385		$	1,551		$	(166	)	$	1,551		$	1,485		$	66
Net cash provided by (used in) operating activities:
Continuing operations		786			137			649			137			(388	)		525
Discontinued operations		178			432			(254	)		432			421			11
Net cash provided by (used in) investing activities:
Continuing operations		(524	)		5			(529	)		5			64			(59	)
Discontinued operations		5,281			(163	)		5,444			(163	)		15			(178	)
Net cash provided by (used in) financing activities:
Continuing operations		(1,477	)		(758	)		(719	)		(758	)		97			(855	)
Discontinued operations		(669	)		181			(850	)		181			(142	)		323
Effect of exchange rate changes		1			—			1			—			(1	)		1

Cash and cash equivalents, end of period	$	4,961		$	1,385		$	3,576		$	1,385		$	1,551		$	(166	)

2007 versus 2006

Continuing Operations

Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash provided by operating activities from continuing operations increased $649 million for the year ended December 31, 2007, compared to 2006, primarily as a result of the following:

—

an increase in realized gross margin of $362 million for the year ended December 31, 2007, compared to 2006. See “Results of Operations” for additional discussion of our performance in 2007 compared to 2006;

—

an increase of $761 million resulting from a reduction in bankruptcy related claims and expenses. In 2007, we paid $17 million in claims payable for the New York entities, $32 million related to MC Asset Recovery and $4 million related to other Mirant claims. In 2006, we paid $1.804 billion of bankruptcy claims, of which $814 million was reflected in cash from operations;

—

an increase of $140 million related to the Settlement Agreement with Pepco becoming fully effective in the third quarter of 2007. Pepco repaid $70 million in 2007 for an advance payment made in the third quarter of 2006 under the Settlement Agreement. These amounts are included in other assets in the consolidated statements of cash flows;

—

an increase of $155 million related to increases in net interest income as a result of higher cash balances resulting from the dispositions completed in 2007;

—

an increase from the receipt in 2007 of a net refund of $48 million related to the New York property tax settlement, which is included in receivables, net in the consolidated statements of cash flows; partially offset by

—

a decrease of $516 million as a result of changes in posted collateral levels, which are included in funds on deposit in the consolidated statements of cash flows. For the year ended December 31, 2007, we posted an additional $70 million of cash collateral primarily to support energy marketing activities. The change in collateral for the year ended December 31, 2006, provided a source of cash of $446 million

primarily because of a decrease in cash collateral to support energy marketing activities of $592 million, and a reduction of $56 million in cash collateral posted in connection with the Mirant Mid-Atlantic lease upon posting $75 million of letters of credit. These amounts were partially offset by a use of cash as a result of the deposit of $200 million into a cash collateral account to support the issuance of letters of credit;

—

a decrease of $77 million resulting from an increase in operations and maintenance expenses. See results of operations for additional discussion;

—

a decrease of $61 million primarily related to changes in our fuel oil and emissions inventories. In 2007, fuel inventory increased $84 million and emissions inventory decreased $18 million. In 2006, fuel inventory decreased $6 million and emissions inventory increased $14 million;

—

a decrease of $60 million primarily a result of the return in 2007 of deposits previously posted by our counterparties which is included in accounts payable and accrued liabilities in the consolidated statements of cash flows;

—

a decrease of $65 million relating to changes in net accounts receivable and accounts payable in 2007 compared to 2006; and

—

a decrease of $38 million related to all other changes in operating assets and liabilities.

Investing Activities. Net cash used in investing activities from continuing operations increased by $529 million for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the following:

—

an increase of $427 million in capital expenditures and $22 million in capitalized interest primarily because of our environmental capital expenditures for our Mid-Atlantic generating facilities; and

—

a decrease in proceeds from the sales of assets and investments of $86 million. In 2007, we received proceeds from the sale of assets of $57 million, which included approximately $30 million from the sale of ancillary equipment included in the sale of six U.S. natural gas-fired facilities and $22 million from the sale of equipment from the Bowline unit 3 suspended construction project. In 2006, we received $143 million from the sale of assets, which included $45 million from the sale of our remaining bankruptcy claims against Enron and its subsidiaries and $58 million from the sale of a portion of our investment in InterContinental Exchange.

Financing Activities. Net cash used in financing activities from continuing operations increased by $719 million for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the following:

—

a decrease in proceeds from the issuance of long-term debt of $2.017 billion. Proceeds from the issuance of long-term debt in 2006 included $850 million from the Mirant North America debt offering, $700 million from the Mirant North America senior secured term loan and $465 million drawn on the Mirant North America senior secured revolving credit facility;

—

a decrease in the repayments of long-term debt of $1.285 billion, which includes $990 million of principal payments for debt settled under the Plan in 2006. In 2007, we paid $138 million on the Mirant North America senior secured term loan and repurchased $39 million of the Mirant Americas Generation 8.3% senior notes due in 2011. In 2006, we repaid $465 million on the Mirant North America senior secured revolving credit facility and $990 million of principal payments for debt settled under the Plan in 2006;

—

a decrease in debt issuance costs of $51 million. In 2006, we paid $51 million in debt issuance costs associated with Mirant North America’s debt offering, senior secured term loan and secured revolving credit facility; and

—

an increase of $47 million used for stock repurchases. In 2007, stock repurchases included 26.66 million shares of Mirant common stock for $1 billion under the accelerated share repurchase

program, 8.27 million shares of Mirant common stock under the open market share repurchase program for approximately $316 million, of which $17 million had not yet been paid as of December 31, 2007, and approximately 245,000 shares of Mirant common stock in odd lot buybacks for approximately $9 million. In 2006, we repurchased 43 million shares of our common stock for $1.228 billion pursuant to a tender offer in 2006 and 1.18 million shares for approximately $32 million under the share repurchase program.

Discontinued Operations

Operating Activities. Net cash provided by operating activities from discontinued operations decreased by $254 million for the year ended December 31, 2007, compared to 2006. In 2006, operating activities included cash flows from the Philippine and Caribbean businesses and six U.S. natural gas-fired facilities for the entire year. In 2007, operating activities included all the discontinued businesses and facilities through their respective dates of sale.

Investing Activities. Net cash provided by investing activities from discontinued operations increased by $5.444 billion for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the following:

—

an increase of $5.410 billion in proceeds from the sale of assets and investments, primarily from the sale of our Philippine and Caribbean businesses and six U.S. natural gas-fired facilities in the second and third quarters of 2007;

—

a decrease of $65 million in cash that was included in the assets sold as part of the Philippine business;

—

a decrease of $47 million in cash that was included in the assets sold as part of the Caribbean business;

—

an increase related to the purchases in 2006 of the remaining 5.15% ownership in Mirant Sual for $35 million and the remaining 4.26% interest in Mirant Pagbilao for $40 million; and

—

an increase as a result of funding in 2006 of $24 million in accordance with the terms and conditions of a stockholder loan agreement for the construction and installation of new generating units at Point Lisas, Trinidad.

Financing Activities. Net cash used in financing activities from discontinued operations increased by $850 million for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the following:

—

a decrease of $78 million in repayments of long-term debt. In 2007, we repaid $700 million related to our Philippine business, $83 million related to West Georgia and $14 million related to our Caribbean business. In 2006, we repaid $551 million related to our Philippine business, $268 million related to our Caribbean business, $56 million related to West Georgia and $2 million related to Zeeland;

—

a decrease of $981 million in proceeds from the issuance of long-term debt primarily from the issuance of $700 million by Mirant Asia-Pacific, $100 million by Mirant Trinidad Investments and $180 million by Mirant JPSCO Finance Ltd. in 2006;

—

a decrease in debt issuance costs of $40 million primarily related to the Philippines; and

—

a decrease in the release of cash deposited in debt service reserves of $10 million.

Cash Flows

2006 versus 2005

Continuing Operations

Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash provided by operating activities from continuing operations increased $525 million for the year ended December 31, 2006, compared to the same period in 2005, primarily due to the following:

—

an increase in realized gross margin of $429 million for the year ended December 31, 2006, compared to the same period in 2005. See “Results of Operations” for additional discussion of our improved performance in 2006 compared to the same period in 2005;

—

a decrease in energy trading collateral levels of $819 million in the year ended December 31, 2006, compared to the same period in 2005. The change in collateral requirements was due to the settlement of energy contracts combined with energy price declines in the year ended December 31, 2006, compared to the same period in 2005. For the year ended December 31, 2006, $592 million of cash collateral from brokers and counterparties was returned to us. For the year ended December 31, 2005, additional net collateral used to support commercial operations was $227 million;

—

an increase in bankruptcy related claims and expenses of $643 million. In 2006 we paid bankruptcy claims of $1.804 billion, of which $814 million was reflected in cash from operations. Our remaining claims payable and estimated claims accrual was $28 million at December 31, 2006. We paid $171 million in the year ended December 31, 2005 related to professional fees and other expenses associated with the bankruptcy proceedings; and

—

a remittance of $70 million to Pepco in the third quarter of 2006. See Note 19 to our consolidated financial statements for further discussion of the settlement agreement with Pepco.

Investing Activities. Net cash provided by investing activities from continuing operations decreased by $59 million for the year ended December 31, 2006, compared to 2005. This difference was primarily due to the following:

—

a decrease in proceeds from the sales of assets and investments of $22 million. In 2006, we received $143 million in proceeds from the sale of assets and investments, which included $45 million from the sale of bankruptcy claims against Enron and its subsidiaries, $12 million from the sale of the Mirant Service Center in Maryland and $58 million from sales of a portion of our investment in InterContinental Exchange. In 2005, proceeds from sales of assets and investments were $165 million and included $63 million in proceeds from the sale of Coyote Springs 2, $48 million from the sale of a portion of our investment in InterContinental Exchange, $4 million in additional proceeds from the 2004 sale of Bowline gas turbines and $44 million from the sale of Wyandotte’s equipment and turbines; and

—

an increase of $32 million in capital expenditures and $6 million in capitalized interest for 2006 as compared to 2005, primarily due to our environmental capital expenditures in 2006 in the Mid-Atlantic.

Financing Activities. Net cash used in financing activities from continuing operations increased by $855 million for the year ended December 31, 2006, compared to 2005. This difference was primarily due to the following:

—

the purchase of 43 million shares of our common stock for approximately $1.228 billion pursuant to our tender offer during the third quarter of 2006 and an additional 1.18 million shares for $32 million under a share repurchase plan in the fourth quarter of 2006;

—

an increase in repayments of long-term debt comprised of the repayment of $465 million on the Mirant North America senior secured revolving credit facility and $990 million of principal payments for debt settled under the Plan; and

—

an increase in proceeds from the issuance of long-term debt of approximately $2 billion. Proceeds from the issuance of long-term debt in 2006 included $850 million from the Mirant North America debt offering that was released from escrow on January 3, 2006, $700 million from the Mirant North America senior secured loan, and $465 million drawn on the Mirant North America senior secured revolving credit facility. In 2005, proceeds from the issuance of long-term debt represented pre-petition letters of credit being drawn upon by counterparties and banks.

Discontinued Operations

Operating Activities. Net cash provided by operating activities from discontinued operations increased $11 million for the year ended December 31, 2006, compared to the same period in 2005, primarily as a result of the following:

—

an increase of $62 million related to a decrease in restricted cash of our West Georgia subsidiary; and

—

a decrease of $26 million due to an increase in payments for interest and taxes, primarily due to the expiration of the Sual tax holiday.

Investing Activities. Net cash used in investing activities from discontinued operations increased by $178 million for the year ended December 31, 2006, compared to 2005. This difference was primarily due to the following:

—

the purchase in 2006 of the remaining 5.15% ownership in the Sual generating facility for $35 million and the purchase of the remaining 4.26% interest in Pagbilao facility for $40 million;

—

a decrease of $82 million from the sale of assets and investments, primarily related to the sale of the Wrightsville assets in 2005; and

—

$30 million in funding by Mirant Trinidad Investments during 2006 for the construction and installation of new generating units at Point Lisas, Trinidad.

Financing Activities. Net cash provided by financing activities from discontinued operations increased by $323 million for the year ended December 31, 2006, compared to 2005. This difference was primarily due to the following:

—

an increase in proceeds from the issuance of $700 million of long-term debt related to the Philippines, $100 million by Mirant Trinidad Investments, $180 million by Mirant JPSCO Finance LTD and $9 million by Grand Bahama Power Company; partially offset by

—

an increase of $678 million of repayments of long-term debt primarily due to the repayment in 2006 of $551 million of existing debt related to Mirant Pagbilao and Mirant Sual, $186 million by JPS, $73 million by Mirant Trinidad Investments and $56 million by West Georgia.

Critical Accounting Estimates

The accounting policies described below are considered critical to obtaining an understanding of our consolidated financial statements because their application requires significant estimates and judgments by management in preparing our consolidated financial statements. Management’s estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the following conditions apply:

—

the estimate requires significant assumptions; and

—

changes in the estimate could have a material effect on our consolidated results of operations or financial condition; or

—

if different estimates that could have been selected had been used, there could be a material effect on our consolidated results of operations or financial condition.

We have discussed the selection and application of these accounting estimates with the Audit Committee of the Board of Directors and our independent auditors. It is management’s view that the current assumptions and other considerations used to estimate amounts reflected in our consolidated financial statements are appropriate. However, actual results can differ significantly from those estimates under different assumptions and conditions. The sections below contain information about our most critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop the estimates.

Revenue Recognition and Accounting for Energy Trading and Marketing Activities

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

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

The fair value model has historically been used for derivative energy contracts that economically hedge our electricity generating facilities or that are used in our proprietary trading activities. We use a variety of derivative contracts, such as 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 a number of 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. We deferred inception gains and losses in accordance with EITF 02-3 for the periods presented. Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of completing forecasted transactions 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 consolidated balance sheets. Transactions that do not qualify for accounting under SFAS 133, either because they are not derivatives or because they qualify for a scope exception, are accounted for under accrual accounting as described above.

Key Assumptions and Approach Used. Determining the fair value of derivatives involves significant estimates based largely on the mid-point of quoted prices in active markets. The mid-point may vary significantly from the bid or ask price for some delivery points. If no active market exists, we estimate the fair value of certain derivative contracts using quantitative pricing models. Fair value estimates involve uncertainties and matters of significant judgment. Our modeling techniques for fair value estimation include assumptions for market prices, supply and demand market data, correlation and volatility. The degree of complexity of our pricing models increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points.

The fair value of price risk management assets and liabilities in our consolidated balance sheets is also affected by our assumptions as to interest rate, counterparty credit risk and liquidity 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 risk of default of counterparties on their contractual obligations to us.

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. As a result of the complexity of the models used to value some of the derivative instruments each period, a significant change in estimate could have a material effect on our results of operations and cash flows at the time contracts are ultimately settled. Upon the adoption of SFAS 157 on January 1, 2008, we will no longer defer inception gains and losses. Additionally, we will incorporate our own credit standing in the fair value measurement of our liabilities. Upon the adoption of FSP FIN 39-1 on January 1, 2008, we will net cash collateral in the measurement of the fair value of our derivative contracts under master netting arrangements. See Note 4 to our consolidated financial statements contained elsewhere in this report for further information on financial instruments related to energy trading and marketing activities.

For additional information regarding accounting for derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Long-Lived Assets

Estimated Useful Lives

Nature of Estimates Required. The estimated useful lives of our long-lived assets are used to compute depreciation expense, determine the carrying value of asset retirement obligations, and estimate expected future cash flows attributable to an asset for the purposes of impairment testing. Estimated useful lives are based, in part, on the assumption that we provide an appropriate level of capital expenditures while the assets are still in operation. Without these continued capital expenditures, the useful lives of these assets could decrease significantly.

Key Assumptions and Approach Used. Estimated useful lives are the mechanism by which we allocate the cost of long-lived assets over the asset’s service period. We perform depreciation studies periodically to update changes in estimated useful lives. The actual useful life of an asset could be affected by changes in estimated or actual commodity prices, environmental regulations, various legal factors, competitive forces and our liquidity and ability to sustain required maintenance expenditures and satisfy asset retirement obligations. We use composite depreciation for groups of similar assets and establish an average useful life for each group of related assets. In accordance with SFAS 144, we cease depreciation on long-lived assets classified as held for sale. Also, we may revise the remaining useful life of an asset held and used subject to impairment testing. See Note 5 to our

consolidated financial statements contained elsewhere in this report for additional information related to our property, plant and equipment.

Effect if Different Assumptions Used. The determination of estimated useful lives is dependent on subjective factors such as expected market conditions, commodity prices and anticipated capital expenditures. Since composite depreciation rates are used, the actual useful life of a particular asset may differ materially from the useful life estimated for the related group of assets. In the event the useful lives of significant assets were found to be shorter than originally estimated, depreciation expense may increase, liabilities recognized for future asset retirement obligations may be insufficient and impairments in the carrying value of tangible and intangible assets may result.

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 $44 million recorded as of December 31, 2007. 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.

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. However, as a result of changes in inflation assumptions, interest rates and asset useful lives, actual future cash flows required to satisfy asset retirement obligations could differ materially from the current recorded liabilities.

Asset Impairments

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

Property, Plant and Equipment and Definite-Lived Intangibles

SFAS 144 requires management to recognize an impairment charge if the sum of the undiscounted expected future cash flows from a long-lived asset or definite-lived intangible is less than the carrying value of that asset. We evaluate our long-lived assets (property, plant and equipment) and definite-lived intangibles for impairment whenever indicators of impairment exist or when we commit to sell the asset. These evaluations of long-lived assets and definite-lived intangibles may result from significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a

significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses. If the carrying amount is not recoverable, an impairment charge is recorded.

Key Assumptions and Approach Used. The fair value of an asset is the amount at which the asset could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, when available. In the absence of quoted prices for identical or similar assets, fair value is estimated using various internal and external valuation methods. These methods include discounted cash flow analyses and reviewing available information on comparable transactions. The determination of fair value requires management to apply judgment in estimating future energy prices, environmental and maintenance expenditures and other cash flows. Our estimates of the fair value of the assets include significant assumptions about the timing of future cash flows, remaining useful lives and selecting a discount rate that reflects the risk inherent in future cash flows.

In 2006, our assessment of the Bowline unit 3 suspended construction project resulted in the conclusion that the Bowline 3 project as configured and permitted was not economically viable. As a result of this conclusion, we determined the estimated value of the equipment and project termination liabilities. The carrying value of the development and construction costs for Bowline unit 3 exceeded the estimated undiscounted cash flows from the abandonment of the project. We recorded an impairment of $120 million, which is reflected in impairment losses on the consolidated statements of operations for the year ended December 31, 2006.

As a result of entering into the amendment to the 2003 Consent Decree and the Tax Assessments Agreement, we tested the recoverability of the Lovett facility under SFAS 144 in the second quarter of 2007. Our estimate of cash flows related to our impairment analysis of our Lovett generating facility involved considering scenarios for the future expected operation of the Lovett facility. The most likely scenario considered was the shutdown of unit 5 by April 30, 2008, according to the amended 2003 Consent Decree. We also considered a scenario that assumes operations, utilizing coal as the primary fuel source, through 2012 to allow the Lovett facility to continue to contribute to the reliability of the electric system of the State of New York. As a result of the analysis, we recorded an impairment of long-lived assets of $175 million in the second quarter of 2007 to reduce the carrying value of the Lovett facility to its estimated fair value. There have been no significant changes to the assumptions used in the impairment analysis since the second quarter of 2007.

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

See Note 5 to our consolidated financial statements contained elsewhere in this report for additional information on impairments.

Stock-Based Compensation

Nature of Estimates Required. We account for stock-based compensation under SFAS 123R. SFAS 123R requires companies to recognize in the income statement the grant-date fair value of stock options and other equity-based compensation issued to employees. We consider the assumptions inherent in our valuation and calculation of compensation expense critical to our 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 option’s fair value. The expected term and expected volatility often have the most effect on the fair value of the option. The inputs to the Black-Scholes model that we used for the years ended December 31, 2007 and 2006, are detailed below:


	2007		2006
	Range	Weighted Average	Range	Weighted Average
Expected volatility	15-28%	19.9%	21 –37%	31.6%
Expected dividends	—%	—%	—%	—%
Expected term
Service condition awards	2.7-3.5 years	3.48 years	5.2 - 6 years	5.9 years
Performance condition awards	—	—	3 years	3 years
Risk-free rate	4 - 4.7%	4%	4.3 - 5.1%	4.5%

We use Mirant’s own implied volatility of its traded options in accordance with SAB 107. Additionally, we assumed there would 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 New York Stock Exchange 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 2007 and 2006 qualify for equity accounting treatment under SFAS No. 123R. 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 reflects actual forfeitures and estimated average annual forfeitures of 5%. For the years ended December 31, 2007 and 2006, we recognized approximately $29 million and $17 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 share-based payment accounting could result in material changes to our consolidated financial statements if different assumptions were used. Compensation expense recognized for stock options would differ to the extent other assumptions were used in the valuation of options. 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 8 to our consolidated financial statements contained elsewhere in this report for additional information on stock-based compensation.

Income Taxes

Nature of Estimates Required. We currently record a tax provision for foreign, state and federal income taxes including any alternative minimum tax as appropriate. We also recognize deferred tax assets and liabilities based on the difference between the balance sheet carrying amounts and the tax basis of the assets and liabilities. We must assess the likelihood that our deferred tax assets will be recoverable based on expected future taxable income. To the extent that we determine it is more likely than not (greater than 50%) that some portion or all of

the deferred tax assets will not be realized, we must establish a valuation allowance. See Note 7 to our consolidated financial statements contained elsewhere in this report for additional information regarding our deferred tax assets and the application of our NOLs.

Key Assumptions and Approach Used. The determination of a valuation allowance requires significant judgment as to the generation of taxable income during future periods for which temporary differences are expected to be deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies. Our view is that future sources of taxable income, reversing temporary differences and implemented tax planning strategies will be sufficient to realize deferred tax assets for which no valuation allowance has been established.

Additionally, we have not recognized any tax benefits relating to tax uncertainties arising in the ordinary course of business that are less than or subject to the measurement threshold of the more-likely-than-not standard prescribed under FIN 48. These unrecognized tax benefits may be either a tax liability or an adjustment to our NOLs based on the specific facts of each tax uncertainty. We periodically assess our tax uncertainties based on the latest information available. The amount of the unrecognized tax benefit requires management to make significant assumptions about the expected outcomes of certain tax positions included in our filed or yet to be filed tax returns. See Note 7 to our consolidated financial statements contained elsewhere in this report for information about our January 1, 2007, adoption of FIN 48.

Effect if Different Assumptions Used. At December 31, 2006, we considered it to be more likely than not that we would elect NOL treatment under Internal Revenue Code Section (“§”) 382(l)(5). As a result of further tax planning, we made the decision to elect §382(l)(6) in our 2006 income tax return that we filed on September 15, 2007. As a result, our recorded deferred income tax items, including our pre-emergence NOLs, are presented in accordance with the §382(l)(6) treatment at December 31, 2007. This change had no net effect on the consolidated balance sheets or consolidated statements of operations because the increase in deferred tax asset NOLs was equally offset by an increase in the related deferred tax asset valuation allowance. The December 31, 2006, NOL balance under §382(l)(6) was $3.2 billion as adjusted for the effect of the Mirant Asia-Pacific check-the-box election discussed below.

Under §382(l)(6), we will be subject to an annual limitation on the use of the pre-emergence NOLs, including the effect of net unrealized built-in gains. The NOLs under this election will not be subject to any previous adjustments for interest accrued on debt settled with stock as required under §382(l)(5). We also elected in our 2006 tax return to reduce the income tax basis of depreciable assets for any cancellation of debt income that arises from making the §382(l)(6) election.

On March 15, 2007, we filed a check-the-box election under which Mirant Asia-Pacific will be treated as a corporation for U.S. federal income tax purposes effective January 1, 2007. As a result of this election, we recognized a taxable gain for U.S. federal income tax purposes in 2006, which was fully offset by other deductions and losses arising in that year.

We continue to be under audit for multiple years by taxing authorities in various jurisdictions. Considerable judgment is required to determine the tax treatment of particular items that involves interpretations of complex tax laws. A tax liability has been recorded for certain filing positions with respect to which the outcome is uncertain and the effect is estimable. Such liabilities are based on judgment and it can take many years between the time the liability is recorded and the related filing position is no longer subject to question.

Loss Contingencies

Nature of Estimates Required. We record loss contingencies when it is probable that a liability has been incurred and the amount can be reasonably estimated. We consider loss contingency estimates to be critical accounting estimates because they entail significant judgment regarding probabilities and ranges of exposure, and

the ultimate outcome of the proceedings is unknown and could have a material adverse effect on our results of operations, financial condition and cash flows. We currently have loss contingencies related to litigation, environmental matters, tax matters and others.

Key Assumptions and Approach Used. The determination of a loss contingency requires significant judgment as to the expected outcome of each contingency in future periods. In making the determination as to potential losses and probability of loss, we consider all available positive and negative evidence including the expected outcome of potential litigation. 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 the contingency and revise our estimates. In our evaluation of legal matters, management holds discussions with applicable legal counsel and relies on analysis of case law and legal precedents.

Effect if Different Assumptions Used. Revisions in our estimates of potential liabilities could materially affect our results of operations and the ultimate resolution may be materially different from the estimates that we make.

Litigation

See Note 18 to our consolidated financial statements contained elsewhere in this report for further information related to our legal proceedings.

We are currently involved in various 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 7A.

Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risks associated with commodity prices, interest rates and credit risk.

Commodity Price Risk

In connection with our business of generating electricity, we are exposed to energy commodity price risk associated with the acquisition of fuel needed to generate electricity, as well as the price of electricity produced and sold. A portion of our fuel requirements is purchased in the spot market and a portion of the electricity we produce is sold in the spot market. In addition, the open positions in our proprietary trading activities expose us to risks associated with changes in energy commodity prices. As a result, our financial performance varies depending on changes in the prices of energy and energy-related commodities. See “Critical Accounting Estimates” for a discussion of the accounting treatment for proprietary trading and asset management activities.

The financial performance of our business of generating electricity is influenced by the difference between the variable cost of converting a fuel, such as natural gas, oil or coal, into electricity, and the revenue we receive from the sale of that electricity. The difference between the cost of a specific fuel used to generate one MWh of electricity and the market value of the electricity generated is commonly referred to as the “conversion spread.” Absent the effects of our price risk management activities, the operating margins that we realize are equal to the difference between the aggregate conversion spread and the cost of operating the facilities that produce the electricity sold.

Conversion spreads are dependent on a variety of factors that influence the cost of fuel and the sales price of the electricity generated over the longer term, including conversion spreads of other generating facilities in the regions in which we operate, facility outages, weather and general economic conditions. As a result of these influences, the cost of fuel and electricity prices do not always change in the same magnitude or direction, which results in conversion spreads for a particular generating facility widening or narrowing (or becoming negative) over any given period.

Through our asset management activities, we enter 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 our 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. Our proprietary trading activities also utilize similar contracts in markets where we have a physical presence to attempt to generate incremental gross margin.

Derivative energy contracts that are required to be reflected at fair value are presented as price risk management assets and liabilities in the accompanying consolidated balance sheets. The net changes in their market values are recognized in income in the period of change. The determination of fair value considers various factors, including closing exchange or OTC market price quotations, time value, credit quality, liquidity and volatility factors underlying options.

The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at December 31, 2007, was approximately 12 months. The net notional amount, or net short position, of the price risk management assets and liabilities at December 31, 2007, was approximately 26 million equivalent MWh.

The following table provides a summary of the factors affecting the change in net fair value of the price risk management asset and (liability) accounts in 2007 (in millions):


	Proprietary Trading and Fuel Oil Management			Asset Management			Back-to- Back Agreement			Total
Net fair value of portfolio at December 31, 2006	$	106		$	384		$	(425	)	$	65
Gains (losses) recognized in the period, net		13			(195	)		84			(98	)
Contracts settled during the period, net		(115	)		(323	)		—			(438	)
Settlement of the Back-to-Back Agreement		—			—			341			341

Net fair value of portfolio at December 31, 2007	$	4		$	(134	)	$	—		$	(130	)

The Settlement Agreement with the Pepco Settling Parties dated May 30, 2006, became fully effective August 10, 2007, and as a result the Back-to-Back Agreement was rejected and terminated. See Note 19 to our consolidated financial statements contained elsewhere in this report for further information about the Settlement Agreement.

The fair values of our price risk management assets and liabilities, net of credit reserves, as of December 31, 2007, are as follows (in millions):


	Net Price Risk Management
	Assets					Liabilities						Net Fair Value at December 31, 2007
	Current			Noncurrent		Current			Noncurrent			Net Fair Value at December 31, 2007
Electricity	$	131		$	28	$	(132	)	$	(137	)	$	(110	)
Natural Gas		9			—		(6	)		—			3
Oil		28			2		(58	)		—			(28	)
Coal		7			—		—			—			7
Other, including credit reserve		(2	)		—		—			—			(2	)

Total	$	173		$	30	$	(196	)	$	(137	)	$	(130	)

We have additional coal contracts with a net fair value of approximately $134 million at December 31, 2007. These 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 consolidated balance sheets.

The following table represents the net price risk management assets and liabilities by tenor (in millions):


	At December 31, 2007
2008	$	(23	)
2009		(66	)
2010		(40	)
2011		(1	)
Thereafter		—

Net assets (liabilities)	$	(130	)

Value at Risk

Our Risk Management Policy prohibits the trading of certain products (e.g., natural gas liquids and pulp and paper) and contains limits and restrictions related to our asset management and proprietary trading activities.

We manage the price risk associated with asset management activities through a variety of methods. Our Risk Management Policy requires that asset management activities are restricted to only those activities that are risk-reducing. We ensure compliance with this restriction at the transactional level by testing each individual transaction executed relative to the overall asset position.

We also use VaR to measure the market price risk of our energy asset portfolio as a result of potential changes in market prices. VaR is a statistical model that provides an estimate of potential loss. We calculate VaR based on the parametric variance/covariance approach, utilizing a 95% confidence interval and a one-day holding period on a rolling 24-month forward looking period. Additionally, we estimate correlation based on historical commodity price changes. Volatilities are based on a combination of historical price changes and implied market rates.

VaR is calculated on an asset management portfolio comprised of mark-to-market and non mark-to-market energy assets and liabilities including generating facilities and bilateral physical and financial transactions. We also calculate VaR on portfolios consisting of mark-to-market and non mark-to-market bilateral physical and financial transactions related to our proprietary trading activities and fuel oil management operations. Asset management VaR levels are substantially reduced due to our decision to hedge actively in the forward markets the commodity price risk related to the expected generation and fuel usage of our generating facilities. See Item 1. “Commercial Operations” for discussion of our hedging strategies and Item 7. “Critical Accounting Estimates” for the accounting treatment of asset management and proprietary trading activities.

The following table summarizes year-end, average, maximum and minimum VaR for our asset management portfolio and proprietary trading and fuel oil management operations (in millions):


	For the Years Ended December 31,
	2007		2006
Asset Management VaR
Year end	$	20	$	41
Average	$	29	$	47
High	$	40	$	54
Low	$	20	$	41



	For the Years Ended December 31,
	2007		2006
Proprietary Trading and Fuel Oil Management VaR
Year end	$	2	$	3
Average	$	3	$	2
High	$	4	$	3
Low	$	2	$	2

The asset management VaR declined for the year ended December 31, 2007, as compared to the year ended December 31, 2006, primarily as a result of increased hedging activity against our underlying generating facilities.

Because of inherent limitations of statistical measures such as VaR and the seasonality of changes in market prices, the VaR calculation may not reflect the full extent of our commodity price risk exposure. Additionally, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated VaR, and such changes could have a material effect on our financial results.

Interest Rate Risk

We have several loans that provide for a variable rate of interest. Interest expense on such borrowings is sensitive to changes in the market rate of interest.

Our total debt from operations that is subject to variable interest rates through either the Mirant North America senior secured term loan or senior secured revolving credit facility, assuming they are fully drawn, is approximately $1.4 billion. A 1% per annum increase in the average market rate would result in an increase in our annual interest expense of approximately $14 million.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty failed to perform under its contractual obligations less the value of collateral held by us. We have established controls and procedures in our Risk Management Policy to determine and monitor the creditworthiness of customers and counterparties. Our credit policies are established and monitored by the Risk Oversight Committee. The Risk Oversight Committee includes the Chief Financial Officer and management’s representatives from several functional areas. We use published ratings of customers, as well as our internal analysis, to guide us in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. Where external ratings are not available, we rely on our internal assessments of customers.

Collection Risk

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

Item 8.

Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Mirant Corporation and subsidiaries:

We have audited the accompanying consolidated balance sheets of Mirant Corporation and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity (deficit), comprehensive income (loss) and cash flows for each of the years in the three-year period ended December 31, 2007. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Mirant Corporation and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO.

F-1

As discussed in Note 2 to the consolidated financial statements, the Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes in 2007. As discussed in Note 8 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, Employer’s Accounting for Defined Benefit and Other Post Retirement Plans and Statement of Financial Accounting Standards No. 123R, Share-Based Payment in 2006. As discussed in Note 9 to the consolidated financial statements, the Company adopted FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations in 2005.

(signed) KPMG LLP

Atlanta, Georgia

February 28, 2008

F-2

MIRANT CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Years Ended December 31,
	2007			2006			2005
	(in millions, except per share data)
Operating revenues	$	2,019		$	3,087		$	2,620
Cost of fuel, electricity and other products		912			1,151			1,784

Gross Margin		1,107			1,936			836

Operating Expenses:
Operations and maintenance		707			592			683
Depreciation and amortization		129			137			135
Impairment losses		175			119			9
Loss (gain) on sales of assets, net		(45	)		(49	)		17

Total operating expenses		966			799			844

Operating Income (Loss)		141			1,137			(8	)

Other Expense (Income), net:
Interest expense		247			289			1,404
Interest income		(202	)		(76	)		(9	)
Gain on sales of investments, net		—			(76	)		(45	)
Other, net		(344	)		(38	)		63

Total other expense (income), net		(299	)		99			1,413

Income (Loss) From Continuing Operations Before Reorganization Items and Income Taxes		440			1,038			(1,421	)
Reorganization items, net		(2	)		(164	)		(18	)
Provision (benefit) for income taxes		9			(550	)		(18	)

Income (Loss) From Continuing Operations		433			1,752			(1,385	)

Income From Discontinued Operations, net		1,562			112			93

Income (Loss) Before Cumulative Effect of Changes in Accounting Principles		1,995			1,864			(1,292	)
Cumulative Effect of Changes in Accounting Principles		—			—			(15	)

Net Income (Loss)	$	1,995		$	1,864		$	(1,307	)

Basic EPS:
Basic EPS from continuing operations	$	1.72		$	6.15
Basic EPS from discontinued operations		6.20			0.39

Basic EPS	$	7.92		$	6.54

Diluted EPS:
Diluted EPS from continuing operations	$	1.56		$	5.90
Diluted EPS from discontinued operations		5.64			0.38

Diluted EPS	$	7.20		$	6.28

Weighted average shares outstanding		252			285
Effect of dilutive securities		25			12

Weighted average shares outstanding assuming dilution		277			297

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

F-3

MIRANT CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2007			2006
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	4,961		$	1,139
Funds on deposit		304			235
Receivables, net		297			381
Price risk management assets		173			715
Inventories		357			287
Prepaid expenses		142			142
Assets held for sale		—			4,987
Deferred income taxes		—			244

Total current assets		6,234			8,130

Property, Plant and Equipment, net		2,590			2,201

Noncurrent Assets:
Intangible assets, net		206			214
Price risk management assets		30			100
Deferred income taxes		83			486
Prepaid rent		234			218
Other		75			147

Total noncurrent assets		628			1,165

Total Assets	$	9,452		$	11,496

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current portion of long-term debt	$	142		$	142
Accounts payable and accrued liabilities		426			443
Price risk management liabilities		196			322
Liabilities held for sale		—			2,218
Deferred income taxes		83			9
Other		12			88

Total current liabilities		859			3,222

Noncurrent Liabilities:
Long-term debt		2,953			3,133
Price risk management liabilities		137			428
Asset retirement obligations		44			40
Pension and postretirement obligations		101			204
Other		48			8

Total noncurrent liabilities		3,283			3,813

Liabilities Subject to Compromise		—			18

Commitments and Contingencies

Stockholders’ Equity:
Preferred stock, par value $.01 per share; authorized 100,000,000 shares, no shares issued at December 31, 2007 and December 31, 2006		—			—
Common stock, par value $.01 per share, authorized 1.5 billion shares, issued 301,196,073 and 300,200,197 at December 31, 2007 and December 31, 2006, respectively, and outstanding 221,811,972 shares and 256,017,187 at December 31, 2007 and December 31, 2006, respectively		3			3
Treasury stock, at cost 79,384,101 shares and 44,183,010 shares at December 31, 2007 and December 31, 2006, respectively		(2,586	)		(1,261	)
Additional paid-in capital		11,357			11,317
Accumulated deficit		(3,486	)		(5,598	)
Accumulated other comprehensive income (loss)		22			(18	)

Total stockholders’ equity		5,310			4,443

Total Liabilities and Stockholders’ Equity	$	9,452		$	11,496

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

F-4

MIRANT CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)


	Common Stock			Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)
	(in millions)
Balance, December 31, 2004	$	4		$	(2	)	$	4,918		$	(6,155	)	$	(83	)
Net loss		—			—			—			(1,307	)		—
Cancellation of pre-reorganization common stock		(4	)		2			(4,918	)		—			—
Issuance of post-reorganization common stock		3			—			11,298			—			—
Other comprehensive loss		—			—			—			—			100

Balance, December 31, 2005		3			—			11,298			(7,462	)		17
Net income		—			—			—			1,864			—
Stock repurchases		—			(1,261	)		—			—			—
Stock-based compensation		—			—			17			—			—
Exercise of warrants		—			—			2			—			—
Other comprehensive income		—			—			—			—			(25	)
Adoption of SFAS 158, net of tax		—			—			—			—			(10	)

Balance, December 31, 2006		3			(1,261	)		11,317			(5,598	)		(18	)
Net income		—			—			—			1,995			—
Stock repurchases		—			(1,325	)		—			—			—
Stock-based compensation		—			—			29			—			—
Exercise of stock options and warrants		—			—			11			—			—
Adoption of FIN 48		—			—			—			117			—
Other comprehensive income		—			—			—			—			40

Balance, December 31, 2007	$	3		$	(2,586	)	$	11,357		$	(3,486	)	$	22

MIRANT CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


	For the Years Ended December 31,
	2007			2006			2005
	(in millions)
Net Income (Loss)	$	1,995		$	1,864		$	(1,307	)
Other comprehensive income (loss), net of tax
Cumulative translation adjustment		4			2			74
Unrealized gains (losses) on available-for-sale securities		—			(27	)		27
Settlement of pension and other postretirement benefits		(6	)		—			—
Gains on pension and other postretirement benefits		46			—			—
Amortization of pension and postretirement benefits		(4	)		—			—
Other		—			—			(1	)

Other comprehensive income (loss), net of tax		40			(25	)		100

Total Comprehensive Income (Loss)	$	2,035		$	1,839		$	(1,207	)

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

F-5

MIRANT CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Years Ended December 31,
	2007			2006			2005
	(in millions)
Cash Flows from Operating Activities:
Net income (loss)	$	1,995		$	1,864		$	(1,307	)
Income from discontinued operations		1,562			112			93

Income (loss) from continuing operations		433			1,752			(1,400	)

Adjustments to reconcile net income (loss) from continuing operations to net cash provided by (used in) operating activities:
Depreciation and amortization		139			147			148
Impairment losses		175			119			9
Gain on sales of assets and investments, net		(45	)		(125	)		(28	)
Non-cash post-petition interest expense		—			—			1,374
Cumulative effect of changes in accounting principles		—			—			15
Effect of the Plan		—			—			(285	)
Price risk management activities, net		536			(655	)		16
Deferred income taxes		—			(552	)		(4	)
Stock-based compensation		25			17			—
Non-cash gain on property tax settlement		—			(71	)		—
Other postretirement benefits curtailment gain		(32	)		—			—
Settlement of the Back-to-Back Agreement with Pepco		(341	)		—			—
Other, net		1			(33	)		43
Changes in operating assets and liabilities:
Receivables, net		147			126			(313	)
Funds on deposit		(69	)		456			(375	)
Inventories		(70	)		(9	)		16
Other assets		57			(80	)		(45	)
Accounts payable and accrued liabilities		(91	)		(192	)		364
Settlement of claims payable		(53	)		(814	)		—
Other liabilities		(26	)		51			77

Total adjustments		353			(1,615	)		1,012

Net cash provided by (used in) operating activities of continuing operations		786			137			(388	)
Net cash provided by operating activities of discontinued operations		178			432			421

Net cash provided by operating activities		964			569			33

Cash Flows from Investing Activities:
Capital expenditures, excluding capitalized interest		(560	)		(133	)		(101	)
Capitalized interest expense for projects under construction		(28	)		(6	)		—
Proceeds from the sales of assets and other investments		57			143			165
Other		7			1			—

Net cash provided by (used in) investing activities of continuing operations		(524	)		5			64
Net cash provided by (used in) investing activities of discontinued operations		5,281			(163	)		15

Net cash provided by (used in) investing activities		4,757			(158	)		79

Cash Flows from Financing Activities:
Proceeds from issuance of long-term debt		—			2,017			100
Repayment of long-term debt		(180	)		(475	)		(2	)
Proceeds from the exercise of stock options and warrants		11			2			—
Settlement of debt under the Plan		—			(990	)		—
Debt issuance costs		—			(51	)		—
Stock repurchases		(1,308	)		(1,261	)		(1	)

Net cash provided by (used in) financing activities of continuing operations		(1,477	)		(758	)		97
Net cash provided by (used in) financing activities of discontinued operations		(669	)		181			(142	)

Net cash used in financing activities		(2,146	)		(577	)		(45	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		1			—			(1	)
Net Increase (Decrease) in Cash and Cash Equivalents		3,576			(166	)		66
Cash and Cash Equivalents, beginning of period		1,139			1,068			1,003
Plus: Cash and Cash Equivalents in Assets Held for Sale, beginning of period		246			483			482
Less: Cash and Cash Equivalents in Assets Held for Sale, end of period		—			246			483

Cash and Cash Equivalents, end of period	$	4,961		$	1,139		$	1,068

Supplemental Cash Flow Disclosures:
Cash paid for interest, net of amounts capitalized	$	346		$	372		$	120
Cash paid for income taxes	$	33		$	165		$	68
Cash paid for claims and professional fees from bankruptcy	$	63		$	1,908		$	171

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

F-6

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2007, 2006 and 2005

1. Description of Business and Organization

Mirant is a competitive energy company that produces and sells electricity in the United States. The Company owns or leases 10,280 MW of electric generating capacity located in markets 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.

In the third quarter of 2006, the Company commenced separate auction processes to sell its Philippine (2,203 MW) and Caribbean (1,050 MW) businesses and six U.S. natural gas-fired facilities totaling 3,619 MW, consisting of the Zeeland (903 MW), West Georgia (613 MW), Shady Hills (469 MW), Sugar Creek (561 MW), Bosque (546 MW) and Apex (527 MW) facilities. On May 1, 2007, the Company completed the sale of the six U.S. natural gas-fired facilities. On June 22, 2007, the Company completed the sale of its Philippine business. On August 8, 2007, the Company completed the sale of its Caribbean business. In addition, on May 7, 2007, the Company completed the sale of Mirant NY-Gen (121 MW). After transaction costs and repayment of debt, the net proceeds to Mirant from dispositions completed in the year ended December 31, 2007, were approximately $5.071 billion. See Note 11 for additional information regarding the accounting for these businesses and facilities as discontinued operations.

On April 9, 2007, Mirant announced that its Board of Directors had decided to explore strategic alternatives to enhance stockholder value. In the exploration process, the Board of Directors considered whether the interests of stockholders would be best served by returning excess cash from the sale proceeds to stockholders, with the Company continuing to operate its retained businesses or, alternatively, whether greater stockholder value would be achieved by entering into a transaction with another company, including a sale of the Company in its entirety. On November 9, 2007, Mirant announced the conclusion of the strategic review process. The Company plans to return a total of $4.6 billion of excess cash to its stockholders. The first stage of the cash distribution is being 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, in conjunction with the accelerated share repurchases, the Company repurchased approximately 26.66 million shares of common stock for $1 billion. See Note 13 for further discussion. In addition, Mirant purchased approximately 8.27 million shares of its common stock for approximately $316 million through open market purchases. Between January 1, 2008 and February 25, 2008, the Company purchased an additional 7.9 million shares in open market purchases for approximately $286 million. 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.

F-7

2. Accounting and Reporting Policies

Basis of Presentation

The accompanying consolidated financial statements of Mirant and its wholly-owned subsidiaries have been prepared in accordance with GAAP.

The accompanying 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 December 31, 2007, all of Mirant’s subsidiaries are wholly-owned. The Company’s obligations to MC Asset Recovery result in its treatment as a variable interest entity in which Mirant is the primary beneficiary as defined in FIN 46R. The entity, therefore, is included in the Company’s consolidated financial statements. See Note 18 for further discussion of MC Asset Recovery.

In preparing the Company’s 2006 federal income tax return during 2007, the Company discovered a misstatement in the historical tax basis of its Philippine business. The sale of the Philippine business was completed on June 22, 2007. The result of the misstatement was an overstatement of the benefit for income taxes as a component of continuing operations and an equivalent understatement of income from discontinued operations by approximately $28 million for the year ended December 31, 2006. Basic and diluted earnings per share from continuing operations were overstated by $0.10 and $0.09, respectively. Conversely, basic and diluted earnings per share from discontinued operations were understated by the same amounts. The misstatement had no effect on net income or stockholders’ equity. The consolidated statement of operations and related footnotes for the year ended December 31, 2006, have been adjusted to reflect the immaterial correction of this misstatement.

In conjunction with Mirant’s tax planning associated with the utilization of NOLs, the Company reevaluated certain items included in its historical tax basis balance sheets used in the calculation of the Company’s deferred tax assets and liabilities. As a result of this reevaluation, the values of certain components of Mirant’s inventory of deferred tax assets and liabilities have been adjusted. Current deferred income tax assets were increased by $134 million and noncurrent deferred income tax assets were decreased by $174 million at December 31, 2006. Current deferred income tax liabilities were increased by $40 million at December 31, 2006. The adjustments had no effect on the net deferred taxes on the accompanying consolidated balance sheets. In addition, the adjustments had no effect on net income, earnings per share or stockholders’ equity. The consolidated balance sheet and the income tax disclosures in Note 7 reflect the immaterial correction of this misstatement.

In preparing the Company’s 2007 consolidated statement of cash flow, the Company discovered that capitalized interest expense for projects under construction had been included in cash flows from operating activities, rather than cash flows from investing activities in 2006. 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 $6 million for the year ended December 31, 2006. The misstatement had no effect on cash, net income, or stockholders’ equity. The consolidated statement of cash flows for the year ended December 31, 2006, has been adjusted to reflect the immaterial correction of this 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 and the associated assets and liabilities have been reclassified to assets and liabilities held for sale for all periods presented. Certain prior period amounts have been reclassified to conform to the current year financial statement presentation.

F-8

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make a number of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates. Mirant’s significant estimates include:

—

determining the fair value of certain derivative contracts;

—

estimating future taxable income in determining its deferred tax asset valuation allowance;

—

estimating the useful lives of our long-lived assets;

—

determining the value of Mirant’s asset retirement obligations;

—

estimating future cash flows in determining impairments of long-lived assets and definite-lived intangible assets;

—

estimating the expected return on plan assets, rate of compensation increases and other actuarial assumptions used in estimating pension and other postretirement benefit plan liabilities;

—

estimating losses to be recorded for contingent liabilities; and

—

estimating certain assumptions used in the grant date fair value of stock options.

Revenue Recognition

Mirant recognizes revenue from the sale of energy when earned and collection is probable. Some sales of energy are based on economic dispatch, or ‘as-ordered’ by an ISO, based on member participation agreements, but without an underlying contractual commitment. ISO revenues and revenues from sales of energy based on economic-dispatch are recorded on the basis of MWh delivered, at the relevant day-ahead or real-time prices. When a long-term electric power agreement conveys to the buyer of the electric power the right to use the generating capacity of Mirant’s facility, that agreement is evaluated to determine if it is a lease of the generating facility rather than a sale of electric power. Operating lease revenue for the Company’s generating facilities is normally recorded as capacity revenue and included in operating revenues in the consolidated statements of operations.

Derivative Financial Instruments

Derivative financial instruments are recorded in the accompanying consolidated balance sheets at fair value as either assets or liabilities, and changes in fair value are recognized currently in earnings, unless the Company elects to apply fair value or cash flow hedge accounting based on meeting specific criteria in SFAS 133. For the years ended December 31, 2007, 2006 and 2005, the Company did not have any derivative instruments that it had designated as fair value or cash flow hedges for accounting purposes. Mirant’s derivative financial instruments are categorized by the Company based on the business objective the instrument is expected to achieve: asset management or proprietary trading. All derivative contracts are recorded at fair value, except for a limited number of transactions that qualify for the normal purchases or normal sales exclusion from SFAS 133 and therefore qualify for the use of accrual accounting.

As the Company’s commodity derivative financial instruments have not been designated as hedges for accounting purposes, changes in such instruments’ fair values are recognized currently in earnings. For asset management activities, changes in fair value of electricity derivative financial instruments are reflected in operating revenue and changes in fair value of fuel derivative contracts are reflected in cost of fuel, electricity and other products in the accompanying consolidated statements of operations. Changes in the fair value and settlements of contracts for proprietary trading activities are recorded on a net basis as operating revenue in the accompanying consolidated statements of operations.

F-9

Concentration of Revenues

In 2007, 2006 and 2005, Mirant earned a significant portion of its operating revenue and gross margin from the PJM energy market, where its Mirant Mid-Atlantic generating facilities are located. Mirant Mid-Atlantic’s revenues and gross margin as a percentage of Mirant’s total revenues and gross margin from continuing operations are as follows:


	Years Ended December 31,
	2007		2006		2005
Operating revenues	56	%	62	%	46	%
Gross margin	55	%	68	%	54	%

Concentration of Labor Subject to Collective Bargaining Agreements

At December 31, 2007, approximately 48% of Mirant’s employees are subject to collective bargaining agreements, of which 60% are subject to the collective bargaining agreement in the Mid-Atlantic region.

Cash and Cash Equivalents

Mirant considers all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2007, except for amounts held in bank accounts to cover current payables, all of the Company’s cash and cash equivalents were invested in AAA-rated U.S. Treasury money market funds.

Restricted Cash

Restricted cash is included in current and noncurrent assets as funds on deposit and other noncurrent assets in the accompanying consolidated balance sheets. At December 31, 2007, current and noncurrent funds on deposit were $304 million and $7 million, respectively. At December 31, 2006, current and noncurrent funds on deposit were $235 million and $6 million, respectively. Restricted cash includes deposits with brokers and cash collateral posted with third parties to support the Company’s commodity positions as well as a $200 million deposit by Mirant North America posted under its senior secured term loan to support the issuance of letters of credit.

Inventory

Inventory consists primarily of oil, coal, purchased emissions allowances and materials and supplies. Inventory, including commodity trading 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. 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 consolidated statements of operations as they are utilized against emissions volumes that exceed the allowances granted to the Company by the EPA.

Inventory at December 31, 2007 and 2006, consisted of (in millions):


	At December 31,
	2007		2006
Fuel	$	280	$	195
Materials and supplies		67		63
Emissions allowances		10		29

Total inventory	$	357	$	287

F-10

Granted Emissions Allowances

Included in property, plant and equipment are emissions allowances granted by the EPA that were projected to be required to offset physical emissions related to generating facilities owned by the Company. These emissions allowances were recorded at fair value at the date of the acquisition of the facility and are depreciated on a straight-line basis over the estimated useful life of the respective generating facility and are charged to depreciation and amortization expense in the accompanying consolidated statements of operations.

Included in other intangible assets are: (1) emissions allowances granted by the EPA related to generating facilities owned by the Company that are projected to be in excess of those required to offset physical emissions; and (2) emissions allowances related to generating facilities leased by the Company. Emissions allowances related to leased generating facilities are recorded at fair value at the commencement of the lease. These emissions allowances are amortized on a straight-line basis over a period up to 30 years for emissions allowances related to owned generating facilities or the term of the lease for emissions allowances related to leased generating facilities, and are charged to depreciation and amortization expense in the accompanying consolidated statements of operations.

As a result of the capital expenditures Mirant is making to comply with the requirements of the Maryland Healthy Air Act, the Company anticipates that it will have significant excess emissions allowances in future periods. The Company plans to continue to maintain some emissions allowances in excess of expected generation in case its actual generation exceeds its current forecasts for future periods and for possible future additions of generating capacity. During the fourth quarter of 2007, the Company began a program to sell excess emissions allowances dependent upon market conditions. The Company sold approximately $24 million of excess emissions allowances and recognized a gain of $22 million, which is included in gain on sales of assets in the consolidated statement of operations for the year ended December 31, 2007. The Company has determined that certain exchanges of emissions allowances that the Company may periodically transact qualify as nonmonetary exchanges under SFAS 153.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost, which includes materials, labor, and associated payroll-related and overhead costs and the cost of financing construction. The cost of routine maintenance and repairs, such as inspections and corrosion removal, and the replacement of minor items of property are charged to expense as incurred. Certain expenditures incurred during a major maintenance outage of a generating facility are capitalized, including the replacement of major component parts and labor and overhead incurred to install the parts. Depreciation of the recorded cost of depreciable property, plant and equipment is determined using primarily composite rates. Leasehold improvements are depreciated over the shorter of the expected life of the related equipment or the lease term. Upon the retirement or sale of property, plant and equipment the cost of such assets and the related accumulated depreciation are removed from the consolidated balance sheets. No gain or loss is recognized for ordinary retirements in the normal course of business since the composite depreciation rates used by Mirant take into account the effect of interim retirements.

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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 assets in terms of interest cost 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 placed in service, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. For the years ended December 31, 2007, 2006 and 2005, the Company incurred the following interest costs (in millions):


	Years Ended December 31,
	2007			2006			2005
Total interest costs	$	272		$	298		$	1,404
Capitalized and included in property, plant and equipment, net		(25	)		(9	)		—

Interest expense	$	247		$	289		$	1,404

Operating Leases

Mirant leases various assets under non-cancelable leasing arrangements, including generating facilities, office space and other equipment. The rental expense associated with leases that qualify as operating leases is recognized on a straight-line basis over the lease term within operations and maintenance expense in the consolidated statement of operations. The Company’s most significant operating leases are Mirant Mid-Atlantic’s leases of the Morgantown and Dickerson baseload units, which expire in 2034 and 2029, respectively. Mirant has an option to extend these leases. Any extensions of the respective leases would be limited to 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. As of December 31, 2007, the total notional minimum lease payments for the remaining terms of the leases of the Morgantown and Dickerson baseload units aggregated approximately $2.1 billion.

Curtailment of Other Postretirement Benefits

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 consolidated statement of operations for the year ended December 31, 2007.

Intangible Assets

Intangible assets with definite useful lives are amortized on a straight-line basis over their respective useful lives ranging up to 40 years to their estimated residual values.

Investments

For the years ended December 31, 2006 and 2005, the Company completed the sales of investments described below. The related gains are recorded in gain on sales of investments, net in the consolidated statements of operations.

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Equity Investment in InterContinental Exchange. In 2005, the Company sold a portion of its investment in InterContinental Exchange for $48 million and realized a gain of $44 million. In 2006, the Company sold its remaining investment in InterContinental Exchange for $58 million and realized a gain of $54 million.

New York Mercantile Exchange Seats. In late 1998 and early 1999, the Company acquired two seats on the New York Mercantile Exchange. In 2006, the Company sold its investment for $20 million and recognized a gain of $19 million, which is recorded in gain on sales of investments, net on the Company’s consolidated statement of operations.

Environmental Remediation Costs

Mirant accrues for costs associated with environmental remediation when such costs are probable and can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Such accruals are adjusted as further information develops or circumstances change. The cost of future expenditures for environmental remediation obligations are discounted to their present value.

Debt Issuance Costs

Debt issuance costs are capitalized and amortized as interest expense on a basis that approximates the effective interest method over the term of the related debt.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

SFAS 109 requires that a valuation allowance be established when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including the Company’s past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies.

Objective positive evidence is necessary to support a conclusion that a valuation allowance is not needed for all or a portion of deferred tax assets when significant negative evidence exists. It is the Company’s view that future sources of taxable income, reversing temporary differences and implemented tax planning strategies will be sufficient to realize deferred tax assets for which no valuation allowance has been established. A portion of the Company’s NOLs (approximately $341 million) is attributable to excess tax deductions primarily related to bankruptcy transactions. The recognition of the tax benefit of these excess tax deductions, either through realization or reduction of the valuation allowance, will be an increase to additional paid-in-capital in stockholders’ equity. These NOLs will be the last utilized for financial reporting purposes.

Impairment of Long-Lived Assets

Mirant evaluates long-lived assets, such as property, plant and equipment and purchased intangible assets subject to amortization, for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Such evaluations are performed in accordance with SFAS 144. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an

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asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value. Assets to be disposed of are separately presented in the accompanying consolidated balance sheets and are reported at the lower of the carrying amount or fair value less costs to sell, and are not depreciated. The assets and liabilities of a disposal group classified as held for sale are presented separately in the appropriate asset and liability sections of the accompanying consolidated balance sheets.

Cumulative Effect of Changes in Accounting Principles

The Company adopted FIN 47, effective December 31, 2005, related to the costs associated with conditional legal obligations to retire tangible, long-lived assets. Conditional asset retirement obligations are recorded at the fair value in the period in which they are incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its fair value and the capitalized costs are depreciated over the useful life of the related asset. For the year ended December 31, 2005, the Company recorded a charge as a cumulative effect of changes in accounting principle of approximately $15 million, net of tax, related to the adoption of this accounting standard.

Earnings per Share

Earnings per share information for 2005 has not been presented. The Company does not think that this information is relevant in any material respect for users of its financial statements. See Note 14 for further discussion.

Basic earnings per share is calculated by dividing net income (loss) applicable to common stockholders by the weighted average number of common shares outstanding. Diluted earnings (loss) per share is computed using the weighted average number of shares of common stock and dilutive potential common shares, including common shares from warrants, restricted stock shares, restricted stock units and stock options using the treasury stock method.

Recently Adopted Accounting Standards

In February 2006, the FASB issued SFAS 155, which allows fair value measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. SFAS 155 is effective for all financial instruments acquired, issued or subject to a re-measurement event beginning in the first fiscal year after September 15, 2006. At the date of adoption, any difference between the total carrying amount of the existing bifurcated hybrid financial instrument and the fair value of the combined hybrid financial instrument will be recognized as a cumulative effect adjustment to beginning retained earnings. The Company adopted SFAS 155 on January 1, 2007. The adoption of SFAS 155 did not affect the Company’s statements of operations, financial position or cash flows.

In March 2006, the FASB issued SFAS 156, which requires all separately recognized servicing assets and servicing liabilities to be measured initially at fair value and permits, but does not require, an entity to measure subsequently those servicing assets or liabilities at fair value. The Company adopted SFAS 156 on January 1, 2007. All requirements for recognition and initial measurement of servicing assets and servicing liabilities have been applied prospectively to transactions occurring after the adoption of this statement. The adoption of SFAS 156 did not have a material effect on the Company’s statements of operations, financial position or cash flows.

On June 28, 2006, the FASB ratified the EITF’s consensus reached on EITF 06-3, which relates to the income statement presentation of taxes collected from customers and remitted to government authorities. The Task Force affirmed as a consensus on this issue that the presentation of taxes on either a gross basis or a net basis within the scope of EITF 06-3 is an accounting policy decision that should be disclosed pursuant to APB 22. A company should disclose the amount of those taxes that is recognized on a gross basis in interim and annual financial statements for each period for which an income statement is presented if those amounts are

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significant. The Company adopted EITF 06-3 on January 1, 2007. While the amounts are not material, the Company’s policy is to present such taxes on a net basis in the consolidated statements of operations.

On July 13, 2006, the FASB issued FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. On January 1, 2007, the Company adopted the provisions of FIN 48. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date were recognized or continue to be recognized. The total effect of adopting FIN 48 was an increase in stockholders’ equity of $117 million. See Note 7 for additional information on FIN 48.

On May 2, 2007, the FASB issued FSP FIN 48-1, which amended FIN 48 to provide guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position is effectively settled, companies are required to make the assessment on a position-by-position basis; however, a company could conclude that all positions in a particular tax year are effectively settled. The Company’s initial adoption of FIN 48 on January 1, 2007, was consistent with the provisions of FSP FIN 48-1.

New Accounting Standards Not Yet Adopted

On September 29, 2006, the FASB issued SFAS 158, which includes the requirement to measure 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 currently uses a September 30 measurement date each year and will transition to a fiscal year-end measurement date by December 31, 2008. This transition will result in a direct adjustment to retained earnings during 2008 that represents one quarter of the annual net periodic benefit cost.

On September 15, 2006, the FASB issued SFAS 157, which establishes a framework for measuring fair value under GAAP and expands disclosure about fair value measurements. SFAS 157 requires 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. 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. The FASB deferred the effective date to January 1, 2009, for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis.

SFAS 157 nullifies 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.

In addition, SFAS 157 also clarifies that 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 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

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Company currently measures fair value using the approximate mid-point of the bid and ask prices. Upon adoption of SFAS 157, the Company will measure fair value based on the bid or ask price for its price risk management assets and liabilities in accordance with the exit price objective.

The provisions of SFAS 157 are to be 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 to be recorded as a transition adjustment to beginning retained earnings in the year of adoption.

Upon adoption, the Company recognized a gain of approximately $1 million as a cumulative-effect adjustment to accumulated deficit, net of income tax on January 1, 2008. The cumulative-effect adjustment relates entirely to the recognition of inception gains and losses formerly deferred under EITF 02-3.

On February 15, 2007, the FASB issued SFAS 159, which permits 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 is 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 have a material effect on the Company’s statements of operations, financial position or cash flows as the Company did not elect the fair value option for any of its financial instruments.

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 is effective at the beginning of the first fiscal year after November 15, 2007. The adoption of FSP FIN 39-1 requires retrospective application for all financial statements presented as a change in accounting principle. The Company adopted FSP FIN 39-1 on January 1, 2008, and elected to continue to net the price risk management assets and liabilities subject to master netting agreements. The Company will reflect the adoption of FSP FIN 39-1 in its consolidated financial position at March 31, 2008, and reclassify amounts at December 31, 2007, to be consistent with the March 31, 2008, presentation. The adoption of FSP FIN 39-1 has no effect on the Company’s consolidated statements of operations or cash flows.

On December 21, 2007, the SEC issued SAB 110, which amends 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 sufficient exercise history is available.

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3.	Accounts Receivable and Notes Receivable

Receivables consisted of the following at December 31, 2007 and 2006 (in millions):


	At December 31,
	2007			2006
Customer accounts	$	250		$	316
Notes receivable		13			20
Other		64			87
Less: allowance for uncollectibles		(14	)		(32	)

Total receivables		313			391
Less: long-term receivables included in other long-term assets		(16	)		(10	)

Total current receivables	$	297		$	381

4.	Financial Instruments

Commodity Financial Instruments

The Company manages the risks around fuel supply and power to be generated from its physical asset positions. Mirant manages the price risk associated with asset management activities through a variety of methods. Mirant’s Risk Management Policy requires that asset management activities are restricted to only those activities that are risk-reducing in nature. In addition, the Company, through its proprietary trading and fuel oil management activities, attempts to achieve incremental returns by entering into energy contracts where it has specific market expertise or physical asset positions. Proprietary trading and fuel oil management activities increase risk and expose the Company to risk of loss if prices move differently than expected.

Mirant enters into a variety of derivative financial and physical instruments to manage its exposure to the prices of the fuel it acquires for generating electricity, as well as the electricity that it sells. These include contractual agreements, such as forward purchase and sale agreements, futures, swaps and option contracts. Futures are traded on national exchanges and swaps are typically traded in OTC financial markets. Option contracts are traded on both a national exchange and in OTC financial markets. These contractual agreements have varying terms, notional amounts and durations, or tenors, which range from a few days to a number of years, depending on the instrument. As part of its proprietary trading activities, the Company is exposed to certain market risks in an effort to generate gains from changes in market prices by entering into derivative instruments, including exchange-traded and OTC contracts, as well as other contractual arrangements.

Derivative instruments are recorded at their estimated fair value in the Company’s accompanying consolidated balance sheets as price risk management assets and liabilities except for a limited number of transactions that qualify for the normal purchase or normal sale exception election that allows accrual accounting treatment. Changes in the fair value and settlements of electricity derivative financial instruments are reflected in operating revenue and changes in the fair value and settlements of fuel derivative contracts are reflected in cost of fuel and other products in the accompanying consolidated statements of operations. As of December 31, 2007 and 2006, the Company does not have any derivative instruments for which hedge accounting has been elected.

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The fair values of Mirant’s price risk management assets and liabilities, net of credit reserves, at December 31, 2007 and 2006, were as follows (in millions):


	At December 31, 2007
	Net Price Risk Management Assets					Net Price Risk Management Liabilities						Net Fair Value
	Current			Noncurrent		Current			Noncurrent			Net Fair Value
Electricity	$	131		$	28	$	(132	)	$	(137	)	$	(110	)
Natural Gas		9			—		(6	)		—			3
Oil		28			2		(58	)		—			(28	)
Coal		7			—		—			—			7
Other, including credit reserves		(2	)		—		—			—			(2	)

Total	$	173		$	30	$	(196	)	$	(137	)	$	(130	)


	At December 31, 2006
	Net Price Risk Management Assets					Net Price Risk Management Liabilities						Net Fair Value
	Current			Noncurrent		Current			Noncurrent			Net Fair Value
Electricity	$	603		$	99	$	(247	)	$	(8	)	$	447
Back-to-Back Agreement		—			—		(36	)		(389	)		(425	)
Natural Gas		21			1		(26	)		(2	)		(6	)
Oil		83			—		(10	)		(29	)		44
Coal		13			—		(3	)		—			10
Other, including credit reserves		(5	)		—		—			—			(5	)

Total	$	715		$	100	$	(322	)	$	(428	)	$	65

The Settlement Agreement and Release (the “Settlement Agreement”) with Pepco and various affiliates of Pepco (collectively the “Pepco Settling Parties”) dated May 30, 2006, became fully effective August 10, 2007, and, as a result, the contractual agreement with Pepco with respect to certain PPAs (the “Back-to-Back Agreement”) was rejected and terminated. As a result, the Company had no price risk management liabilities related to the Back-to-Back Agreement at December 31, 2007. The fair value of the price risk management liability related to the Back-to-Back Agreement was reversed and the Company recognized a gain of $341 million in other income, net in the consolidated statements of operations. See “Pepco Litigation” in Note 19 for further discussion of the Settlement Agreement.

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The following table represents the net price risk management assets and liabilities by tenor (in millions):


	At December 31, 2007
2008	$	(23	)
2009		(66	)
2010		(40	)
2011		(1	)
Thereafter		—

Net assets (liabilities)	$	(130	)

Fair Values

Financial instruments recorded at market or fair value include cash and interest-bearing cash equivalents, derivative financial instruments and financial instruments used for price risk management purposes. The following methods are used by Mirant to estimate the fair value of all financial instruments that are not subject to compromise and not otherwise carried at fair value on the accompanying consolidated balance sheets:

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

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

The carrying amounts and fair values of Mirant’s financial instruments at December 31, 2007 and 2006 are as follows (in millions):


	December 31, 2007
	Carrying Amount		Fair Value
Liabilities:
Long-and short-term debt	$	3,095	$	3,009

Other:
Notes and other receivables	$	20	$	24


	December 31, 2006
	Carrying Amount		Fair Value
Liabilities:
Long-and short-term debt	$	3,275	$	3,338

Other:
Notes and other receivables	$	13	$	13

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5.	Long-Lived Assets

Property, plant and equipment, net consisted of the following at December 31, 2007 and 2006 (dollars in millions):


	At December 31,						Depreciable Lives (years)
	2007			2006			Depreciable Lives (years)
Production	$	2,448		$	2,505		14 to 35
Construction work in progress		645			192		—
Other		219			208		2 to 12
Less: accumulated depreciation, depletion and amortization and provision for impairment		(722	)		(704	)

Total property, plant and equipment, net	$	2,590		$	2,201

Depreciation of the recorded cost of property, plant and equipment is recognized on a straight-line basis over the estimated useful lives of the assets. Acquired emissions allowances related to owned facilities that were projected to be required to offset physical emissions are included in production assets above, and are depreciated on a straight-line basis over the average life of the related generating facilities.

Intangible Assets, net

Following is a summary of intangible assets at December 31, 2007 and 2006 (dollars in millions):


		At December 31, 2007					At December 31, 2006
	Weighted Average Amortization Lives	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Trading rights	26 years	$	27	$	(5	)	$	27	$	(3	)
Development rights	38 years		62		(11	)		62		(9	)
Emissions allowances	32 years		151		(29	)		151		(25	)
Other intangibles	27 years		14		(3	)		14		(3	)

Total intangible assets		$	254	$	(48	)	$	254	$	(40	)

Trading rights are intangible assets recognized in connection with asset purchases that represent the Company’s ability to generate additional cash flows by incorporating Mirant’s trading activities with the acquired generating facilities.

Development rights represent the right to expand capacity at certain acquired generating facilities. The existing infrastructure, including storage facilities, transmission interconnections and fuel delivery systems and contractual rights acquired by Mirant, provide the opportunity to expand or repower certain generating facilities.

Emissions allowances recorded in intangible assets relate to emissions allowances granted for owned generating facilities that were projected at the time of acquisition to be in excess of those required to offset physical emissions and emissions allowances granted for the leasehold baseload units at the Morgantown and Dickerson facilities.

Emissions allowances granted by the EPA that were projected at the time of acquisition to be required to offset physical emissions for owned assets are recorded within property, plant and equipment, net on the consolidated balance sheets.

Amortization expense was approximately $8 million for the years ended December 31, 2007, 2006 and 2005. Assuming no future acquisitions, dispositions or impairments of intangible assets, amortization expense is estimated to be approximately $9 million for each of the next five years.

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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.

Year Ended December 31, 2007

Background

Mirant Lovett has been in ongoing discussions with the NYSDEC and the New York State Office of the Attorney General regarding environmental controls at the Lovett generating facility in New York. On June 11, 2003, Mirant New York, Mirant Lovett and the State of New York entered into a consent decree (the “2003 Consent Decree”). Under the terms of the 2003 Consent Decree, Mirant Lovett was required to install certain environmental controls on unit 5 of the Lovett facility, convert unit 5 to operate exclusively on natural gas, or discontinue operation of unit 5 by April 30, 2007. The 2003 Consent Decree also required that certain environmental controls be installed on unit 4 by April 30, 2008, or operation of unit 4 had to be discontinued.

On May 8, 2007, Mirant New York, Mirant Lovett, Mirant Bowline and Hudson Valley Gas also entered into an agreement (the “Tax Assessments Agreement”) with the Town of Stony Point, the Town of Haverstraw and the Village of Haverstraw to set the assessed values for the Lovett and Bowline facilities and the pipeline owned by Hudson Valley Gas for 2007 and 2008 for property tax purposes at the values established for 2006 under a settlement agreement entered into by the Mirant entities and those taxing authorities in December 2006.

The Bankruptcy Court approved the amendment to the 2003 Consent Decree and the Tax Assessments Agreement on May 10, 2007. The United States District Court for the Southern District of New York approved the amendment to the 2003 Consent Decree on May 11, 2007.

In its impairment analysis of the Lovett generating facility in prior periods, the Company assumed multiple scenarios, including the operation of all units of the Lovett facility beyond April 2008. Entering into the amendment to the 2003 Consent Decree and the Tax Assessments Agreement prompted management to test for recoverability of the Lovett facility under SFAS 144 in the second quarter of 2007.

Assumptions and Results

The Company’s assessment of Lovett under SFAS 144 in the second quarter of 2007 involved developing two scenarios for the future expected operation of the Lovett facility. The first scenario considered was the shutdown of unit 5 by April 30, 2008, in accordance with the amendment to the 2003 Consent Decree. The Company also considered a second scenario that assumed operation of unit 5, utilizing coal as the primary fuel

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source, through 2012 to allow the Lovett facility to continue to contribute to the reliability of the electric system of the State of New York. Property taxes under both scenarios were assumed at the assessed levels specified in the Tax Assessments Agreement for those periods. Additionally, both scenarios included an estimated cost for demolition of the facility to reduce future property taxes, a value for the land on which the facility operates and the sale of previously granted emissions allowances for periods beyond the shutdown date. For purposes of measuring an impairment loss, a long-lived asset or assets must be grouped at the lowest level of independent identifiable cash flows. All of the units at Mirant Lovett are viewed as one group. As required under SFAS 144, the assessment did not include the value of new generating capacity that could potentially be constructed at the current Lovett facility site.

As a result of this assessment, in the second quarter of 2007, the Company 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.

Year Ended December 31, 2006

In 2006, the Company’s assessment of the Bowline unit 3 suspended construction project resulted in the conclusion that the Bowline unit 3 project as configured and permitted was not economically viable. As a result of this conclusion, the Company determined the estimated value of the equipment and project termination liabilities. At December 31, 2006, the carrying value of the development and construction costs for Bowline unit 3 exceeded the estimated undiscounted cash flows from the abandonment of the project. The Company recorded an impairment of $120 million, which is reflected in impairment losses on the consolidated statement of operations for the year ended December 31, 2006.

6.	Long-Term Debt

Long-term debt at December 31, 2007 and 2006, was as follows (in millions):


	At December 31,						Interest Rate	Secured/ Unsecured
	2007			2006			Interest Rate	Secured/ Unsecured
Long-term Debt:
Mirant Americas Generation:
Senior notes:
Due 2011	$	811		$	850		8.30%	Unsecured
Due 2021		450			450		8.50%	Unsecured
Due 2031		400			400		9.125%	Unsecured
Unamortized debt premium/discount		(3	)		(4	)
Mirant North America:
Senior secured term loan, due 2008 to 2013		555			693		LIBOR + 1.75%	Secured
Senior notes, due 2013.		850			850		7.375%	Unsecured
Capital leases, due 2008 to 2015		32			36		7.375% - 8.19%

Total		3,095			3,275
Less: current portion of long-term debt		(142	)		(142	)

Total long-term debt, excluding current portion	$	2,953		$	3,133

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Mirant Americas Generation Senior Notes

In 2006, Mirant’s wholly-owned subsidiary, Mirant Americas Generation, reinstated $1.7 billion of senior notes maturing in 2011, 2021 and 2031. The reinstated senior notes are senior unsecured obligations of Mirant Americas Generation and are not recourse to any subsidiary or affiliate of Mirant Americas Generation. In the fourth quarter of 2007, the Company purchased and retired $39 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 an $800 million senior secured revolving credit facility and a senior secured term loan with an initial principal balance of $700 million amortized to $555 million as of December 31, 2007. 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. At December 31, 2007, there were approximately $199 million of letters of credit outstanding under the senior secured term loan and approximately $91 million of letters of credit outstanding under the $800 million senior secured revolving credit facility. At December 31, 2007, a total of $710 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 the quarterly installments of $1.75 million, Mirant North America is required to prepay a portion of the outstanding senior secured term loan principal balance once a year. The prepayment is based on an adjusted EBITDA calculation that determines excess free cash flows, as defined in the loan agreement. At December 31, 2007, the current estimate of the mandatory principal prepayment of the term loan in the first quarter of 2008 is approximately $132 million. This amount has been reclassified from long-term debt to current portion of long-term debt at December 31, 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 are nonrecourse to any other Mirant entities.

Mirant North America Senior Notes

In December 2005, Mirant North America issued senior notes in an aggregate principal amount of $850 million that bear interest at 7.375% and mature on December 31, 2013. The original senior notes were issued in a private placement and were not registered with the SEC. The proceeds of the original senior notes offering initially were placed in escrow pending the emergence of Mirant North America from bankruptcy. The proceeds were released from escrow in connection with Mirant North America’s emergence from bankruptcy and the closing of the senior secured credit facilities.

In connection with the issuance of the original senior notes, Mirant North America entered into a registration rights agreement under which it agreed to complete an exchange offer for the original senior notes. On June 29, 2006, Mirant North America completed its registration under the Securities Act of $850 million of the senior notes and initiated the exchange offer. The exchange offer was completed on August 4, 2006, with $849.965 million of the outstanding original senior notes being tendered for the senior notes. The terms of the senior notes are identical in all material respects to the terms of the original senior notes, except that the senior notes are registered under the Securities Act and generally are not subject to transfer restrictions or registration rights.

Interest on the notes is payable on each June 30 and December 31. The senior notes 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

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obligations, the senior notes. The senior notes are nonrecourse to any other Mirant entities. The notes are redeemable at the option of Mirant North America, in whole or in part, at any time prior to December 31, 2009, at a price equal to 100% of the principal amount, plus accrued and unpaid interest, plus a make-whole premium. At any time on or after December 31, 2009, Mirant North America may redeem the notes at specified redemption prices, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to December 31, 2008, Mirant North America may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings at a redemption price of 107.375% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. Under the terms of the notes, the occurrence of a change of control will be a triggering event requiring Mirant North America to offer to purchase all or a portion of the notes at a price equal to 101% of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase. In addition, certain asset dispositions or casualty events will be triggering events which may require Mirant North America to use the proceeds from those asset dispositions or casualty events to make an offer to purchase the notes at 100% of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase if such proceeds are not otherwise used, or committed to be used, within certain time periods, to repay senior secured indebtedness, to repay indebtedness under the senior secured credit facilities (with a corresponding reduction in commitments) or to invest in capital assets related to its business.

Debt Maturities

At December 31, 2007, the annual scheduled maturities of debt during the next five years and thereafter were as follows (in millions):


2008	$	142
2009		11
2010		11
2011		822
2012		9
Thereafter		2,100

Total	$	3,095

With the exception of 2008, the annual scheduled maturities above do not include estimates of Mirant North America’s required payments of its senior secured term loan based on its EBITDA.

Capital Leases

Long-term debt includes a capital lease by Mirant Chalk Point. At December 31, 2007 and 2006, the current portion of the long-term debt under this capital lease was $3 million. The amount outstanding under the capital lease, which matures in 2015, is $30 million with an 8.19% annual interest rate. This lease is of an 84 MW peaking electric power generating facility. Depreciation expense related to this lease was approximately $2 million for each of the years ended December 31, 2007, 2006 and 2005. The annual principal payments under this lease are approximately $3 million in 2008 through 2010, $4 million in 2011 through 2012 and $14 million thereafter. The gross amount of assets under the capital lease, recorded in property, plant and equipment, net as of December 31, 2007 and 2006, was $24 million. The related accumulated depreciation was $12 million and $10 million as of December 31, 2007 and 2006, respectively.

Sources of Funds and Capital Structure

The principal sources of liquidity for the Company’s future operations and capital expenditures are expected to be: (1) existing cash on hand and cash flows from the operations of the Company’s subsidiaries; (2) letters of credit issued or borrowings made under Mirant North America’s $800 million senior secured revolving credit

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facility; and (3) $200 million letter of credit capacity available under Mirant North America’s senior secured term loan.

The Company and certain of its subsidiaries, including Mirant Americas Generation and Mirant North America, are holding companies and, as a result, the Company and such subsidiaries are dependent upon dividends, distributions and other payments from their respective subsidiaries to generate the funds necessary to meet their obligations. The ability of certain of the Company’s subsidiaries to pay dividends and make distributions is restricted under the terms of their debt or other agreements. In particular, a substantial portion of the cash from the Company’s operations is generated by Mirant Mid-Atlantic. The Mirant Mid-Atlantic leveraged leases contain a number of covenants, including limitations on dividends, distributions and other restricted payments. Under its leveraged leases, Mirant Mid-Atlantic is not permitted to make any dividends, distributions and other restricted payments unless: (1) it satisfies the fixed charge coverage ratio on a historical basis for the last period of four fiscal quarters; (2) it is projected to satisfy the fixed charge coverage ratio for the next two periods of four fiscal quarters; and (3) no significant lease default or event of default has occurred and is continuing. In the event of a default under the leveraged leases or if the restricted payments test is not satisfied, Mirant Mid-Atlantic would not be able to distribute cash. Based on the Company’s calculation of the fixed charge coverage ratios under the leveraged leases as of December 31, 2007, Mirant Mid-Atlantic meets the required 1.7 to 1.0 ratio for restricted payments, both on a historical and projected basis.

Mirant North America is an intermediate holding company that is a subsidiary of Mirant Americas Generation and the parent of its indirect subsidiaries, including Mirant Mid-Atlantic. Mirant North America incurred certain indebtedness pursuant to its senior notes and senior secured credit facilities secured by the assets of Mirant North America and its subsidiaries (other than Mirant Mid-Atlantic and Mirant Energy Trading). The indebtedness of Mirant North America includes certain covenants typical in such notes and credit facilities, including restrictions on dividends, distributions and other restricted payments. Further, the notes and senior secured credit facilities include financial covenants that will exclude from the calculation the financial results of any subsidiary that is unable to make distributions or pay dividends at the time of such calculation. Thus, the ability of Mirant Mid-Atlantic to make distributions to Mirant North America under the leveraged lease transaction could have a material effect on the calculation of the financial covenants under the senior notes and senior secured credit facilities of Mirant North America and on its ability to make distributions to Mirant Americas Generation.

The ability of Mirant Americas Generation to pay its obligations is dependent on the receipt of dividends from Mirant North America, capital contributions from Mirant and its ability to refinance all or a portion of those obligations as they become due.

7. Income Taxes

Income from continuing operations before income taxes for the years ended December 31, 2007 and 2006, was $442 million and $1.202 billion, respectively. For the year ended December 31, 2005, the Company had a loss from continuing operations before taxes of $1.403 billion.

The income tax provision (benefit) from continuing operations consisted of the following (in millions):


	Years Ended December 31,
	2007		2006			2005
Current income tax provision (benefit)	$	9	$	2		$	(4	)
Deferred income tax provision (benefit)		—		(552	)		(14	)

Provision (benefit) for income taxes	$	9	$	(550	)	$	(18	)

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A reconciliation of the Company’s federal statutory income tax provision to the effective income tax provision adjusted for restructuring items for the years ended December 31, 2007, 2006 and 2005, is as follows (in millions):


	Years Ended December 31,
	2007			2006			2005
Provision (benefit) for income taxes based on United States federal statutory income tax rate	$	154		$	419		$	(492	)
State and local income tax (benefit), net of federal income taxes		(95	)		79			73
Discontinued operations		21			(64	)		(27	)
Return to provision adjustments:
Professional fees during bankruptcy		—			65			—
Previously deferred intercompany gain		—			22			—
Foreign reorganization gain		—			83			—
Other		(86	)		50			—
Effect of Internal Revenue Code Section §382(1)(6) and §382(1)(5)		(321	)		297			—
Effect of implementing FIN 48		44			—			—
Netherlands NOL write-off		—			—			164
Reorganization adjustments		(170	)		—			12
Taxes accrued on foreign earnings		—			16			31
Excess tax deductions related to bankruptcy transactions		(212	)		(22	)		(107	)
Change in deferred tax asset valuation allowance		671			(1,513	)		260
Other differences, net		3			18			68

Tax provision (benefit)	$	9		$	(550	)	$	(18	)

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and their respective tax bases which give rise to deferred tax assets and liabilities for continuing operations are as follows (in millions):


	December 31,
	2007			2006
Deferred Tax Assets:
Employee benefits	$	64		$	30
Reserves		25			80
Loss carryforwards		1,464			1,333
Tax basis in excess of book basis in foreign investments expected to be realized		—			335
Property and intangible assets		158			146
Energy marketing and risk management contracts		52			—
Other		62			59

Subtotal		1,825			1,983
Valuation allowance		(1,786	)		(1,115	)

Net deferred tax assets		39			868

Deferred Tax Liabilities:
Energy marketing and risk management contracts		—			(92	)
Taxes accrued on foreign earnings		—			(15	)
Other		(39	)		(40	)

Net deferred tax liabilities		(39	)		(147	)

Net deferred taxes	$	—		$	721

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NOLs

As required by applicable accounting principles, an enterprise that anticipates the realization of a pre-tax gain must recognize the benefit or detriment of the deferred tax assets and liabilities associated with the transaction in the year in which it becomes more likely than not that the gain will be realized. In accordance with EITF 93-17, Recognition of Deferred Tax Assets for a Parent Company’s Excess Tax Basis in the Stock of a Subsidiary that Is Accounted for as a Discontinued Operation, the Company recognized a tax benefit in 2006 arising from and related solely to the sale of the Philippine business. Conversely, in 2007, the Company recognized an income tax provision of $721 million that arose from and was specifically related to the sale of the Philippine business. The entire amount of this provision was recorded in income from discontinued operations in the consolidated statement of operations for the year ended December 31, 2007.

At December 31, 2006, Mirant considered it to be more likely than not that it would elect treatment under Internal Revenue Code Section (“§”) §382(l)(5). As a result of further tax planning, the Company made the decision to follow §382(l)(6) in its 2006 income tax return that was filed on September 15, 2007. As a result, the recorded deferred income tax items, including pre-emergence NOLs, are presented in accordance with the §382(l)(6) treatment at December 31, 2007. This change had no net effect on the consolidated balance sheets or consolidated statements of operations because the increase in deferred tax asset NOLs was equally offset by an increase in the related deferred tax asset valuation allowance.

Under §382(l)(6), the Company is subject to an annual limitation on the use of its NOLs that arose prior to its emergence from bankruptcy on January 3, 2006. The annual limitation is based on a number of factors including the emergence date value of the Company’s stock (as defined for tax purposes), its net unrealized built in gain position on that date, the occurrence or occurrences of realized built in gains in the post emergence years or in future years, and the effects of subsequent ownership changes (as defined for tax purposes), if any. The NOLs under this election will not be subject to any previous adjustments for interest accrued on debt settled with stock as required under §382(l)(5). The Company elected in its 2006 tax return to reduce the income tax basis of depreciable assets for any cancellation of debt income that arises from making the §382(l)(6) election.

On March 15, 2007, Mirant filed a check-the-box election under which Mirant Asia-Pacific will be treated as a corporation for U.S. federal income tax purposes effective January 1, 2007. As a result of this election, Mirant recognized a taxable gain for U.S. federal income tax purposes in 2006, which was fully offset by other deductions and losses arising in that year.

The December 31, 2007, federal NOL carryforward for financial reporting was $3.3 billion with expiration dates from 2022 to 2026. The December 31, 2006, NOL balance under §382(l)(6) was $3.2 billion as adjusted for the effect of the Mirant Asia-Pacific check-the-box election discussed above. Similarly, there is an aggregate amount of $6.5 billion of state NOL carryforwards with various expiration dates (based on the application of apportionment factors and other state tax limitations).

Objective positive evidence is necessary to support a conclusion that a valuation allowance is not needed for all or a portion of deferred tax assets when significant negative evidence exists. It is the Company’s view that future sources of taxable income, reversing temporary differences and implemented tax planning strategies will be sufficient to realize deferred tax assets for which no valuation allowance has been established. The Company continues to maintain its valuation allowance against its deferred tax assets. As of December 31, 2007, the Company’s deferred tax assets reduced by the valuation allowance are completely offset with its deferred tax liabilities. A portion of the Company’s NOLs (approximately $341 million) is attributable to excess tax

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deductions primarily related to bankruptcy transactions. The recognition of the tax benefit of these excess tax deductions, either through realization or reduction of the valuation allowance, will be an increase to additional paid-in-capital in stockholders’ equity. These NOLs will be the last utilized for financial reporting purposes.

Tax Uncertainties

The Company adopted the provisions of FIN 48 on January 1, 2007. Prior to adoption of FIN 48, Mirant recognized contingent liabilities related to tax uncertainties when it was probable that a loss had occurred and the loss or range of loss could be reasonably estimated. The recognition of contingent losses for tax uncertainties required management to make significant assumptions about the expected outcomes of certain tax contingencies. Upon adoption of FIN 48, the Company changed its method to recognize only liabilities for uncertain tax positions that are less than or subject to the measurement threshold of the more-likely-than-not standard. As a result of the implementation of FIN 48, for continuing operations, the Company recognized a decrease in accrued liabilities of $61 million and an increase of $26 million in taxes receivable. For discontinued operations, the adoption of FIN 48 resulted in a decrease in liabilities held for sale and accumulated deficit of $30 million. The total effect of adopting FIN 48 was an increase in stockholders’ equity of $117 million. A reconciliation of the beginning and ending amount of unrecognized tax benefits for continuing operations is as follows (in millions):


Unrecognized tax benefits, January 1, 2007	$	13
Increases based on tax positions related to the current year		—
Increases for tax positions for prior years		2
Settlements		—
Lapse of statute of limitations		—

Unrecognized tax benefits, December 31, 2007	$	15

The unrecognized tax benefit included the review of tax positions relating to open tax years beginning in 1999 and continuing to the present. The Company’s major tax jurisdictions are U.S. federal and multiple state jurisdictions. For U.S. federal income taxes, all tax years prior to 2004 are closed and for state income taxes, the earliest open year is 1999. However, both the federal and state NOL carryforwards from any closed year is subject to examination until the year that such NOL carryforwards are utilized and that year is closed for audit. The Company does not anticipate any significant changes in its unrecognized tax benefits over the next 12 months. Included in the balance at December 31, 2007 and 2006, the Company had $4 million and $3 million, respectively, of unrecognized tax benefits that would affect the effective tax rate if it were recognized. The Company’s tax provision continues to include an immaterial amount related to the accrual for any penalties and interest subsequent to its adoption of FIN 48.

8. Employee Benefit Plans

Pension Plans

Mirant provides pension benefits to its non-union and union employees through various defined benefit and defined contribution pension plans. These benefits are based on pay, service history and age at retirement. Defined benefit pensions are not provided for non-union employees hired after April 1, 2000, who participate in a profit sharing arrangement. Most pension benefits are provided through tax-qualified plans that are funded in accordance with ERISA and Internal Revenue Service requirements. Certain executive pension benefits that cannot be provided by the tax-qualified plans are provided through unfunded non-tax-qualified plans. The measurement date for the defined benefit plans is September 30 for each year presented.

SFAS 158 is designed to improve financial reporting by requiring an employer to recognize the overfunded or underfunded status of pension, retiree medical and other postretirement benefit plans on its balance sheets rather than only disclosing the funded status in the financial statement footnotes. The Company adopted SFAS 158 on December 31, 2006, and recognized an increase in other noncurrent liabilities of $21 million related to its underfunded defined benefit pension plans. Effective December 31, 2008, SFAS 158 also requires that

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companies measure the funded status of plans as of the year-end balance sheet date. Mirant currently uses September 30 as the date to measure the funded status of its plans. SFAS 158 offers two transition methods for companies that do not use a year-end measurement date to transition to a December 31, 2008, measurement date. Mirant has elected to use the alternative transition method under SFAS 158 for changing its measurement date, which resulted in an increase to accumulated deficit of $1.8 million as of January 1, 2008.

The following table shows the benefit obligations and funded status for the defined benefit pension plans of Mirant’s continuing operations (in millions):


	Tax-Qualified						Non-Tax Qualified
	2007			2006			2007			2006
Change in benefit obligation:
Benefit obligation, beginning of year	$	244		$	245		$	9		$	12
Service cost		8			10			—			—
Interest cost		14			13			—			1
Benefits paid		(8	)		(7	)		—			—
Actuarial gain		(15	)		(17	)		—			(4	)

Benefit obligation, end of year	$	243		$	244		$	9		$	9

Change in plan assets:
Fair value of plan assets, beginning of year	$	151		$	109		$	—		$	—
Return on plan assets		21			11			—			—
Employer contributions		41			38			—			—
Benefits paid		(8	)		(7	)		—			—

Fair value of plan assets, end of year	$	205		$	151		$	—		$	—

Funded Status:
Funded status at measurement date	$	(38	)	$	(93	)	$	(9	)	$	(9	)

The accumulated benefit obligation exceeded the fair value of plan assets at year-end 2007 for the tax qualified pension plans. The total accumulated benefit obligation as of September 30, 2007, was $213 million.

The weighted average assumptions used for measuring year-end pension benefit obligations as of their respective measurement dates are listed in the table below. The discount rate used as of September 30, 2007, was determined based on individual bond-matching models comprised of portfolios of high quality corporate bonds with projected cash flows and maturity dates reflecting the expected time horizon during which that benefit will be paid. Bonds included in the model portfolios are from a cross-section of different issuers, are rated AA-rated or better, and are non-callable so that the yield to maturity can actually be attained without intervening calls. For 2006, the discount rate was based on the Moody’s Aa Corporate Bond Rate as of September 30, 2006.


	2007		2006
Discount rate	6.12	%	5.66	%
Rate of compensation increases	3.64	%	3.70	%

Additional amounts recognized in the consolidated balance sheets under SFAS 158 are shown below at December 31, 2007 and 2006 (in millions):


	Tax-Qualified						Non-Tax Qualified
	2007			2006			2007			2006
Noncurrent liabilities	$	(38	)	$	(93	)	$	(9	)	$	(9	)

Total liability recognized at measurement date		(38	)		(93	)		(9	)		(9	)

Total liability recognized at year-end	$	(38	)	$	(93	)	$	(9	)	$	(9	)

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Amounts recognized in accumulated other comprehensive income at December 31, 2007 and 2006, under SFAS 158 are as follows (in millions):


	Tax-Qualified						Non-Tax Qualified
	2007			2006			2007			2006
Net gain (loss)	$	7		$	(17	)	$	(1	)	$	(1	)
Prior service cost		(3	)		(3	)		(2	)		(3	)

Total amounts included in accumulated other comprehensive income (expense)	$	4		$	(20	)	$	(3	)	$	(4	)

Expected amortization payments. The estimated net gain (loss) and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $0.2 million and $0.5 million, respectively. Additionally, as of January 1, 2008, Mirant expects to recognize no net gain/(loss) and $0.1 million of prior service cost as other comprehensive income as a result of the adjustment to retained earnings related to the change in measurement date under SFAS 158.

The components of the net periodic benefit cost of Mirant’s continuing operations pension plans for the years ended December 31, 2007, 2006 and 2005, are shown below (in millions):


	Years Ended December 31,
	2007			2006			2005
Service cost	$	9		$	10		$	9
Interest cost		14			14			12
Expected return of plan assets		(13	)		(10	)		(8	)
Net amortization(1)		1			2			—

Net periodic benefit cost	$	11		$	16		$	13

(1)

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

Other changes in plan assets and benefit obligation recognized in other comprehensive income for the year ended December 31, 2007, are shown below (in millions):


Net gain		$ (24)
Prior service credit		(1	)

Total recognized in other comprehensive income	$	(25	)

The resulting total amount recognized in net periodic benefit cost and other comprehensive income for the year ended December 31, 2007, was $14 million.

The weighted average assumptions used for measuring pension benefit cost each year were as follows:


	2007		2006
Discount rate	5.66	%	5.36	%
Rate of compensation increase	3.70	%	3.82	%
Expected long-term rate of return on plan assets	8.50	%	8.50	%

In determining the long-term rate of return for plan assets, the Company evaluates historic and current market factors such as inflation and interest rates before determining long-term capital market assumptions. The Company also considers the effects of diversification and portfolio rebalancing. To check for reasonableness and appropriateness, the Company reviews data about other companies, including their historic returns.

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The following table shows the target allocation and percentage of fair value of plan assets by asset category for Mirant’s qualified pension plans for 2007 and 2006:


	2007				2006
	Target Allocation		Percent of Fair Value of Plan Assets		Target Allocation		Percent of Fair Value of Plan Assets
U.S. Stocks	50	%	55	%	55	%	56	%
Non-U.S. Stocks	20		15		15		14
Fixed income	30		30		30		30

Total	100	%	100	%	100	%	100	%

For the qualified pension plans, Mirant uses a mix of equities and fixed income investments in an attempt to maximize the long-term return of plan assets for a prudent level of risk. The Company’s risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. Equity investments are diversified across U.S. and non-U.S. stocks. For U.S. stocks, Mirant employs both a passive and active approach by investing in an index that mirrors the Russell 1000 Index and an actively managed small cap fund. For non-U.S. stocks, Mirant is invested in an international equity fund that is benchmarked against the Europe, Australia and Far East Index. Fixed income investments include a passive bond market index fund and a long U.S. government/credit index fund which seek to replicate the Lehman Brothers Long Government/Credit Bond Index. Investment risk is monitored on an ongoing basis through quarterly portfolio reviews and annual pension liability measurements.

During 2008, Mirant expects to contribute approximately $22 million to the qualified pension plans and approximately $0.3 million to the non-tax-qualified pension plans. Additionally, Mirant expects the following benefits to be paid from the pension plans (in millions):


Projected Benefit Payments to Plan Participants	Tax- Qualified		Non-Tax Qualified
2008	$	8.2	$	0.3
2009		8.6		0.3
2010		9.1		0.3
2011		9.8		0.3
2012		10.8		0.3
2013 through 2017		75.7		2.2

Other Postretirement Benefits

Mirant also provides certain medical care and life insurance benefits for eligible retired employees which are accounted for on an accrual basis using an actuarial method that recognizes the net periodic costs as employees render service to earn the postretirement benefits. The measurement date for these other postretirement benefit plans is September 30 for each year presented.

The Company adopted SFAS 158 on December 31, 2006, and recognized a decrease in other noncurrent liabilities of $5 million related to its other postretirement benefit plans. Effective December 31, 2008, SFAS 158 also requires that companies measure the funded status of plans as of the year-end balance sheet date. Mirant currently uses September 30 as the date to measure the funded status of its plans. SFAS 158 offers two transition methods for companies that do not use a year-end measurement date to transition to a December 31, 2008, measurement date. Mirant has elected to use the alternative transition method under SFAS 158 for changing its measurement date, which has resulted in a decrease to accumulated deficit of $0.2 million as of January 1, 2008.

During the fourth quarter of 2006, Mirant amended the postretirement benefit plan covering non-union employees to eliminate all employer provided subsidies through a gradual phase-out by 2011. As a result, Mirant recognized a reduction in other postretirement liabilities of $32 million. Since the amendment occurred after the 2006 measurement date, the plan curtailment was recognized during the first quarter of fiscal 2007.

F-31

The following table shows the benefit obligations and funded status for other postretirement benefit plans of Mirant (in millions):


	Years Ended December 31,
	2007			2006
Change in benefit obligation:
Benefit obligation, beginning of year	$	107		$	127
Service cost		1			4
Interest cost		4			7
Amendments		(9	)		(17	)
Actuarial gain		(12	)		(11	)
Curtailments		(32	)		—
Benefits paid		(2	)		(3	)

Benefit obligation, end of year		57			107


Change in plan assets:
Employer contributions		2			3
Benefits paid		(2	)		(3	)

Fair value of plan assets, end of year		—			—


Funded Status:

Funded status at measurement date	$	(57	)	$	(107	)

The weighted average assumptions used for other postretirement benefit obligations as of their respective measurement dates were as follows:


	2007		2006
Discount rate	6.06	%	5.66	%
Rate of compensation increases	3.00	%	3.00	%
Assumed medical inflation for next year
Before age 65	8.00	%	9.00	%
After age 65	9.50	%	11.00	%
Assumed ultimate medical inflation rate	5.00	%	5.00	%
Year in which ultimate rate is reached	2015		2011

An annual increase or decrease in the assumed medical care cost trend rate of 1% would correspondingly increase or decrease the total accumulated benefit obligation at December 31, 2007, by an inconsequential amount.

Additional amounts recognized in the consolidated balance sheet for other postretirement benefit plans at December 31, 2007 and 2006, were as follows (in millions):


	December 31,
	2007			2006
Current liabilities	$	(3	)	$	(4	)
Noncurrent liabilities		(54	)		(103	)

Total liability recognized at measurement date		(57	)		(107	)
Net employer contributions after measurement date		—			1

Total liability recognized at year-end	$	(57	)	$	(106	)

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Amounts recognized in accumulated other comprehensive income for other postretirement benefit plans at December 31, 2007 and 2006, were as follows (in millions):


	December 31,
	2007			2006
Net loss		$(15	)	$	(43	)
Prior service credit		38			48

Total amounts included in accumulated other comprehensive income	$	23		$	5

Expected amortization payments. The estimated net (gain) loss and prior service cost (credit) for other postretirement benefit plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $0.7 million and $(6.6) million, respectively. Additionally, as of January 1, 2008, Mirant expects to recognize $0.2 million of net loss and $1.7 million of prior service credit as other comprehensive income as a result of the adjustment to retained earnings related to the change in measurement date under SFAS 158.

The components of the net periodic cost for Mirant’s postretirement benefit plans during each year are shown below (in millions):


	Years Ended December 31,
	2007			2006			2005
Service cost	$	2		$	4		$	4
Interest cost		4			7			8
Net amortization(1)		(3	)		(1	)		2
Curtailment		(32	)		—			—

Net periodic postretirement benefit cost	$	(29	)	$	10		$	14

(1)

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

Other changes in plan assets and benefit obligation recognized in other comprehensive income for other postretirement benefit plans for the year ended December 31, 2007, were as follows (in millions):


Net gain	$	(12	)
Prior service credit		(9	)
Amortization of:
Net gain		(15	)
Prior service cost		19

Total recognized in other comprehensive income	$	(17	)

The resulting total amount recognized in net periodic postretirement benefit cost and other comprehensive income for the year ended December 31, 2007, was $(46) million.

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The weighted average assumptions used for Mirant’s postretirement benefit costs during each year are shown below:


	December 31,
	2007		2006
Discount rate	5.66	%	5.36	%
Rate of compensation increases	3.00	%	3.00	%
Assumed medical inflation for current year
Before age 65	9.00	%	10.00	%
After age 65	11.00	%	12.50	%
Assumed ultimate medical inflation rate	5.00	%	5.00	%
Year in which ultimate rate is reached	2011		2011

An annual increase or decrease in the assumed medical care cost trend rate of 1% would correspondingly increase or decrease the aggregate of the service and interest cost components of the annual postretirement benefit cost in 2007 by an inconsequential amount.

Mirant expects the following net benefits to be paid from the postretirement benefit plans (in millions):


Projected Benefit Payments to Plan Participants	Before Medicare Subsidy		Medicare Subsidy
2008	$	2.8	$	0.0
2009		2.8		0.0
2010		2.8		0.0
2011		2.3		0.0
2012		2.7		0.0
2013 through 2017		19.9		0.6

Employee Savings Plan

The Company maintains a defined contribution employee savings plan with a profit sharing arrangement whereby employees may contribute a portion of their base compensation to the employee savings plan, subject to limits under the Internal Revenue Code. The Company provides a matching contribution each payroll period equal to 75% of the employee’s contributions up to 6% of the employee’s pay for that period. For unionized employees, matching levels vary by bargaining unit.

Under the profit sharing arrangement, the Company contributes a quarterly fixed contribution of 3% of eligible pay and may make an annual discretionary contribution for those employees not accruing a benefit under the defined benefit pension plan.

Expenses recognized for the matching and profit sharing contributions were as follows (in millions):

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Stock-based Compensation

The Mirant Corporation 2005 Omnibus Incentive Plan for certain employees and directors of Mirant became effective on January 3, 2006. The Omnibus Incentive Plan provides for the granting of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards, other stock-based awards, covered employee annual incentive awards and non-employee director awards. Under the Omnibus Incentive Plan, 18,575,851 shares of Mirant common stock are available for issuance to participants. Shares covered by an award are counted as used only to the extent that they are actually issued. Any shares related to awards that terminate by expiration, forfeiture, cancellation or otherwise without the issuance of such shares will be available again for grant under the Omnibus Incentive Plan. The Company had both service condition and performance condition forms of stock-based compensation at December 31, 2007.

On October 5, 2006, the Compensation Committee of the Board of Directors approved the implementation of a special bonus plan to reward participants for successful completion of the Company’s planned business and asset sales as well as to provide certain participants with an incentive to remain with the Company. The grants consisted of cash and restricted stock units. On November 13, 2006, the Company’s Compensation Committee, pursuant to the Company’s 2005 Omnibus Incentive Plan, awarded certain equity grants to five executive management members. The grants consist of options to acquire the Company’s common stock and restricted stock units. These grants were considered performance condition awards, as the payout under the November 13, 2006, awards was based on achieving certain target amounts related to the sales of the Company’s Philippine and Caribbean businesses and six natural gas-fired facilities in the United States. The performance conditions were met at December 31, 2007, and the awards become fully vested and non forfeitable on June 30, 2008.

SFAS 123R was adopted by the Company during the first quarter of 2006, using the modified prospective transition method. For the year ended December 31, 2007, the Company recognized approximately $21 million and $8 million of compensation expense, respectively, related to service condition and performance condition stock-based compensation. For the year ended December 31, 2006, the Company recognized approximately $16 million and $1 million, respectively, related to service condition and performance condition stock-based compensation. These amounts are included in operations and maintenance expense in the consolidated statements of operations, with the exception of approximately $4 million for the year ended December 31, 2007, which is included in income (loss) from discontinued operations, net.

Prior to the Company’s adoption of SFAS No.123R, Mirant accounted for stock-based employee compensation plans under the intrinsic-value method of accounting for recognition, but disclosed fair value pro forma information. Under that method, compensation expense for employee stock options is measured on the date of grant only if the current market price of the underlying stock exceeds the exercise price. The following table illustrates the effect on net income for the year ended December 31, 2005, if the fair-value-based method had been applied to all outstanding and unvested stock-based awards (in millions):


	Year Ended December 31, 2005
Net loss, as reported	$	(1,307	)
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects		(3	)

Pro forma net loss	$	(1,310	)

All share-based payment awards issued prior to the Company’s emergence from bankruptcy were cancelled. As a result, the presentation of information above for the year ended December 31, 2005, is not comparable to the information that follows for the years ending December 31, 2006 and 2007. Additionally, the Company’s

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pre-bankruptcy capital structure differed significantly from the Company’s post-emergence capital structure, further degrading comparability between the pre-emergence and post-emergence periods.

As of December 31, 2007, there were approximately $24 million and $3 million, respectively, of total unrecognized compensation cost, excluding estimated forfeitures, related to non-vested share-based compensation granted through service condition and performance condition awards, which is expected to be recognized on a straight-line basis over a weighted average period of 1 year.

Stock Options

The fair value of stock options is estimated on the date of grant using a Black-Scholes option-pricing model based on the assumptions noted in the following table. As a result of the Company’s bankruptcy and other factors, historical information concerning the Company’s stock price volatility for purposes of valuing stock option grants is not sufficient. Therefore, the implied volatility derived from peer group companies was used as the basis for valuing the stock options granted through September 30, 2006. Beginning in the fourth quarter 2006, the Company re-evaluated the use of implied volatility derived from peer group companies and determined that sufficient evidence existed to place exclusive reliance on Mirant’s own implied volatility of its traded options in accordance with SAB 107. 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. For performance condition awards, the Company utilized the contractual term as the expected term. 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. The table below includes significant assumptions used in valuing the Company’s stock options:


	Years Ended December 31,
	2007		2006
	Range	Weighted Average	Range	Weighted Average
Expected volatility	15-28%	19.9%	21 - 37%	31.6%
Expected dividends	—%	—%	—%	—%
Expected term
Service condition awards	2.7- 3.5 years	3.48 years	5.2 - 6 years	5.9 years
Performance condition awards	—	—	3 years	3 years
Risk-free rate	4 - 4.7%	4%	4.3 - 5.1%	4.5%

Service Condition Awards

During 2006, Mirant made awards of nonqualified stock options to purchase approximately 3 million shares. These stock options were granted with a 10-year term. Options to purchase approximately 1.8 million shares vest 25% six months from the grant date, and 25% on each of the first, second and third anniversaries of the grant date. Options to purchase approximately 1.1 million shares vest in three equal installments on each of the first, second and third anniversaries of the grant date. Options to purchase approximately 41,000 shares were granted to non-management members of the Board of Directors and vest one year from the grant date.

During 2007, the Company granted options to purchase a total of approximately 605,000 shares. These stock options were granted with a five-year term, and vest in three equal installments on each of the first, second and third anniversaries of the grant date. Options to purchase approximately 15,000 shares were granted to non-management members of the Board of Directors and vest one year from the grant date.

The granted options provide for accelerated vesting if there is a change of control (as defined in the Omnibus Incentive Plan) or, in certain circumstances, as a result of a termination of employment. Options to purchase approximately 1.1 million and 525,000 shares vested during 2007 and 2006, respectively, of which approximately 177,000 and 87,000 respectively, became exercisable as a result of accelerated vesting resulting

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from the termination of an employee. The weighted average grant-date fair value of stock options granted during the years ended December 31, 2007 and 2006, was $8.44 and $10.42 per share, respectively.

A summary of the Company’s option activity under the Omnibus Incentive Plan is presented below:


Stock Options	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (years)	Aggregate Intrinsic Value (in thousands)
Outstanding at January 1, 2006	—			—
Granted	2,987,936		$	24.89
Exercised or converted	(23,287	)	$	25.05
Forfeited	(162,930	)	$	24.96
Expired	—			—

Outstanding at December 31, 2006	2,801,719		$	24.89	9.2	$	18,720
Granted	605,386		$	37.91
Exercised or converted	(371,306	)	$	25.98
Forfeited	(131,755	)	$	29.64
Expired	—			—

Outstanding at December 31, 2007	2,904,044		$	27.25	7.4	$	34,069

Exercisable or convertible at December 31, 2006	501,669		$	24.83	9.1	$	3,379

Exercisable or convertible at December 31, 2007	1,095,190		$	22.64	8.0	$	15,230

The range of exercise prices for stock options granted is presented below:


	Hi		Low
2007	$	45.77	$	37.71
2006	$	28.89	$	23.70

Cash received from the exercise of stock options under the Omnibus Incentive Plan for the years ended December 31, 2007 and 2006, was approximately $10 million and $583,000, respectively, and no tax benefit was realized during the years then ended.

Performance Condition Awards

On November 13, 2006, Mirant made awards of nonqualified stock options to purchase approximately 830,000 shares to five members of executive management. These options were granted with a 3-year term and vest on June 30, 2008, provided that the Company achieved the performance target amounts by December 31, 2007, which it did. The options provide for accelerated vesting if there is a change of control (as defined in the Omnibus Incentive Plan) or, in certain circumstances, as a result of a termination of employment. As of December 31, 2007, options to purchase approximately 100,000 shares became exercisable as a result of accelerated vesting resulting from the termination of an employee. The weighted average grant date fair value of performance condition stock options granted during the year ended December 31, 2006, was $6.08 per share. There were no performance condition stock options granted during 2007.

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A summary of option activity for performance condition awards under the Omnibus Incentive Plan is presented below:


Stock Options	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (years)	Aggregate Intrinsic Value (in thousands)
Outstanding at January 1, 2006	—		—
Granted	830,000	$	28.89
Exercised or converted	—		—
Forfeited	—		—
Expired	—		—

Outstanding at December 31, 2006	830,000	$	28.89	2.9	$	2,224
Granted	—		—
Exercised or converted	—		—
Forfeited	—		—
Expired	—		—

Outstanding at December 31, 2007	830,000	$	28.89	1.9	$	8,375

Exercisable or convertible at December 31, 2006	—		—

Exercisable or convertible at December 31, 2007	100,000	$	28.89	1.9	$	1,009

Restricted Stock Shares and Restricted Stock Units

Service Condition Awards

During 2006, the Company issued approximately 392,000 restricted stock units and 205,000 restricted stock shares under the Omnibus Incentive Plan. Approximately 350,000 restricted stock units vest 25% six months from the grant date, and 25% on each of the first, second and third anniversaries of the grant date. Approximately 34,000 of the restricted stock units and 205,000 of the restricted stock shares vest in three equal installments on each of the first, second and third anniversaries of the grant date. Approximately 8,000 of the restricted stock units were granted to non-management members of the Board of Directors and vest one year from the grant date. The granted restricted stock units and restricted stock shares provide for accelerated vesting if there is a change of control (as defined in the Omnibus Incentive Plan) or, in certain circumstances, as a result of a termination of employment. Approximately 105,000 restricted stock units vested during the year ended December 31, 2006, of which approximately 17,000 became fully vested as a result of the termination of an employee.

During 2007, the Company issued approximately 428,000 restricted stock units under the Omnibus Incentive Plan. Approximately 419,000 of the restricted stock units vest on each of the first, second and third anniversaries of the grant date. Approximately 9,000 of the restricted stock units were granted to non-management members of the Board of Directors and vest one year from the grant date. The granted restricted stock units and restricted stock shares provide for accelerated vesting if there is a change of control (as defined in the Omnibus Incentive Plan) or, in certain circumstances, as a result of a termination of employment. Approximately 213,000 and 105,000 restricted stock units vested during the years ended December 31, 2007 and 2006, respectively, of which, approximately 54,000 and 17,000, respectively, became fully vested as a result of the termination of an employee.

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The grant date fair value of the restricted stock shares and restricted stock units is equal to the Company’s closing stock price on the grant date. A summary of the Company’s restricted stock shares and restricted stock units for service condition award is presented below:


Restricted Stock Shares and Restricted Stock Units	Number of Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2006	—			—
Granted	597,596		$	24.89
Vested	(104,991	)	$	24.84
Forfeited	(32,586	)	$	24.96
Expired	—			—

Outstanding at December 31, 2006	460,019		$	24.90
Granted	428,035		$	37.89
Vested	(212,700	)	$	26.65
Forfeited	(45,381	)	$	33.16
Expired	—			—

Outstanding at December 31, 2007	629,973		$	32.54

Performance Condition Awards

During 2006, the Company issued 283,554 restricted stock units under the Omnibus Incentive Plan. Approximately 140,000 were awarded on October 31, 2006 to certain key employees and approximately 143,000 on November 13, 2006, to five members of executive management. The restricted stock units vest on June 30, 2008, provided that the Company achieves the performance target amounts by December 31, 2007, which it did. The granted restricted stock units provide for accelerated vesting if there is a change of control (as defined in the Omnibus Incentive Plan) or, in certain circumstances, as a result of a termination of employment. Approximately 37,000 restricted stock units and shares vested during the year ended December 31, 2007, as a result of the termination of an employee. The grant date fair value of the restricted stock and restricted stock units for performance condition awards is equal to the Company’s closing stock price on the grant date.

A summary of the Company’s restricted stock units awarded is as follows:


Restricted Stock Units	Number of Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2006	—			—
Granted	283,554		$	29.23
Vested	—			—
Forfeited	—			—
Expired	—			—

Outstanding at the December 31, 2006	283,554		$	29.23
Granted
Vested	(36,891	)	$	29.25
Forfeited	—			—
Expired	—			—

Outstanding at December 31, 2007	246,663		$	29.22

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9.	Asset Retirement Obligations

Effective January 1, 2003, the Company adopted SFAS 143, which requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Additionally, effective December 31, 2005, the Company adopted FIN 47, which expands the scope of asset retirement obligations to be recognized to include asset retirement obligations that may be uncertain as to the nature or timing of settlement. Upon initial recognition of a liability for an asset retirement obligation or a conditional asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS 143 and FIN 47 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

The Company identified certain asset retirement obligations within its power generating facilities. These asset retirement obligations are primarily related to asbestos abatement in facilities on owned or leased property and other environmental obligations related to fuel storage facilities, wastewater treatment facilities, ash disposal sites and pipelines.

Asbestos abatement is the most significant type of asset retirement obligation identified for recognition in the Company’s adoption of FIN 47. The EPA has regulations in place governing the removal of asbestos. Due to the nature of asbestos, it can be difficult to ascertain the extent of contamination in older facilities unless substantial renovation or demolition takes place. Therefore, the Company incorporated certain assumptions based on the relative age and size of its facilities to estimate the current cost for asbestos abatement. The actual abatement cost could differ from the estimates used to measure the asset retirement obligation. As a result, these amounts will be subject to revision when actual abatement activities are undertaken.

The following table sets forth the balances of the asset retirement obligations as of January 1, 2006, and the additions and accretion of the asset retirement obligations for the years ended December 31, 2007 and 2006. The asset retirement obligations are included in noncurrent liabilities in the consolidated balance sheets (in millions):


	For the Years Ended December 31,
	2007			2006
Beginning balance January 1	$	40		$	34
Liabilities recorded in the period		3			5
Liabilities settled during the period		(2	)		(2	)
Accretion expense		3			3

Ending balance, December 31	$	44		$	40

The following represents, on a pro forma basis, the amount of the liability for asset retirement obligations as if FIN 47 had been applied during all periods affected (in millions):


	For the Year Ended December 31, 2005
Beginning balance January 1	$	36
Revisions to cash flows for liabilities recognized upon adoption of SFAS 143		(5	)
Accretion expense		3

Ending balance, December 31	$	34

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10.

Commitments and Contingencies

Mirant has made firm commitments to buy materials and services in connection with its ongoing operations and has made financial guarantees relative to some of its investments.

Cash Collateral

In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, the Company often is required to provide trade credit support to its counterparties or make deposits with brokers. In addition, the Company often is required to provide cash collateral for access to the transmission grid to participate in power pools and for other operating activities. In the event of default by the Company, the counterparty can apply cash collateral held to satisfy the existing amounts outstanding under an open contract.

The following is a summary of cash collateral posted with counterparties as of December 31, 2007 and 2006 (in millions):


	At December 31,
	2007		2006
Cash collateral posted—energy trading and marketing	$	96	$	27
Cash collateral posted—other operating activities		14		13

Total	$	110	$	40

Commitments

In addition to debt and other obligations in the consolidated balance sheets, Mirant has the following annual commitments under various agreements at December 31, 2007, related to its operations (in millions):


	Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations by Year
	Total		2008		2009		2010		2011		2012		>5 Years
Operating:
Mirant Mid-Atlantic operating leases	$	2,133	$	121	$	142	$	140	$	134	$	132	$	1,464
Other operating leases		70		10		10		10		9		8		23
Fuel commitments		506		314		192		—		—		—		—
Long-term service agreements		31		2		2		2		2		5		18
Other		153		153		—		—		—		—		—

Investing :
Maryland Healthy Air Act		713		689		24		—		—		—		—

Total payments	$	3,606	$	1,289	$	370	$	152	$	145	$	145	$	1,505

Operating Leases

Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively. Mirant Mid-Atlantic has an option to extend the leases. Any extensions of the respective leases would be limited to 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. The Company is accounting for these leases as operating leases and recognizes rent expense on a straight-line basis. Rent expense totaled $96 million for the years ended December 31, 2007 and 2006 and $99 million for the year ended

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December 31, 2005, and is included in operations and maintenance expense in the accompanying consolidated statements of operations. As of December 31, 2007 and 2006, the Company has paid approximately $330 million and $314 million, respectively, of lease payments in excess of rent expense recognized, which is recorded in prepaid rent on the consolidated balance sheets.

As of December 31, 2007, the total notional minimum lease payments for the remaining terms of the leases aggregated approximately $2.1 billion and the aggregate termination value for the leases was approximately $1.4 billion and generally decreases over time. Mirant Mid-Atlantic leases the Morgantown and the Dickerson baseload units from third party owner lessors. These owner lessors each own the undivided interests in these baseload generating facilities. The subsidiaries of the institutional investors who hold the membership interests in the owner lessors are called owner participants. Equity funding by the owner participants plus transaction expenses paid by the owner participants totaled $299 million. The issuance and sale of pass through certificates raised the remaining $1.2 billion needed for the owner lessors to acquire the undivided interests.

The pass through certificates are not direct obligations of Mirant Mid-Atlantic. Each pass through certificate represents a fractional undivided interest in one of three pass through trusts formed pursuant to three separate pass through trust agreements between Mirant Mid-Atlantic and U.S. Bank National Association (as successor in interest to State Street Bank and Trust Company of Connecticut, National Association), as pass through trustee. The property of the pass through trusts consists of lessor notes. The lessor notes issued by an owner lessor are secured by that owner lessor’s undivided interest in the lease facilities and its rights under the related lease and other financing documents.

Mirant has commitments under other operating leases with various terms and expiration dates. Minimum lease payments under non-cancelable operating leases approximate $7 million in each of 2008, 2009 and 2010, $6 million in 2011, $5 million in 2012, and $19 million thereafter.

Fuel Commitments

Fuel commitments primarily relate to long-term coal agreements and other fuel purchase agreements. As of December 31, 2007, Mirant’s total estimated fuel commitments were $506 million. In addition, the Company has transactions for which commercial terms have been negotiated but for which contracts have not yet been executed. Individual transactions may or may not be binding prior to execution of a contract.

Long-Term Service Agreements

As of December 31, 2007, the total estimated commitments under LTSAs associated with turbines were approximately $31 million. These commitments are payable over the terms of the respective agreements, which range from ten to twenty years. These agreements have terms that allow for cancellation of the contracts by the Company upon the occurrence of certain events during the term of the contracts. Estimates for future commitments for the LTSAs are based on the stated payment terms in the contracts at the time of execution. These payments are subject to an annual adjustment for inflation.

Other

Other represents the open purchase orders less invoices received related to open purchase orders for procurement of products and services purchased in the ordinary course of business. These include construction, maintenance and labor activities at the Company’s generating facilities.

Maryland Healthy Air Act

Maryland Healthy Air Act commitments are contracts and open purchase orders related to capital expenditures that the Company expects to incur to comply with the limitations for SO2 and NOx emissions under the Maryland Healthy Air Act.

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Guarantees

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, engagement agreements with vendors and other third parties. While 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, since 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. 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 that met the recognition requirements under FIN 45 at December 31, 2007.

Alternatively, guarantees between and on behalf of entities under common control are subject only to the disclosure provisions of the interpretation. The Company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

Letters of Credit

As of December 31, 2007, Mirant and its subsidiaries were contingently obligated for $290 million under letters of credit issued under the credit facilities of Mirant North America, which includes $199 million letters of credit issued pursuant to its senior secured term loan and $91 million letters of credit issued pursuant to its revolving credit facility. Most of these letters of credit are issued in support of the obligations of Mirant North America and its subsidiaries to perform under commodity agreements, financing or lease agreements or other commercial arrangements. In the event of default by the Company, the counterparty can draw on a letter of credit to satisfy the existing amounts outstanding under an open contract. A majority of these letters of credit expire within one year of issuance, and it is typical for them to be renewed on similar terms.

Following is a summary of letters of credit issued as of December 31, 2007 and 2006 (in millions):


	At December 31,
	2007		2006
Letters of credit—energy trading and marketing	$	100	$	100
Letters of credit—debt service and rent reserves		78		84
Letters of credit—other operating activities		112		15

Total	$	290	$	199

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Purchase and Sale Guarantees and Indemnifications

In connection with the purchase or sale of an asset or a business by Mirant or a subsidiary, Mirant is typically required to provide certain assurances to the counterparties for the performance of the obligations of such a subsidiary under the purchase or sale agreements. Such assurances may take the form of a guarantee issued by Mirant or a subsidiary on behalf of the obligor subsidiary. The scope of such guarantees would typically include any indemnity obligations owed to such counterparty. While the terms thereof vary in the scope, exclusions, thresholds and applicable limits, the indemnity obligations of a seller typically include liabilities incurred as a result of a breach of a purchase and sale agreement, including the indemnifying party’s representations or warranties, unpaid and unreserved tax liabilities and specified retained liabilities, if any. These obligations generally have a term of 12 months from the closing date and are intended to protect the non-indemnifying parties against breaches of the agreement or risks that are difficult to predict or estimate at the time of the transaction. In most cases, the contract limits the liability of the indemnifying party. Subject to certain standard exclusions, the potential indemnity exposure of Mirant under the recent sales of its Caribbean business, its Philippine business and its six U.S. natural gas-fired facilities is limited to fifteen percent (15%), ten percent (10%) and ten percent (10%) of the respective sale prices. As of December 31, 2007, Mirant and its subsidiaries’ contingent obligation for such assurances was $532 million. The Company does not expect that it will be required to make any material payments under these guarantee and indemnity provisions.

Commercial Purchase and Sales Arrangements

In connection with the purchase and sale of fuel, emission allowances and energy to and from third parties with respect to the operation of Mirant’s generating facilities, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments. The majority of the guarantees are set to expire before the end of 2010, although the obligations of the issuer will remain in effect until all the liabilities created under the guarantee have been satisfied or no longer exist. As of December 31, 2007, Mirant and its subsidiaries were contingently obligated for a total of $93 million under such arrangements. The Company does not expect that it will be required to make any material payments under these guarantees.

Other Guarantees and Indemnifications

As of December 31, 2007, Mirant has issued $67 million of guarantees of obligations that its subsidiaries may incur as a provision for construction agreements, equipment leases, and on-going litigation. The Company does not expect that it will be required to make any material payments under these guarantees.

The Company, through its subsidiaries, participates in several power pools with RTOs. The rules of these RTOs require that each participant indemnify the pool for defaults by other members. Usually, the amount indemnified is based upon the activity of the participant relative to the total activity of the pool and the amount of the default. Consequently, the amount of such indemnification by the Company cannot be quantified.

On a routine basis in the ordinary course of business, Mirant and its subsidiaries indemnify financing parties and consultants or other vendors who provide services to the Company. The Company does not expect that it will be required to make any material payments under these indemnity provisions.

Because some of the guarantees and indemnities Mirant issues to third parties do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the Company’s liability exposure, the Company may not be able to estimate its potential liability until a claim is made for payment or performance, because of the contingent nature of these contracts.

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11.

Dispositions

Overview

The Company had no assets or liabilities held for sale at December 31, 2007. Assets and liabilities held for sale at December 31, 2006, included discontinued operations and other assets that the Company disposed of in 2007. In the third quarter of 2006, Mirant commenced separate auction processes to sell its Philippine (2,203 MW) and Caribbean (1,050 MW) businesses and six U.S. natural gas-fired facilities totaling 3,619 MW, consisting of the Zeeland (903 MW), West Georgia (613 MW), Shady Hills (469 MW), Sugar Creek (561 MW), Bosque (546 MW) and Apex (527 MW) facilities.

The sale of the six U.S. natural gas-fired facilities was completed on May 1, 2007. In the third quarter of 2006, the Company recorded an impairment loss of $396 million to reduce the carrying value of the six facilities held for sale to estimated fair value. In subsequent periods, the Company recorded reductions to the impairment loss of approximately $51 million resulting from the sale process. As a result, the Company recognized a cumulative loss of $345 million related to the sale of the six facilities. The net proceeds to Mirant after transaction costs and retiring $83 million of project-related debt were $1.306 billion.

The Company completed the sale of Mirant NY-Gen on May 7, 2007. The Company recognized a gain of $8 million related to the sale. The proceeds related to the sale were immaterial as a result of the transfer of the net liabilities of Mirant New York-Gen.

The sale of the Philippine business was completed on June 22, 2007. The Company recognized a gain of $2.003 billion related to the sale. The net proceeds to Mirant after transaction costs and the repayment of $642 million of debt were $3.21 billion.

The sale of the Caribbean business was completed on August 8, 2007. The Company recognized a gain of approximately $63 million in the third quarter of 2007 related to the sale. The net proceeds to Mirant after transaction costs were $555 million. The gain and net proceeds are subject to final working capital adjustments.

The table below presents the components of the balance sheet accounts classified as assets and liabilities held for sale for the year ended December 31, 2006 (in millions):


	At December 31, 2006
Current Assets	$	893
Property, Plant and Equipment, net		3,489

Total Assets		4,382

Noncurrent Assets:
Investments		224
Other Noncurrent Assets		381

Total Noncurrent Assets		605

Total Assets	$	4,987

Current Liabilities:
Short-term Debt	$	25
Current Portion of Long-term Debt		166
Other Current Liabilities		245

Total Current Liabilities		436

Noncurrent Liabilities:
Long-term Debt		1,149
Other Noncurrent Liabilities		633

Total Noncurrent Liabilities		1,782

Total Liabilities	$	2,218

F-45

During the second quarter of 2007, the Company recognized $9 million of other comprehensive income, net of tax, related to the sale of the Philippine business. Of this amount, $5 million was related to a pension liability that was settled as part of the sale and $4 million was related to a cumulative translation adjustment. During the third quarter of 2007, the Company recognized $11 million of other comprehensive loss, net of tax, related to pension and other postretirement benefits as part of the sale of the Caribbean business.

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 have been disposed of as of December 31, 2007.

The Company sold its Wrightsville power generating facility in 2005, but retained transmission credits that arose from transmission system upgrades associated with the construction of the Wrightsville facility. During the third quarter of 2007, Mirant entered into an agreement that established the amount of the outstanding transmission credits. As a result of the agreement, Mirant recognized a gain of $24 million in income from discontinued operations in the third quarter of 2007.

For the year ended December 31, 2007, income from discontinued operations included the results of operations of the Caribbean business, the Philippine business, the six U.S. natural gas-fired facilities and Mirant NY-Gen through their respective dates of sale and the gain related to Wrightsville described above. For the year ended December 31, 2006, income from discontinued operations included the results of operations of all the discontinued businesses and assets for the entire year, as well as the Wichita Falls facility in Texas through its May 2006 date of sale. For the year ended December 31, 2005, income from discontinued operations also included the results of operations of the Wrightsville generating facility through its date of sale in the third quarter of 2005.

A summary of the operating results for these discontinued operations for the years ended December 31, 2007, 2006 and 2005 is as follows (in millions):


	Year Ended December 31, 2007
	U.S.			Philippines			Caribbean			Total
Operating revenues	$	82		$	200		$	514		$	796
Operating expenses (income):
Gain on sales of assets		(38	)		(2,003	)		(63	)		(2,104	)
Other operating expenses		56			67			433			556

Total operating expenses (income)		18			(1,936	)		370			(1,548	)

Operating income		64			2,136			144			2,344
Provision (benefit) for income taxes		—			704			13			717
Other expense (income), net		—			33			32			65

Net income	$	64		$	1,399		$	99		$	1,562


	Year Ended December 31, 2006
	U.S.			Philippines			Caribbean		Total
Operating revenues	$	303		$	469		$	825	$	1,597
Operating expenses:
Loss on sales of assets		375			—			—		375
Other operating expenses		221			187			686		1,094

Total operating expenses		596			187			686		1,469

Operating income (loss)		(293	)		282			139		128
Provision (benefit) for income taxes		1			(104	)		26		(77	)
Other expense (income), net		9			30			54		93

Net income (loss)	$	(303	)	$	356		$	59	$	112

F-46


	Year Ended December 31, 2005
	U.S.			Philippines			Caribbean		Total
Operating revenues	$	344		$	488		$	729	$	1,561
Operating expenses:
Loss (gain) on sales of assets		9			(1	)		—		8
Other operating expenses		315			196			623		1,134

Total operating expenses		324			195			623		1,142

Operating income		20			293			106		419
Provision (benefit) for income taxes		—			135			6		141
Other expense (income), net		103			44			38		185

Net income (loss)	$	(83	)	$	114		$	62	$	93

On July 12, 2006, the Company’s Sual generating facility in the Philippines had an unplanned outage of unit 2 as a result of a failure of the generator. The repairs on unit 2 were completed on March 4, 2007, and the unit returned to operation. On October 23, 2006, unit 1 at the Sual generating facility had an unplanned outage as a result of a failure of the generator. The repairs on unit 1 were completed on June 12, 2007, and the unit returned to operation.

As part of the sale of the Philippine business, Mirant retained the rights to future insurance recoveries related to the Sual outages. In 2007, the Company received a total of $23 million related to these recoveries. Additional recoveries will be recognized in discontinued operations when outstanding claims are resolved.

As part of the sale of Mirant NY-Gen, Mirant retained the rights to future insurance recoveries related to repairs of the dam at the Swinging Bridge facility. In the fourth quarter of 2007, the Company reached an insurance settlement and recognized a gain of $10 million, which is included in income from discontinued operations.

12.

Bankruptcy Related Disclosures

Mirant’s Plan was confirmed by the Bankruptcy Court on December 9, 2005, and the Company emerged from bankruptcy on January 3, 2006. For financial statement presentation purposes, Mirant recorded the effects of the Plan at December 31, 2005.

At December 31, 2007 and 2006, amounts related to allowed claims, estimated unresolved claims and professional fees associated with the bankruptcy that are to be settled in cash were $27 million and $28 million, respectively, and these amounts were recorded in accounts payable and accrued liabilities on the accompanying consolidated balance sheets. These amounts do not include unresolved claims that will be settled in common stock or the stock portion of claims that are expected to be settled with cash and stock. For the year ended December 31, 2007, the Company paid approximately $53 million in cash related to bankruptcy claims, which is reflected in cash flows from operating activities from continuing operations. For the year ended December 31, 2006, the Company paid approximately $1.849 billion, in cash related to bankruptcy claims. Of this amount, approximately $990 million is reflected in cash flows from financing activities from continuing operations and $45 million from discontinued operations and together represent the principal amount of debt claims. As of December 31, 2007, approximately one million of the shares of Mirant common stock to be distributed under the Plan have not yet been distributed and have been reserved for distribution with respect to claims that are disputed by the Mirant Debtors and have yet to be resolved. See Note 18 for further discussion of the Chapter 11 proceedings.

F-47

Mirant New York Subsidiaries

The Company’s New York subsidiaries, Mirant New York, Mirant Bowline, Mirant Lovett, Hudson Valley Gas and Mirant NY-Gen, remained in bankruptcy at December 31, 2006. On January 26, 2007, Mirant New York, Mirant Bowline (which owns the Bowline facility) and Hudson Valley Gas (collectively the “Emerging New York Entities”) filed their Supplemental Joint Chapter 11 Plan of Reorganization with the Bankruptcy Court and subsequently filed amendments to that plan (as subsequently amended, the “Supplemental Plan”). The Supplemental Plan was confirmed by the Bankruptcy Court on March 23, 2007, and became effective on April 16, 2007, resulting in the Emerging New York Entities’ emergence from bankruptcy. For financial statement presentation purposes, the effects of the Supplemental Plan were recorded on March 31, 2007.

On January 31, 2007, Mirant New York entered into an agreement for the sale of Mirant NY-Gen, which owned the Hillburn and Shoemaker gas turbine facilities and the Swinging Bridge, Rio and Mongaup hydroelectric generating facilities. The sale closed on May 7, 2007, and the Company recognized a gain of $8 million. Mirant NY-Gen emerged from bankruptcy under a plan of reorganization that incorporated the sale and was approved by the Bankruptcy Court on April 27, 2007.

On July 13, 2007, Mirant Lovett (which owns the Lovett facility) filed a plan of reorganization (the “Mirant Lovett Plan”) with the Bankruptcy Court. The Mirant Lovett Plan was confirmed by the Bankruptcy Court on September 19, 2007, and became effective on October 2, 2007, resulting in Mirant Lovett’s emergence from bankruptcy. For financial statement presentation purposes, the effects of the Mirant Lovett Plan were recorded on September 30, 2007. As a result of Mirant Lovett’s emergence, Mirant has no subsidiaries that remain in bankruptcy. See Note 18 for further discussion regarding Mirant Lovett’s emergence from bankruptcy.

Reorganization Items, net

Reorganization items, net represents expense, income and gain or loss amounts that were recorded in the financial statements as a result of the bankruptcy proceedings. In 2006, reorganization items, net relate to refunds received from various New York tax jurisdictions for the settlement of the property tax dispute related to the New York subsidiaries. Reorganization items, net for the years ended December 31, 2007, 2006 and 2005, are comprised of the following (in millions):


	Years Ended December 31,
	2007			2006			2005
Gain on the implementation of the Plan		$ —		$	—		$	(285	)
Gain on New York property tax settlement		—			(163	)		—
Estimated claims and losses on rejected and amended contracts(1)		—			—			72
Professional fees and administrative expense		3			2			226
Interest income, net		(5	)		(3	)		(31	)

Total		$(2	)	$	(164	)	$	(18	)

(1)	Estimated claims and losses on rejected and amended contracts relate primarily to rejected energy contracts, such as tolling agreements and gas transportation and electric transmission contracts.

Interest Expense

In the third quarter of 2005, the Company determined that it was probable that contractual interest on liabilities subject to compromise from the Petition Date would be incurred for certain claims expected to be allowed under Mirant’s Plan. As a result, the Company recorded interest expense of approximately $1.4 billion in 2005 on liabilities subject to compromise. This amount represents interest from the Petition Date through the effective date of the Plan. The interest amount was calculated based on the provisions of the Plan. The $1.4 billion expense amount included approximately $450 million related to Mirant Americas Generation senior notes maturing in 2011, 2021 and 2031, which were reinstated under the confirmed Plan.

F-48

13.

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 December 31, 2007, approximately one million shares of common stock are reserved for unresolved claims pursuant to Mirant’s emergence from bankruptcy.

Mirant also issued two series of warrants that will expire on January 3, 2011. The Series A and Series B warrants entitle the holders to purchase an aggregate of approximately 35 million and 18 million shares of New Mirant common stock, respectively. The exercise price of the Series A and Series B warrants is $21.87 and $20.54 per share, respectively. The exercise price and number of common shares issuable are subject to adjustments based on the occurrence of certain events, including (1) dividends or distributions, (2) rights offerings or (3) other distributions. Mirant’s common stock is currently traded on the NYSE under the ticker symbol MIR. At December 31, 2007 and 2006, approximately 182,000 and 88,000 of Series A warrants, respectively and 463,000 and 11,000 of Series B warrants, respectively, have been exercised. At December 31, 2007, 35,023,201 and 17,172,929 of Series A and Series B warrants, respectively, remain outstanding.

On January 3, 2006, the Omnibus Incentive Plan for certain employees and directors of Mirant became effective. Under the Omnibus Incentive Plan, 18,575,851 shares of Mirant common stock are available for issuance to participants. See Note 8 for further discussion of the Omnibus Incentive Plan.

During the third quarter of 2006, the Company repurchased 43 million shares of Mirant common stock for an aggregate purchase price of approximately $1.228 billion. On September 28, 2006, the Company announced that its Board of Directors had authorized a $100 million share repurchase program which expired in September 2007. As of September 30, 2007, the Company had repurchased 1.18 million shares under this program.

In January 2007, the Company began a program of repurchasing shares at market prices from stockholders holding less than 100 shares of Mirant stock. For the year ended December 31, 2007, the Company repurchased approximately 245,000 shares for approximately $9 million.

In the fourth quarter of 2007, the Company announced that it would return a total of $4.6 billion of excess cash to its stockholders. Mirant entered into an accelerated share repurchase program with JP Morgan Chase Bank, National Association, London Branch (“JP Morgan”). Under the terms of the accelerated share repurchase program, Mirant repurchased 26.66 million shares of its outstanding common stock from JP Morgan, for a total of $1 billion based on the closing price of Mirant’s common stock on November 9, 2007. Upon receipt of the shares, the accelerated share repurchase program met the necessary criteria to be accounted for as an equity contract. As such, changes in the fair value will not be recorded in the Company’s consolidated financial statements. Under the accelerated share repurchase program, the final price of shares repurchased will be determined based on a discount to the volume weighted average trading price of Mirant’s common stock over a period not to exceed six months. Depending on the final price and number of shares repurchased, JP Morgan may deliver additional shares to Mirant at the completion of the transaction, or Mirant may deliver to JP Morgan either cash or shares that were previously delivered under the accelerated share repurchase agreement. In addition to the accelerated share repurchase program, the Company also entered into an open market purchase agreement with JP Morgan Securities, Inc. to purchase up to $1 billion of its outstanding common stock. As of December 31, 2007, the Company had purchased approximately 8.27 million shares in open market purchases for approximately $316 million. Between January 1, 2008 and February 25, 2008, the Company purchased an additional 7.9 million shares in open market purchases for approximately $286 million. 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.

F-49

14.

Earnings per Share

On January 3, 2006, all shares of Mirant’s old common stock were cancelled and 300 million shares of new common stock were issued. Mirant also issued two series of warrants that will expire on January 3, 2011. Therefore, earnings per share information for 2005 has not been presented because the information is not relevant in any material respect for users of its financial statements.

Mirant calculates basic EPS by dividing income available to stockholders by the weighted average number of common shares outstanding. Diluted EPS gives effect to dilutive potential common shares, including unvested restricted shares and restricted stock units, stock options and warrants. The Company excluded 465,024 and 3.4 million of potential common shares representing antidilutive stock options from the earnings per share calculations for the years ended December 31, 2007 and 2006, respectively.

The following table shows the computation of basic and diluted EPS for the years ended December 31, 2007 and 2006 (in millions except per share data):


	2007		2006		2005
Net income (loss) from continuing operations	$	433	$	1,752	$	(1,400	)
Net income from discontinued operations		1,562		112		93

Net income (loss) as reported	$	1,995	$	1,864	$	(1,307	)

Basic and diluted:
Weighted average shares outstanding—basic		252		285
Shares related to assumed exercise of warrants		24		11
Shares related to assumed exercise of options		1		—
Shares related to assumed vesting of restricted shares and restricted stock units		—		1

Weighted average shares outstanding—diluted		277		297

Basic EPS
EPS from continuing operations	$	1.72	$	6.15
EPS from discontinued operations		6.20		0.39

Basic EPS	$	7.92	$	6.54

Diluted EPS
EPS from continuing operations	$	1.56	$	5.90
EPS from discontinued operations		5.64		0.38

Diluted EPS	$	7.20	$	6.28

F-50

15.

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 generating facilities located in Massachusetts and New York with total net generating capacity of 2,689 MW. The Company’s California segment consists of three generating facilities located in or near the City of San Francisco, which have total net generating capacity of 2,347 MW. Other Operations includes proprietary trading, fuel oil management, and gains and losses related to the Back-to-Back Agreement which was terminated pursuant to a settlement that became effective in the third quarter of 2007. See Note 19 for further discussion of the Back-to-Back Agreement. 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. 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)
2007:
Operating revenues	$	1,133		$	664		$	177		$	45		$	—		$	2,019
Cost of fuel, electricity and other products		528			427			42			(67	)		(18	)		912

Gross margin		605			237			135			112			18			1,107
Operating Expenses:
Operations and maintenance		360			179			74			94			—			707
Depreciation and amortization		81			25			13			10			—			129
Impairment losses		—			175			—			—			—			175
Gain on sales of assets, net		—			(49	)		(2	)		(5	)		11			(45	)

Total operating expenses		441			330			85			99			11			966

Operating income (loss)		164			(93	)		50			13			7			141

Total other income, net		(5	)		(7	)		(5	)		(282	)		—			(299	)
Income (loss) from continuing operations before reorganization items and income taxes		169			(86	)		55			295			7			440
Reorganization items, net		—			(2	)		—			—			—			(2	)
Provision for income taxes		—			—			—			9			—			9

Income (loss) from continuing operations	$	169		$	(84	)	$	55		$	286		$	7		$	433

Total assets	$	3,804		$	645		$	192		$	5,983		$	(1,172	)	$	9,452
Gross property additions	$	531		$	17		$	3		$	9		$	—		$	560

F-51

Operating Segments


	Mid- Atlantic			Northeast			California			Other Operations			Eliminations			Total
	(in millions)
2006:
Operating revenues	$	1,901		$	811		$	171		$	204		$	—		$	3,087
Cost of fuel, electricity and other products		583			464			56			86			(38	)		1,151

Gross margin		1,318			347			115			118			38			1,936
Operating Expenses:
Operations and maintenance		333			116			63			80			—			592
Depreciation and amortization		74			25			13			25			—			137
Impairment losses		—			118			—			1			—			119
Gain on sales of assets, net		(7	)		(46	)		—			(40	)		44			(49	)

Total operating expenses		400			213			76			66			44			799

Operating income		918			134			39			52			(6	)		1,137

Total other expense (income), net		(4	)		9			(34	)		128			—			99
Income (loss) from continuing operations before reorganization items and income taxes		922			125			73			(76	)		(6	)		1,038
Reorganization items, net		—			(164	)		—			—			—			(164	)
Provision (benefit) for income taxes		—			2			—			(552	)		—			(550	)

Income from continuing operations	$	922		$	287		$	73		$	476		$	(6	)	$	1,752

Total assets	$	3,404		$	1,185		$	443		$	3,326		$	(1,849	)	$	6,509
Gross property additions	$	112		$	12		$	1		$	8		$	—		$	133

F-52


	Mid- Atlantic		Northeast			California			Other Operations			Eliminations			Total
	(in millions)
2005:
Operating revenues	$	1,197	$	1,013		$	166		$	245		$	(1	)	$	2,620
Cost of fuel, electricity and other products		742		818			53			187			(16	)		1,784

Gross margin		455		195			113			58			15			836
Operating Expenses:
Operations and maintenance		341		210			69			64			(1	)		683
Depreciation and amortization		64		33			5			33			—			135
Impairment losses		—		—			—			9			—			9
Loss (gain) on sales of assets, net		—		(10	)		—			19			8			17

Total operating expenses		405		233			74			125			7			844

Operating income (loss)		50		(38	)		39			(67	)		8			(8	)

Total other expense (income), net		18		6			1			1,414			(26	)		1,413
Income (loss) from continuing operations before reorganization items and income taxes		32		(44	)		38			(1,481	)		34			(1,421	)
Reorganization items, net		22		7			(169	)		96			26			(18	)
Provision (benefit) for income taxes		—		6			9			(33	)		—			(18	)

Income (loss) from continuing operations	$	10	$	(57	)	$	198		$	(1,544	)	$	8		$	(1,385	)

Total assets	$	3,334	$	1,017		$	379		$	4,354		$	(1,763	)	$	7,321
Gross property additions	$	67	$	15		$	14		$	5		$	—		$	101


	Geographic Areas Property, Plant and Equipment and Other Intangible Assets
	Mid- Atlantic		Northeast		California		Other Operations		Eliminations			Total
	(in millions)
At December 31, 2007	$	2,999	$	381	$	153	$	62	$	(799	)	$	2,796
At December 31, 2006	$	2,450	$	563	$	163	$	38	$	(799	)	$	2,415

F-53

16.

Quarterly Financial Data (Unaudited)

Summarized quarterly financial data for 2007, 2006 and 2005, is as follows (in millions):


	Operating Revenue		Operating Income (Loss)			Income (Loss) from Continuing Operations			Income (Loss) Before Cumulative Effect of Changes in Accounting Principles			Consolidated Net Income (Loss)
2007:
March	$	352	$	(103	)	$	(133	)	$	(52	)	$	(52	)
June		542		(71	)		(83	)		1,256			1,256
September		717		318			642			775			775
December		408		(3	)		7			16			16
2006:
March	$	957	$	481		$	422		$	467		$	467
June		619		153			107			99			99
September		963		282			248			(26	)		(26	)
December		548		221			975			1,324			1,324
2005:
March	$	530	$	(8	)	$	(49	)	$	11		$	11
June		583		(14	)		7			(10	)		(10	)
September		401		(305	)		(1,556	)		(1,515	)		(1,515	)
December		1,106		319			213			222			207

17.

Valuation and Qualifying Accounts


	As of December 31, 2007, 2006 and 2005
			Additions
Description	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
Provision for uncollectible accounts (current)
2007	$	75	$	11	$	3		$	(77	)	$	12
2006		84		15		(24	)		—			75
2005		234		16		(167	)		1			84
Provision for uncollectible accounts (noncurrent)
2007	$	24	$	—	$	(3	)	$	(15	)	$	6
2006		72		14		24			(86	)		24
2005		161		—		7			(96	)		72

18.

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.

F-54

Environmental Matters

Kivalina Suit. On February 26, 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the United States District Court for the Northern District of California against several owners of generating facilities, including Mirant Corporation, several oil companies and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska that they contend is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The Plaintiffs assert claims for nuisance and contend that the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which cost is alleged to be $95 million to $400 million. Mirant intends to oppose this action vigorously, but cannot predict its outcome.

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 Company subsidiaries’ ownership and lease of those facilities. 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 subsidiaries of the Company. If a violation is determined to have occurred at any of the facilities, the Company subsidiary owning or leasing the facility may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. The Company’s subsidiaries owning or leasing the Chalk Point, Dickerson and Morgantown facilities in Maryland are installing a variety of emissions control equipment on those facilities 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 Company’s subsidiaries acquired or leased the facilities or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, the Company’s subsidiary owning or leasing the facility at issue 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, 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 the Company and its subsidiaries that own or lease these facilities.

Morgantown Particulate Emissions NOV. On March 3, 2006, Mirant Mid-Atlantic received a notice sent on behalf of the MDE alleging that violations of particulate matter emissions limits applicable to unit 1 at the Morgantown facility occurred on nineteen days in June and July 2005. The notice advises that the potential civil penalty is up to $25,000 per day for each day that unit 1 exceeded the applicable particulate matter limit. The letter further advises that the MDE has asked the Maryland Attorney General to file a civil suit under Maryland law based upon the alleged violations.

Morgantown SO2 Exceedances. Mirant Mid-Atlantic received an NOV dated March 8, 2006, asserting that on three days in June 2005 and January 2006, the Morgantown facility exceeded SO2 emissions limitations specified in its air permit. The NOV indicates that on two of those days the SO2 emissions limitation was exceeded by two different units of the Morgantown facility each day. The NOV did not seek a specific penalty amount but noted that the violations identified could subject Mirant Mid-Atlantic to a civil penalty of up to $25,000 per day.

Morgantown Emissions Observation NOV. On June 30, 2006, the MDE issued an NOV to Mirant Mid-Atlantic indicating that it had failed to comply with the air permit for the Morgantown facility by operating the combustion turbines at the facility for more than 168 hours without performing an EPA Reference Method 9 observation of stack emissions for an 18-minute period. The NOV did not seek a specific penalty amount but noted that the violation identified could subject Mirant Mid-Atlantic to a civil penalty of up to $25,000 per day.

Mirant Potomac River NAAQS Exceedance. On March 23, 2007, the Virginia DEQ issued an NOV to Mirant Potomac River alleging that it violated Virginia’s Air Pollution Control Law and regulations on February 23, 2007, by operating the Potomac River facility in a manner that resulted in a monitored exceedance

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in a twenty-four hour period of the NAAQS for SO2. As noted in the NOV, Mirant Potomac River was operating on February 23, 2007, as directed by PJM in accordance with a DOE order during a scheduled outage of the Pepco transmission lines serving Washington, D.C. The NOV asserts that plant operators did not implement appropriate actions to minimize SO2 emissions. The NOV did not seek a specific penalty amount but noted that the violations identified could subject Mirant Potomac River to civil penalties of varying amounts under different provisions of the Virginia Code, including a potential civil fine of up to $100,000.

New York State Administrative Claim. 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. The State of New York cited various existing outstanding matters between the State and the Company’s subsidiaries owning generating facilities in New York related to compliance with environmental laws and regulations. The State of New York and the NYSDEC executed a stipulated order with the Company, its New York subsidiaries and the other Mirant Debtors to stay resolution of this administrative claim. That stipulated order was approved by the Bankruptcy Court on February 23, 2006. Although this administrative claim remains stayed, the bulk of the existing outstanding matters upon which the claim was based have been separately resolved with the NYSDEC.

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.

Lovett/Bowline SPDES Notices of Violation. On March 8, 2007, Mirant Lovett and Mirant Bowline received NOVs from the NYSDEC alleging certain violations of their State Pollutant Discharge Elimination System (“SPDES”) permits. On April 6, 2007, the NYSDEC filed a complaint against Mirant Lovett and Mirant Bowline based on these allegations. The complaint seeks a penalty of $500,000. On December 31, 2007, Mirant Bowline entered into a Consent Order with the NYSDEC that resolved the NOV issued to it. In the Consent Order, Mirant Bowline agreed to pay a fine of $50,000 and to fund an environmental benefit project in the amount of $250,000. Mirant Lovett is in discussions with the NYSDEC to resolve the NOV issued to it and has not yet responded to the complaint filed by the NYSDEC.

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 not been complied with 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

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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. 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 Corporation, emerged from bankruptcy on various dates in 2007. As of December 31, 2007, 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, to the extent unresolved claims are resolved now that Mirant has emerged from bankruptcy, the claimants 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

In 2005, Mirant Corporation and various of its subsidiaries filed actions in the Bankruptcy Court against several parties seeking to recover damages for fraudulent transfers that occurred prior to the filing of Mirant’s bankruptcy proceedings, and asserting other related claims. 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. In addition to these avoidance actions, the official Committee of Unsecured Creditors of Mirant Corporation filed an action against Arthur Andersen on behalf of the Mirant Debtors alleging malpractice. Under the Plan, the rights to most of these avoidance actions, and the suit filed against Arthur Andersen, were transferred to MC Asset Recovery. MC Asset Recovery, while wholly-owned by Mirant, is governed by managers that are independent of Mirant and its other subsidiaries. Mirant is obligated to make capital contributions to MC Asset Recovery as necessary to pay up to $20 million of professional fees and to pay certain other costs incurred by MC Asset Recovery, including expert witness fees and other costs of the avoidance actions and the Andersen suit, which costs are not capped and for which Mirant has accrued $45 million.

Under the Plan, any cash recoveries received by MC Asset Recovery from the avoidance actions or the Andersen suit, net of costs incurred in prosecuting the actions (including all capital contributions from Mirant), 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 Corporation 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 December 31, 2007, none of those actions has resulted in any recovery.

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If MC Asset Recovery succeeds in obtaining any recoveries on the 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 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 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 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 has ruled 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. 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

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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.

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 of service 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 the 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 rerunning of the dispatch of 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.

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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.

The Company disputes the allegations made by the MD PSC in its complaint and intends to oppose the complaint and the relief requested. If the FERC were to remove the exemptions to the Offer Capping Rules, and apply the removal retroactively from January 15, 2008, or an earlier date, PJM would have to rerun its day-ahead market from that date forward to determine what prices would have resulted in the absence of the exemptions. Such a rerun of the PJM day-ahead market likely would result in refunds being owed by all sellers, including the Company, but the potential amount cannot be quantified.

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, due to 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.

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.

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.

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19.

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 is 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 the Pepco Settling Parties. The 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 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 Settlement Agreement became effective August 10, 2007. The 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 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 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 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 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 Settlement Agreement shortly after the appeal was filed. Pepco repaid the $70 million once the Settlement Agreement became fully effective.

Upon the distribution of the shares to Pepco, Mirant recognized a gain of $379 million. 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 are included in other income, net and the $36 million is included in gross margin in the consolidated statement of operations.

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New York Tax Proceedings

Mirant New York, Mirant Bowline, Mirant Lovett and Hudson Valley Gas (collectively with Mirant New York, Mirant Bowline and Mirant Lovett, the “New York Companies”) were the petitioners in various proceedings (the “Tax Certiorari Proceedings”) initially brought in the New York state courts challenging the assessed values determined by local taxing authorities for the Bowline and Lovett generating facilities and a natural gas pipeline (the “HVG Property”) owned by Hudson Valley Gas. Mirant Bowline had challenged the assessed value of the Bowline generating facility and the resulting local tax assessments for tax years 1995 through 2006. Mirant Bowline succeeded to rights held by Orange and Rockland for the tax years prior to its acquisition of the Bowline facility in 1999 under its agreement with Orange and Rockland for the purchase of that facility. Mirant Lovett had challenged the assessed value of the Lovett facility for each of the years 2000 through 2006. Hudson Valley Gas had challenged the assessed value of the HVG Property for each of the years 2004 through 2006. As of December 31, 2006, Mirant Bowline and Mirant Lovett had not paid property taxes on the Bowline and Lovett generating facilities that fell due in the period from September 30, 2003, through December 31, 2006, in order to preserve their respective rights to offset the overpayments of taxes made in earlier years against the sums payable on account of current taxes. Hudson Valley Gas had not paid property taxes that fell due in the period from September 30, 2004, through December 31, 2006.

On December 13, 2006, Mirant and the New York Companies entered into a settlement agreement (the “Tax Settlement Agreement”) with the Town of Haverstraw (“Haverstraw”), the Town of Stony Point (“Stony Point”), the Haverstraw-Stony Point Central School District (the “School District”), the County of Rockland (the “County”), the Village of Haverstraw (“Haverstraw Village”), and the Village of West Haverstraw (“West Haverstraw Village” and collectively with Haverstraw, Stony Point, the School District, the County, and Haverstraw Village, the “Tax Jurisdictions”). The Tax Settlement Agreement was approved by the Bankruptcy Court on December 14, 2006, and resolved all pending disputes regarding real property taxes between the New York Companies and the Tax Jurisdictions. Under the agreement, the New York Companies received total refunds of $163 million from the Tax Jurisdictions and paid unpaid but accrued taxes to the Tax Jurisdictions of $115 million, resulting in the New York Companies receiving a net cash payment in the amount of $48 million. The refunds and unpaid taxes were paid in February 2007. The $163 million of total refunds received by the New York Companies was recognized as a gain in the financial statements in the fourth quarter of 2006. In addition, the New York Companies had previously accrued a liability based upon the unpaid taxes as billed by the Tax Jurisdictions. Due to the reductions of the unpaid taxes that occurred pursuant to the terms of the Tax Settlement Agreement, the New York Companies also recognized in the fourth quarter of 2006 a reduction of operating expenses of approximately $23 million related to 2006 and a gain of approximately $71 million related to prior periods.

California Settlement

The California Settlement described in Note 18 in California and Western Power Markets—FERC Refund Proceedings Arising Out of California Energy Crisis included a provision that either (1) the partially constructed Contra Costa 8 project, which was a planned 530 MW combined cycle generating facility, and related equipment (collectively, the “CC8 Assets”) were to be transferred to PG&E or (2) PG&E would receive additional alternative consideration of $70 million (the “CC8 Alternative Consideration”). To fund the CC8 Alternative Consideration, PG&E received an allowed, unsecured claim in the bankruptcy proceedings against Mirant Delta that resulted in a distribution to PG&E of cash and Mirant common stock with an aggregate value of approximately $70 million. PG&E was required to liquidate the common stock received as part of that distribution and place the net resulting amount plus any cash received into an escrow account.

The California Settlement provided that if the transfer of the CC8 Assets to PG&E did not occur on or before June 30, 2008, then the CC8 Alternative Consideration was to be paid to PG&E and the Mirant Settling Parties would retain the CC8 Assets. If PG&E closed on its acquisition of the CC8 Assets, the funds in the

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escrow account were to be paid to Mirant Delta. The transfer of the CC8 Assets to PG&E was completed on November 28, 2006, and the $70 million escrow account was paid to Mirant Delta. The Company recognized in the fourth quarter of 2006 a gain of $27 million for the amount by which the escrow account exceeded the carrying amount of the CC8 Assets. The gain was included in other income in the Company’s consolidated statements of operations.

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Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.

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 resulting from 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 our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of December 31, 2007. Based upon this assessment, our management concluded that, as of December 31, 2007, these disclosure controls and procedures were effective.

Appearing as exhibits to this annual 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.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined by Rules 13a-15(f) under the Exchange Act). The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Internal control over financial reporting includes those processes and procedures that:

—

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

—

provide reasonable assurance that transactions are recorded properly to allow for the preparation of financial statements, in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company;

—

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the consolidated financial statements; and

—

provide reasonable assurance as to the detection of fraud.

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we carried out an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007. In conducting our assessment, management utilized the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2007.

Our independent registered public accounting firm, KPMG LLP, has issued reports on their assessment of internal control over financial reporting and our consolidated financial statements. KPMG LLP’s reports can be found on pages F-1 and F-2. Our audit committee appoints, retains, oversees, evaluates, compensates and terminates on its sole authority our independent auditors and approves all audit engagements, including the scope, fees and terms of each engagement. The audit committee’s oversight process is intended to ensure that we will continue to have high-quality, cost-efficient independent auditing services.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2007, there were no changes in Mirant’s internal control over financial reporting or in other factors that could materially affect or is reasonably likely to affect such internal controls over financial reporting.

Item 9B.

Other Information

None.

PART III

Item 10.

Directors and Executive Officers of the Registrant

The information required by this Item will be set forth in our definitive Proxy Statement for our 2008 Annual Meeting of Stockholders, to be filed on or before March 28, 2008, and is incorporated herein by reference.

Item 11.

Executive Compensation

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13.

Certain Relationships and Related Transactions

Item 14.

Principal Accountant Fees and Services

PART IV

Item 15.

Exhibits and Financial Statement Schedules

(a)

1. Financial Statements

Our consolidated financial statements, including the notes thereto and independent auditors’ report thereon, are set forth on pages F-1 through F-67 of the Annual Report on Form 10-K, and are incorporated herein by reference.

2. Financial Statement schedules

None

3. Exhibit Index


Exhibit No.		Exhibit Name
2.1*		Purchase and Sale Agreement, dated as of April 17, 2007, between Mirant International Investments, Inc. and Marubeni Caribbean Power Holdings, Inc. (Designated on Form 8-K dated April 18, 2007, as Exhibit 2.1)

2.2*		Purchase and Sale Agreement, dated as of January 15, 2007, by and between Mirant Americas, Inc. and LS Power (Designated on Form 8-K dated January 15, 2007 as Exhibit 2.1)

2.3*		Stock and Note Purchase Agreement, dated as of December 11, 2006, by and among Mirant Asia-Pacific Ventures, Inc., Mirant Asia-Pacific Holdings, Inc., Mirant Sweden International AB (publ), and Tokyo Crimson Energy Holdings Corporation (Designated on Form 8-K dated December 13, 2006 as Exhibit 2.1)

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 January 3, 2006 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*		Accelerated Share Repurchase Agreement, dated November 9, 2007, by and between Mirant Corporation and J.P. Morgan Securities, Inc., as agent for J.P. Morgan Chase Bank (designated on Form 8-K dated November 9, 2007, as Exhibit 10.1)

10.2*		Engineering, Procurement and Construction Agreement, dated as of July 30, 2007, between Mirant Mid-Atlantic, LLC, Mirant Chalk Point, LLC and Stone & Webster, Inc. (designated on Form 8-K filed August 3, 2007, as exhibit 10.1)

10.3*		Tax Settlement Agreement, dated as of December 13, 2006, by and between Mirant Corporation, Mirant New York, Inc., Mirant Bowline, LLC, Mirant Lovett, LLC, Hudson Valley Gas Corporation and the Town of Haverstraw, the Town of Stony Point, the Haverstraw-Stony Point Central School District, the County of Rockland, the Village of Haverstraw, and the Village of West Haverstraw as Exhibit 10.1 (Designated on Form 8-K filed December 15, 2006)

10.4*		Settlement Agreement and Release dated May 30, 2006 by and between Registrant and PEPCO (Designated on Form 8-K filed May 31, 2006 as Exhibit 10.1)

10.5*		Employment Agreement between Registrant and Robert M. Edgell (Designated on Form 8-K filed March 4, 2006 as Exhibit 10.1)


Exhibit No.		Exhibit Name
10.6*		Employment Agreement between Registrant and Thomas Legro (Designated on Form 8-K filed December 1, 2005 as Exhibit 10.1)

10.7*		Employment Agreement between Registrant and James V. Iaco (Designated on Form 8-K filed November 4, 2005 as Exhibit 10.1)

10.8*		Employment Agreement between Registrant and S. Linn Williams (Designated on Form 8-K filed November 4, 2005 as Exhibit 10.2)

10.9*		Employment Agreement between Registrant and Edward R. Muller (Designated on Form 8-K filed October 3, 2005 as Exhibit 10.1)

10.10*		Form of Stock Option Award Agreement (Designated on Form 8-K filed November 16, 2006 as Exhibit 10.1)

10.11*		Form of Restricted Stock Unit Award Agreement (Designated on Form 8-K filed November 16, 2006 as Exhibit 10.2)

10.12*		Description of Mirant Corporation Special Bonus Plan (Designated on Form 8-K filed October 11, 2006)

10.13*		Mirant Corporation 2006 Non-Employee Director Compensation Plan (Designated on Form 8-K filed May 8, 2006 as Exhibit 10.1)

10.14*		2006 Short-term Incentive Plan Description (Designated on Form 10-K filed March 14, 2006 as Exhibit 10.55)

10.15*		2006 Named Executive Officer Base Compensation and Short-term Incentive Targets (Designated on Form 10-K filed March 14, 2006 as Exhibit 10.56)

10.16*		Form of Stock Option Award Agreement (Designated on Form 8-K filed January 18, 2006 as Exhibit 10.1)

10.17*		Form of Restricted Stock Unit Award Agreement (Designated on Form 8-K filed January 18, 2006 as Exhibit 10.2)

10.18*		2005 Omnibus Incentive Compensation Plan (Designated on Form 8-K filed January 3, 2006 as Exhibit 10.1)

10.19*		Form of Amended and Restated Mirant Services Supplemental Executive Retirement Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.31)

10.20*		Form of First Amendment to the Amended and Restated Mirant Services Supplemental Executive Retirement Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.61)

10.21*		Form of Second Amendment to the Amended and Restated Mirant Services Supplemental Executive Retirement Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.62)

10.22*		Form of Third Amendment to the Amended and Restated Mirant Services Supplemental Executive Retirement Plan (Designated on Form 10-Q filed October 28, 2003 as Exhibit 10.86)

10.23*		Form of Fourth Amendment to the Amended and Restated Mirant Services Supplemental Executive Retirement Plan (Designated on Form 10-K filed March 15, 2005 as Exhibit 10.42)

10.24*		Form of Amended and Restated Mirant Corporation Deferred Compensation Plan for Directors and Select Employees (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.55)

10.25*		First Amendment to the Mirant Corporation Deferred Compensation Plan for Directors and Select Employees (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.56)


Exhibit No.		Exhibit Name
10.26*		Second Amendment to the Mirant Corporation Deferred Compensation Plan for Directors and Select Employees (Designated on Form 10-Q filed October 27, 2003 as Exhibit 10.87)

10.27*		Third Amendment to the Mirant Corporation Deferred Compensation Plan for Directors and Select Employees (Designated on Form 10-K filed March 15, 2005 as Exhibit 10.43)

10.28*		Fourth Amendment to the Mirant Corporation Deferred Compensation Plan for Directors and Select Employees (Designated on Form 10-K filed March 14, 2006 as Exhibit 10.22)

10.29*		2006 Mirant Corporation Deferred Compensation Plan (Designated on Form 10-K filed March 14, 2006 as Exhibit 10.23)

10.30*		Form of Mirant Services Supplemental Benefit Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.57)

10.31*		First Amendment to the Mirant Services Supplement Benefit Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.58)

10.32*		Second Amendment to the Mirant Services Supplemental Benefit Plan (Designated on Form 10-K filed April 30, 2003 as Exhibit 10.72)

10.33*		Third Amendment to the Mirant Services Supplemental Benefit Plan (Designated on Form 10-K filed March 15, 2005 as Exhibit 10.40)

10.34*		Fourth Amendment to the Mirant Services Supplemental Benefit Plan (Designated on Form 10-K filed March 14, 2006 as Exhibit 10.28)

10.35		Fifth Amendment to the Mirant Services Supplemental Benefit Plan

10.36*		Mirant Corporation—Four Year Credit Agreement with Credit Suisse First Boston, Bank of America, N.A., Commerzbank AG, New York and Grand Cayman Branches, The Royal Bank of Scotland PC, The Bank of Tokyo-Mitsubishi Ltd., New York Branch, Bayerische Landesbank Girozentrale, Deutsche Bank AG, New York Branch, Wachovia Bank, N.A., and the initial lenders listed on the signature pages thereof. (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.67)

10.37*		Mirant Corporation—Facility C Credit Agreement with Citibank, N.A., the issuing banks and lenders named therein. (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.69)

10.38*		Mirant North America, LLC—Credit Agreement with Deutsche Bank Securities Inc., Goldman Sachs Credit Partners L.P., and JPMorgan Chase Bank, N.A (Designated on Form 10-K filed March 14, 2006 as Exhibit 10.33)

10.39*		Mirant Americas Generation, LLC—Facility B Credit Agreement with Lehman Brothers, Inc. and Lehman Commercial Paper, Inc. (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.70)

10.40*		Mirant Americas Generation, LLC—Facility C Credit Agreement with Lehman Brothers, Inc. and Lehman Commercial Paper, Inc. (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.71)

10.41*		Payment Guaranty, dated as of December 11, 2006, by Mirant Corporation, to and in favor of Tokyo Crimson Energy Holdings Corporation (Designated on Form 8-K filed December 13, 2006 as Exhibit 10.1)

10.42*		Payment Guaranty, dated as of December 11, 2006, made by The Tokyo Electric Power Company, Incorporated in favor of Mirant Asia-Pacific Ventures, Inc. and Mirant Asia-Pacific Holdings, Inc. (Designated on Form 8-K filed December 13, 2006 as Exhibit 10.2)


Exhibit No.		Exhibit Name
10.43*		Payment Guaranty, dated as of December 11, 2006, by Marubeni Corporation in favor of Mirant Asia-Pacific Ventures Inc. and Mirant Asia-Pacific Holdings, Inc. (Designated on Form 8-K filed December 13, 2006 as Exhibit 10.3)

21.1		Subsidiaries of Registrant

23.1		Consent of KPMG dated February 28, 2008

24.1		Powers of Attorney

31.1		Certification of Chief Executive Officer

31.2		Certification of Chief Financial Officer

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 Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 28th day of February, 2008.


MIRANT CORPORATION

By:		/s/ EDWARD R. MULLER
		Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 28, 2008 by the following persons on behalf of the registrant and in the capacities indicated.


Signatures		Title
/s/ EDWARD R. MULLER Edward R. Muller		Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)

/s/ JAMES V. IACO James V. Iaco		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ THOMAS LEGRO Thomas Legro		Senior Vice President and Controller (Principal Accounting Officer)

* A. D. Correll		Director

* Thomas W. Cason		Director

* Terry G. Dallas		Director

* Thomas H. Johnson		Director

* John T. Miller		Director

* Robert C. Murray		Director

* John M. Quain		Director

* William L. Thacker		Director

* By attorney-in-fact.

/s/ THOMAS LEGRO Thomas Legro