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 Americas Generation, LLC

(Exact name of registrant as specified in its charter)


Delaware	N/A	51-0390520
(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:

None

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. x Yes ¨ 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. x

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


Large Accelerated Filer ¨		Accelerated Filer ¨

Non-accelerated Filer x (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

All of our outstanding membership interests are held by our parent, Mirant Americas, Inc., so we have no membership interests held by nonaffiliates.

We have not incorporated by reference any information into this Form 10-K from any annual report to securities holders, proxy statement or registration statement.

TABLE OF CONTENTS


		Page
	Glossary of Certain Defined Terms	i - iv

	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	32
Item 4.	Submission of Matters to a Vote of Security Holders	32

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	33
Item 6.	Selected Financial Data	33
Item 7.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	67
Item 8.	Financial Statements and Supplementary Data	F-1
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	71
Item 9A.	Controls and Procedures	71
Item 9B.	Other Information	72

	PART III
Item 10.	Directors and Executive Officers of the Registrant	73
Item 11.	Executive Compensation	75
Item 12.	Security Ownership of Certain Beneficial Owners and Management	75
Item 13.	Certain Relationships and Related Transactions	75
Item 14.	Principal Accountant Fees and Services	75

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	76

Glossary of Certain Defined Terms

APB—Accounting Principles Board.

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.

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.

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 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 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.

kW—Kilowatt.

LIBOR—London InterBank Offered Rate.

LTSA—Long-term service agreement.

MAAC—Mid-Atlantic Area Council.

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 Bowline—Mirant Bowline, LLC.

Mirant Chalk Point—Mirant Chalk Point, LLC.

Mirant Delta—Mirant Delta, LLC.

Mirant Energy Trading—Mirant Energy Trading, LLC.

Mirant Kendall—Mirant Kendall, LLC.

Mirant Las Vegas—Mirant Las Vegas, LLC.

Mirant Lovett—Mirant Lovett, LLC.

Mirant Mid-Atlantic—Mirant Mid-Atlantic, LLC.

Mirant New York—Mirant New York, Inc.

Mirant North America—Mirant North America, LLC.

Mirant NY-Gen—Mirant NY-Gen, LLC.

Mirant Peaker—Mirant Peaker, LLC.

Mirant Potomac River—Mirant Potomac River, LLC.

Mirant Potrero—Mirant Potrero, LLC.

Mirant Power Purchase—Mirant Power Purchase, LLC.

Mirant Services—Mirant Services, LLC.

Mirant Sugar Creek—Mirant Sugar Creek, LLC.

Mirant Wichita Falls—Mirant Wichita Falls, LLC.

Mirant Zeeland—Mirant Zeeland, 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.

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.

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

Pepco—Potomac Electric Power Company.

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 Mirant’s and 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.

iii

PUHCA—Public Utility Holding Company Act of 1935.

Reserve Margin—Excess capacity over peak demand.

RMR—Reliability-must-run.

RTO—Regional Transmission Organization.

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 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 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.

UWUA—Utility Workers Union of America.

VaR—Value-at-risk.

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 Americas Generation’s consolidated and combined 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 Americas Generation” refer to Mirant Americas Generation, LLC and its subsidiaries, unless the context requires otherwise.

PART I

Item 1.

Business

Overview

We are a competitive energy company that produces and sells electricity. 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 Americas Generation is a Delaware limited liability company and an indirect wholly-owned subsidiary of Mirant. 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.

In the third quarter of 2006, Mirant commenced auction processes to sell six U.S. natural gas-fired facilities including our indirectly owned Zeeland and Bosque facilities. On May 1, 2007, we completed the sale of the Zeeland and Bosque natural gas-fired facilities. In addition, on May 7, 2007, we completed the sale of Mirant NY-Gen, an indirect wholly-owned subsidiary. In accordance with Mirant North America’s debt covenants, approximately $524 million of the proceeds from the sale of the Zeeland and Bosque facilities are being reinvested in the business of Mirant North America. At December 31, 2007, $273 million of such proceeds have been reinvested in Mirant North America. See Note 10 to our consolidated and combined financial statements contained elsewhere in this report for additional information regarding the accounting for these 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 Mirant 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 Mirant in its entirety. On November 9, 2007, Mirant announced the conclusion of the strategic review process. Mirant plans to return a total of $4.6 billion of excess cash to its stockholders.

The accompanying consolidated financial statements include the accounts of Mirant Americas Generation and reflect the effects of the Plan as of December 31, 2005, including:

•

The contribution by Mirant of its interest in Mirant Potomac River and Mirant Peaker to our indirect wholly-owned subsidiary, Mirant Mid-Atlantic, and its interest in Mirant Zeeland and in Mirant Americas Energy Marketing, Mirant Americas Development, Inc., Mirant Americas Production Company, Mirant Americas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas Retail Energy Marketing, LP, and Mirant Americas Gas Marketing I-XV, LLCs (collectively, the “Trading Debtors”) to Mirant North America. All of the contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.”

•

The transfer of the trading and marketing business of the Trading Debtors to Mirant Energy Trading, a wholly-owned subsidiary of Mirant North America. After these transfers took place on January 31, 2006, the Trading Debtors were transferred to a trust created under the Plan that is not affiliated with us.

The accompanying 2005 combined financial statements present our results of operations and cash flows based on the assets, liabilities and operations of the predecessor Contributed Subsidiaries.

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 Mirant’s website at www.mirant.com as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Information contained on this 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, for periods prior to 2006, includes gains and losses related to a long-term PPA with Pepco (the “Back-to-Back Agreement”) and the transition power agreement with Pepco that expired in January 2005. See Note 15 to our consolidated and combined financial statements contained elsewhere in this report for further discussion of the Back-to-Back Agreement. Other Operations also includes interest on our and Mirant North America’s debt 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	60	%	$	164		140	%
Northeast		664		32	%		237	24	%		(93	)	(80	)%
California		177		9	%		135	13	%		50		43	%
Other Operations		2,657		130	%		7	1	%		(11	)	(9	)%
Eliminations		(2,590	)	(127	)%		18	2	%		7		6	%

Total	$	2,041		100	%	$	1,002	100	%	$	117		100	%

Eliminations are primarily related to intercompany sales of emissions allowances and interest on intercompany notes receivable and notes payable. For selected financial information about our business segments, see Note 13 to our consolidated and combined financial statements contained elsewhere in this report. See Item 2. Properties for a complete list of our operating 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 to 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 11 to our consolidated and combined 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 at 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 NAAQS (“non-attainment area”), from purchasing SO2 and NOx allowances to achieve compliance under the CAIR. In the fourth quarter of 2007, the Virginia State Air Pollution Control Board approved regulations that it interprets as prohibiting the trading of SO2 and NOx allowances by facilities in non-attainment areas to satisfy the requirements of the CAIR as implemented by Virginia. 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

Under our services agreement with Mirant Services, a direct subsidiary of Mirant, Mirant Services provides our personnel. At December 31, 2007, approximately 1,255 Mirant Services employees worked at our facilities. 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 and combined 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 $3.093 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) borrowings under Mirant North America’s 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.

The sale by our parent of the six U.S. natural gas-fired facilities and its Philippine and Caribbean businesses, and its decision to return a total of $4.6 billion in excess cash to its stockholders, could adversely limit its ability to make capital contributions to or otherwise support us and our subsidiaries.

We and our subsidiary, Mirant North America, are holding companies and we may not have access to sufficient cash to meet our obligations if our subsidiaries, in particular, Mirant Mid-Atlantic, are unable to make distributions.

We and our subsidiary, 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. 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 us. 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.

Our obligations and the obligations of Mirant North America, including our respective indebtedness, are effectively subordinated to the obligations or indebtedness of our 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 $108 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 9 to our consolidated and combined 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 14 to our consolidated and combined 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

We are an indirect wholly-owned subsidiary of Mirant. Our membership interests are not publicly traded and all of our membership interests are held by our parent, Mirant Americas. For the years ended December 31, 2007 and 2006, we made cash distributions to Mirant Americas of $534 million and $236 million, respectively. We have no equity compensation plans under which we issue our membership interests.

Item 6.

Selected Financial Data

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

During our bankruptcy proceedings, our consolidated and combined 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. 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.


	Years Ended December 31,
	2007			2006		2005			2004			2003
	(in millions)
Statements of Operations Data:
Operating revenues	$	2,041		$	3,257	$	2,941		$	3,449		$	3,958
Income (loss) from continuing operations		(68	)		1,197		(755	)		113			(3,182	)
Income (loss) from discontinued operations		8			3		(9	)		(7	)		(17	)
Net income (loss)	$	(60	)	$	1,200	$	(779	)	$	106		$	(3,209	)

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
	(in millions)
Balance Sheet Data:
Total assets	$	5,007	$	5,837	$	7,020	$	6,157		$	6,296
Total long-term debt		3,093		3,272		2,582		38			43
Liabilities subject to compromise		—		34		34		5,364			5,345
Equity (deficit)	$	1,169	$	1,644	$	703	$	(326	)	$	(439	)

Our debt 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 and combined financial statements and the notes accompanying those financial statements.

Overview

We are a competitive energy company that produces and sells electricity. We are an indirect wholly-owned subsidiary of Mirant. We own or lease 10,280 MW of electric generating capacity located in markets in the Mid-Atlantic and Northeast regions and in California. We also operate an integrated asset management and energy marketing organization based in Atlanta, Georgia.

Dispositions

Exploration of Strategic Alternatives and Share Repurchases

Hedging Activities

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 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 $553 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		8		1		4

Total	$	964	$	516	$	274

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.

Consolidated Financial Performance

We reported a net loss of $60 million for the year ended December 31, 2007, net income of $1.2 billion for the year ended December 31, 2006, and a net loss of $779 million 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	$	1,626		$	1,340		$	286		$	1,340		$	848		$	492
Unrealized gross margin		(624	)		609			(1,233	)		609			(23	)		632

Total gross margin		1,002			1,949			(947	)		1,949			825			1,124

Operating expenses:
Operations and maintenance
Affiliate		276			274			2			274			287			(13	)
Nonaffiliate		353			260			93			260			360			(100	)
Depreciation and amortization		120			122			(2	)		122			115			7
Impairment losses		175			119			56			119			—			119
Gain on sales of assets, net		(39	)		(9	)		(30	)		(9	)		(1	)		(8	)

Total operating expenses		885			766			119			766			761			5

Operating income		117			1,183			(1,066	)		1,183			64			1,119

Total other expense (income), net
Affiliate		1			(1	)		2			(1	)		23			(24	)
Nonaffiliate		186			220			(34	)		220			750			(530	)
Gain on sales of investments		—			(74	)		74			(74	)		(44	)		(30	)

Income (loss) from continuing operations before reorganization items, net and income taxes		(70	)		1,038			(1,108	)		1,038			(665	)		1,703
Reorganization items, net		(2	)		(164	)		162			(164	)		85			(249	)
Provision for income taxes		—			5			(5	)		5			5			—

Income (loss) from continuing operations		(68	)		1,197			(1,265	)		1,197			(755	)		1,952
Income (loss) from discontinued operations		8			3			5			3			(9	)		12

Income (loss) before cumulative effect of changes in accounting principles		(60	)		1,200			(1,260	)		1,200			(764	)		1,964

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

Net income (loss)	$	(60	)	$	1,200		$	(1,260	)	$	1,200		$	(779	)	$	1,979

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 sale of the Zeeland and Bosque facilities and Mirant NY-Gen. The sales have resulted in the reclassification of the revenues and expenses of these 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, for periods prior to 2006, includes gains and losses related to a long-term PPA with Pepco (the “Back-to-Back Agreement”) and the transition power agreement with Pepco that expired in January 2005. See Note 15 to our consolidated and combined financial statements contained elsewhere in this report for further discussion of the Back-to-Back Agreement. Other Operations also includes interest on our and Mirant North America’s debt and interest income 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		109		(102	)		7		70		61		131
Eliminations		18		—			18		38		—		38

Total	$	1,626	$	(624	)	$	1,002	$	1,340	$	609	$	1,949

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		—			—		415
Incremental realized value of hedges		202			65			—		—			—		267

Total realized gross margin		1,084			280			135		109			18		1,626
Unrealized gross margin		(479	)		(43	)		—		(102	)		—		(624	)

Total Gross Margin	$	605		$	237		$	135	$	7		$	18	$	1,002


	Year Ended December 31, 2006
	Mid- Atlantic		Northeast		California			Other Operations		Eliminations		Total
Energy	$	532	$	117	$	14		$	70	$	38	$	771
Contracted and capacity		39		44		101			—		—		184
Incremental realized value of hedges		263		125		(3	)		—		—		385

Total realized gross margin		834		286		112			70		38		1,340
Unrealized gross margin		484		61		3			61		—		609

Total Gross Margin	$	1,318	$	347	$	115		$	131	$	38	$	1,949

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 and ancillary services.

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 $1.002 billion as compared to $1.949 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 $1.233 billion in unrealized gross margin was comprised of the following:

•

unrealized losses of $624 million in 2007, which include $442 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 $182 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 $609 million in 2006, which include a $440 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power prices in 2006 and $169 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 $286 million in realized gross margin primarily attributable to: (1) an increase in contracted and capacity of $231 million principally related to the PJM RPM and the FCM in New England; (2) an increase in energy of $173 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 15 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; and

•

an increase of $3 million in gain on sales of assets, net which includes a $14 million gain on the sale of certain ancillary equipment that was included in the sale of the six U.S. natural gas-fired facilities in the second quarter of 2007. This amount was partially offset by a decrease of $11 million in sales of

emissions allowances. In 2007, gain on the sales of emissions allowances was $33 million and included a gain of $22 million on the sales of excess emissions allowances to third parties and $11 million related to the sales of emissions allowances to affiliates. In 2006, gain on the sales of emissions allowances to affiliates was $44 million. The affiliate gains are eliminated in the consolidated and combined statements of operations.

California

Our California segment consists of the Pittsburg, Contra Costa and Potrero facilities with total net generating capacity of 2,347 MW. The following tables summarize 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 15 to our consolidated and combined financial statements contained elsewhere in this report for further discussion.

Other Operations

Other Operations includes proprietary trading, fuel oil management, interest on our and Mirant North America’s debt 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	$	109		$	70		$	39
Unrealized gross margin		(102	)		61			(163	)

Total gross margin		7			131			(124	)

Operating expenses:
Operations and maintenance		16			22			(6	)
Depreciation and amortization		1			10			(9	)
Impairment losses		—			1			(1	)
Loss on sales of assets, net		1			—			1

Total operating expenses		18			33			(15	)

Operating income (loss)		(11	)		98			(109	)

Total other expense, net		204			174			30

Loss from continuing operations before reorganization items and income taxes	$	(215	)	$	(76	)	$	(139	)

Gross Margin


	Years Ended December 31,					Increase/ (Decrease)
	2007			2006		Increase/ (Decrease)
Energy	$	109		$	70	$	39

Total realized gross margin		109			70		39
Unrealized gross margin		(102	)		61		(163	)

Total gross margin	$	7		$	131	$	(124	)

The decrease of $163 million in unrealized gross margin was comprised of the following:

•

in 2007, 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; and

•

unrealized gains on proprietary trading and fuel oil management activities of $61 million in 2006.

The increase of $39 million in realized gross margin was principally a result of an increase 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.

Operating Expenses

Operating expenses decreased $15 million primarily as a result of the following:

•

a decrease of $9 million in depreciation expense as a result of fully depreciated computer equipment; and

•

a decrease of $6 million in operations and maintenance expense, primarily resulting from a reduction in allocated expenses as a result of the dispositions completed in 2007.

Other Expense (Income), Net

Other expense (income), net increased $30 million primarily as a result of the following:

•

a decrease of $45 million related to increased interest income resulting from increased cash balances as a result of the receipts of proceeds from dispositions completed in 2007 and lower interest expense on our debt; 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

Discontinued Operations

For the year ended December 31, 2007 and 2006, income from discontinued operations was $8 million and $3 million, respectively, and included the results of operations of Mirant Zeeland, Mirant Texas and Mirant NY-Gen. See Note 10 to our consolidated and combined 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,						Increase/ (Decrease)
	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 15 to our consolidated and combined 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		70		61		131		(39	)		85			46
Eliminations		38		—		38		16			—			16

Total	$	1,340	$	609	$	1,949	$	848		$	(23	)	$	825

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

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 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 (income), 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 15 to our consolidated and combined financial statements contained elsewhere in this report for further discussion.

Other Operations

Other Operations includes proprietary trading, fuel oil management and for periods prior to 2006, 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 15 to our consolidated and combined financial statements contained elsewhere in this report 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	$	70		$	(39	)	$	109
Unrealized gross margin		61			85			(24	)

Total gross margin		131			46			85

Operating expenses:
Operations and maintenance		22			27			(5	)
Depreciation and amortization		10			13			(3	)
Impairment losses		1			—			1
Loss on sales of assets, net		—			1			(1	)

Total operating expenses		33			41			(8	)

Operating income		98			5			93

Total other expense, net		174			730			(556	)

Loss from continuing operations before reorganization items and income taxes	$	(76	)	$	(725	)	$	649

Gross Margin

Gross margin increased by $85 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	$	70	$	39		$	31
Contracted and capacity		—		(78	)		78

Total realized gross margin		70		(39	)		109
Unrealized gross margin		61		85			(24	)

Total gross margin	$	131	$	46		$	85

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

•

an increase of $31 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 $78 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

•

a decrease of $24 million in unrealized gross margin, which includes an increase of $73 million in unrealized gains on our proprietary trading and fuel oil management activities, offset by a decrease of $97 million in unrealized gains on the Back-to-Back Agreement and the related hedges. In 2006, the Back-to-Back agreement was transferred to Mirant Power Purchase.

Operating Expenses

Operating expenses decreased by $8 million primarily due to a decrease in operations and maintenance of $5 million and a decrease in depreciation of $3 million.

Other Expense, net

The decrease in other expense, net of $556 million is primarily due to the following:

•

interest expense, net decreased by $527 million. In 2005, we recognized $746 million 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 $30 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,						Increase/ (Decrease)
	2006			2005			Increase/ (Decrease)
Gain on the implementation of the Plan	$	—		$	(30	)	$	30
Gain on the New York property tax settlement		(163	)		—			(163	)
Estimated claims and losses on rejected and amended contracts		—			54			(54	)
Professional fees and administrative expense		2			82			(80	)
Interest income, net		(3	)		(21	)		18

Total	$	(164	)	$	85		$	(249	)

Reorganization items, net decreased by $249 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.

Discontinued Operations

During the third quarter of 2006, Mirant commenced auction processes to sell six U.S. natural gas-fired facilities, including the Zeeland and Bosque facilities. Accordingly, the results of operations related to the planned sales were reclassified to income (loss) from discontinued operations in our consolidated and combined statements of operations for all periods presented.

For the year ended December 31, 2006, we reported net income from discontinued operations of $3 million, which includes an impairment loss to write-down the Zeeland and Bosque facilities to fair value. For the year ended December 31, 2005, we reported a net loss of $9 million. See Note 10 to our consolidated and combined 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; (3) $200 million of letter of credit capacity available under the Mirant North America senior secured term loan; and (4) redemptions of preferred shares in Mirant Americas.

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


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

Total cash and cash equivalents		698		750
Less: Cash restricted and reserved for other purposes		—		99

Total available cash and cash equivalents		698		651
Available under credit facilities		710		796

Total cash, cash equivalents and credit facilities availability	$	1,408	$	1,447

Cash and cash equivalents of discontinued operations	$	—	$	3

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.

We and our subsidiary, Mirant North America, are holding companies. Except for existing cash on hand and, in the case of Mirant North America, letters of credit and borrowings under its senior credit facilities, the liquidity of Mirant Americas Generation and Mirant North America is dependent on the distributions and dividends of their subsidiaries and their ability to refinance. The chart below is a summary representation of our capital structure and is not a complete 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.

Our subsidiary Mirant North America is an intermediate holding company that is the parent of our operating 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 its subsidiaries 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 us.

At December 31, 2007, Mirant North America had distributed to us all available cash that was permitted to be distributed under the terms of its debt agreements, leaving Mirant North America and its subsidiaries with $697 million. 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 us in March 2008.

Our ability to pay our obligations is dependent on the receipt of dividends from Mirant North America, capital contributions from Mirant, redemptions under the Mirant Americas preferred shares and our 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) capital expenditures required to keep our power generating facilities in operation; (2) debt service; (3) our asset management and proprietary trading activities; and (4) the Mirant Mid-Atlantic operating leases.

Capital Expenditures. Capital expenditures excluding capitalized interest for our continuing operations were $553 million, $127 million and $96 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 $964 million, $516 million and $274 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 contract obligations, 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 $3.093 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 our 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 us for the purpose of paying interest on our 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, we were required to use 25% of our free cash flow to pay down our 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. 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 $108 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 9 to our consolidated and combined 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		12		11
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	$	398	$	237

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
Mirant Mid-Atlantic operating leases	$	2,133	$	121	$	142	$	140	$	134	$	132	$	1,464
Other operating leases		35		5		4		4		3		2		17
Fuel commitments		506		314		192		—		—		—		—
Long-term service agreements		31		2		2		2		2		5		18
Other		125		125		—		—		—		—		—
Maryland Healthy Air Act		713		689		24		—		—		—		—
Long-term Debt		5,220		378		242		245		1,012		174		3,169

Total payments	$	8,763	$	1,634	$	606	$	391	$	1,151	$	313	$	4,668

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	$	753		$	424		$	329		$	424		$	636		$	(212	)
Net cash provided by (used in) operating activities:
Continuing operations		652			348			304			348			(211	)		559
Discontinued operations		(19	)		20			(39	)		20			19			1
Net cash provided by (used in) investing activities:
Continuing operations		(529	)		(36	)		(493	)		(36	)		(34	)		(2	)
Discontinued operations		503			(6	)		509			(6	)		(4	)		(2	)
Net cash provided by (used in) financing activities:
Continuing operations		(662	)		5			(667	)		5			18			(13	)
Discontinued operations		—			(2	)		2			(2	)		—			(2	)

Cash and cash equivalents, end of period	$	698		$	753		$	(55	)	$	753		$	424		$	329

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 $304 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 $286 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 $745 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 and $3 million related to other Mirant Americas Generation claims. In 2006, we paid $1.755 billion of bankruptcy claims, of which $765 million was reflected in cash from operations;

•

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 customer accounts receivable, net in the consolidated statements of cash flows;

•

an increase of $18 million related to increases in net interest income as a result of higher cash balances resulting from the dispositions completed in 2007;

•

a decrease of $517 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 $447 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 $111 million relating to net accounts receivable and accounts payable. The change in net accounts receivable and accounts payable for the year ended December 31, 2007, was a use of cash of $31 million. For the year ended December 31, 2006, the change in net accounts receivable and accounts payable was a source of cash of $80 million;

•

a decrease of $60 million primarily as 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 $59 million primarily related to changes in our fuel oil and emissions inventories. In 2007, fuel inventory increased $50 million and emissions inventory decreased $18 million.

•

a decrease of $24 million resulting from an increase in operations and maintenance expenses, excluding the non-cash gain on the New York property tax settlement in 2006. See “Results of Operations” for additional discussion.

•

a decrease of $22 million related to all other changes.

Investing Activities. Net cash used in investing activities from continuing operations increased by $493 million for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the following:

•

an increase of $426 million in capital expenditures and $22 million in capitalized interest primarily because of our environmental capital expenditures for our Mid-Atlantic generating facilities;

•

a decrease in proceeds from the sales of assets and investments of $48 million. In 2007, we received proceeds from the sale of assets of $49 million, which included approximately $22 million from the sale of ancillary equipment included in the sale of the Zeeland and Bosque natural gas-fired facilities and $24 million from the sales of emissions to third parties. In 2006, we received $97 million from the sale of assets, which included $12 million from the sale of a building, $20 million for the sale of our investment in the New York Mercantile Exchange and $58 million from the sale of a portion of our investment in InterContinental Exchange; and

•

an increase of $3 million in proceeds from property insurance in 2007.

Financing Activities. Net cash used in financing activities from continuing operations increased $667 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 $2.015 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 distribution of $534 million in 2007 to our member, as compared to $236 million for the same period in 2006;

•

a payment of $250 million in 2006 to Mirant Americas under the Plan;

•

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;

•

an increase of $39 million in capital contributions from Mirant Americas for the purchase of our bonds;

•

an increase of $16 million from the issuance (repayment) of affiliate debt. In 2007, we had issuance of $7 million and in 2006 we had repayments of $9 million; and

•

in 2007, we received $5 million from the redemption of preferred stock issued by Mirant Americas.

Discontinued Operations

Operating Activities. Net cash used in operating activities from discontinued operations increased by $39 million for the year ended December 31, 2007, compared to 2006. In 2006, operating activities included cash flows from the Zeeland and Bosque natural gas-fired facilities and Mirant NY-Gen for the entire year. In 2007, operating activities included all the discontinued facilities through their respective dates of sale.

Investing Activities. Net cash provided by investing activities from discontinued operations increased by $509 million for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the proceeds from the sale of the Zeeland and Bosque natural gas-fired facilities and Mirant NY-Gen in the second quarter of 2007.

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 $559 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 $492 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; and

•

an increase in bankruptcy related claims and expenses of $662 million. In 2006 we paid bankruptcy claims of $1.755 billion, of which $765 million was reflected in cash from operations. Our remaining claims payable and estimated claims accrual was $5 million at December 31, 2006. We paid $103 million in the year ended December 31, 2005 related to professional fees and other expenses associated with the bankruptcy proceedings.

Investing Activities. Net cash used in investing activities from continuing operations increased $2 million for the year ended December 31, 2006, compared to 2005. This difference was primarily due to the following:

•

an increase of $31 million in capital expenditures and $6 million in capitalized interest for 2006 compared to 2005, primarily due to our environmental capital expenditures in 2006 at Mid-Atlantic;

•

an increase in the proceeds from the sales of assets and investments of $45 million. In 2006, we received $97 million in proceeds from the sales of assets and investments, which included $12 million from the sale of the Mirant Service Center, $20 million from the sale of our investment in the New

York Mercantile Exchange and $58 million from the sale of a portion of our investment in InterContinental Exchange. In 2005, proceeds from the sales of assets and investments were $52 million and included $48 million from the sale of a portion of our investment in InterContinental Exchange and $4 million in additional proceeds from the 2004 sale of the Bowline gas turbines; and

•

a decrease in the repayment of notes receivable from affiliate of $10 million compared to the same period in 2005.

Financing Activities. Net cash provided by financing activities from continuing operations decreased $13 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 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 2006 we also incurred $51 million in debt issuance costs;

•

in 2005, proceeds from the issuance of debt-affiliate of $21 million represented advances under the intercompany cash management program;

•

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

•

the payment by Mirant North America of $250 million to Mirant Americas under the Plan and the distribution of $236 million to Mirant Americas as member.

Critical Accounting Estimates

The accounting policies described below are considered critical to obtaining an understanding of our consolidated and combined financial statements because their application requires significant estimates and judgments by management in preparing our consolidated and combined 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 and combined 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 and combined results of operations or financial condition.

We have discussed the selection and application of these accounting estimates with the Board of Managers and our independent auditors. It is management’s view that the current assumptions and other considerations used to estimate amounts reflected in our consolidated and combined 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 and combined 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 affiliate and nonaffiliate 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 affiliate and nonaffiliate 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 and combined

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 and combined 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 and combined financial statements contained elsewhere in this report for additional information on impairments.

Income Taxes

We are a limited liability company treated as a branch for income tax purposes. As a result, Mirant Americas and Mirant have direct liability for the majority of the federal and state income taxes relating to our operations. Through December 31, 2005, we allocated current and deferred income taxes to each regarded corporate member entity of our consolidated group as if each regarded corporate entity member was a single taxpayer utilizing the asset and liability method to account for income taxes except with respect to recognizing certain current period tax benefits. Specifically, we did not record current period tax benefits on each regarded corporate entity’s ability to carry back its separate company current year NOL as realization of such losses is dependent on reimbursements from Mirant, which were at Mirant’s discretion under the tax sharing agreement. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and NOL and tax credit carryforwards. When necessary, deferred tax assets are reduced by a valuation allowance to reflect the amount that is estimated to be recoverable. In assessing the recoverability of our deferred tax assets, we consider whether it is likely that some portion or all of the deferred tax assets will be realized. 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 enacted change.

Several significant changes to our tax posture occurred as a result of the Plan. Implementation of the Plan included the conversion of certain of our regarded corporate entities to limited liability companies coupled with the liquidation and/or merger of these regarded corporate entities into other disregarded corporate entities for income tax purposes. As a result, certain subsidiaries previously treated as regarded corporate entities for income tax purposes have either been liquidated or converted into disregarded entities for income tax purposes pursuant to the Plan. Additionally, certain partnerships owned by the regarded corporate entities were also liquidated, and now form part of these disregarded entities for income tax purposes. The result of the above Plan effects was to eliminate our recording of tax expense and benefit prospectively with respect to the liquidated regarded corporate entities. Furthermore, with respect to those liquidated regarded corporate entities, all previously existing deferred tax assets and liabilities were eliminated as of December 31, 2005. Certain of our other subsidiaries continue to exist as regarded corporate entities for income tax purposes, including Hudson Valley Gas, Mirant Kendall and Mirant Special Procurement, Inc. In May 2007, Mirant New York was converted to a limited liability company, resulting in the elimination of any existing deferred tax assets and liabilities related to Mirant New York.

When it emerged from bankruptcy, Mirant terminated the tax sharing agreement with its direct and indirect wholly-owned regarded corporate entities. As a result, Mirant’s direct and indirect wholly-owned regarded corporate entities are no longer responsible for reimbursing Mirant for their intercompany tax obligations

attributable to their operations. Accordingly, our income tax receivables and payables with Mirant or Mirant Americas were resolved pursuant to a global settlement under the Plan whereby intercompany receivables and payables received no distribution. The income tax payables and receivables related to Mirant New York, which remained in bankruptcy at December 31, 2006, were resolved upon its emergence from Bankruptcy, which became effective on April 16, 2007; however, for financial statement purposes, we recorded the effects of its plan of reorganization on March 31, 2007.

For those subsidiaries that continue to exist as corporate regarded entities, we allocate current and deferred income taxes to each corporate regarded entity as if such entity were a single taxpayer utilizing the asset and liability method to account for income taxes. To the extent we provide tax expense or benefit, any related tax payable or receivable to Mirant is reclassified to equity in the same period.

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.

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. An unrecognized tax benefit 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 any unrecognized tax benefit requires management to make significant assumptions about the expected outcomes of certain tax positions included in Mirant’s filed or yet to be filed tax returns. See Note 2 to our consolidated and combined financial statements contained elsewhere in this report for information about our January 1, 2007, adoption of FIN 48.

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 14 to our consolidated and combined 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—affiliate and nonaffiliate 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—affiliate and nonaffiliate 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			Total
Net fair value of portfolio at December 31, 2006	$	106		$	388		$	494
Gains (losses) recognized in the period, net		13			(195	)		(182	)
Contracts settled during the period, net		(115	)		(327	)		(442	)

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

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


	Net Price Risk Management											Net Fair Value At December 31, 2007
	Assets					Liabilities
	Current			Noncurrent		Current			Noncurrent
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 two 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 our senior secured term loan or our 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 Member

Mirant Americas Generation, LLC:

We have audited the accompanying consolidated balance sheets of Mirant Americas Generation, LLC (a wholly-owned indirect subsidiary of Mirant Corporation) and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, equity and comprehensive income (loss) and cash flows for each of the years in the two-year period ended December 31, 2007, and the related combined statements of operations, equity and comprehensive income (loss) and cash flows for the year ended December 31, 2005. These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated and combined financial statements 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Mirant Americas Generation, LLC 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 U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated and combined financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes, in 2007 and Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations: an interpretation of FASB Statement No. 143, in 2005.

/s/ KPMG LLP

Atlanta, Georgia

March 9, 2008

F-1

MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES

(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

DECEMBER 31, 2007 AND 2006, CONSOLIDATED STATEMENTS OF OPERATIONS

AND

DECEMBER 31, 2005, COMBINED STATEMENT OF OPERATIONS


	For the Years ended December 31,
	2007			2006			2005
	(in millions)
Operating revenues—affiliate	$	51		$	70		$	159
Operating revenues—nonaffiliate		1,990			3,187			2,782

Total operating revenues		2,041			3,257			2,941

Cost of fuel, electricity and other products—affiliate		51			133			187
Cost of fuel, electricity and other products—nonaffiliate		988			1,175			1,929

Total cost of fuel, electricity and other products		1,039			1,308			2,116

Gross Margin		1,002			1,949			825

Operations and maintenance—affiliate		276			274			287
Operations and maintenance—nonaffiliate		353			260			360
Depreciation and amortization		120			122			115
Impairment losses		175			119			—
Gain on sales of assets, net		(39	)		(9	)		(1	)

Total operating expenses		885			766			761

Operating Income		117			1,183			64

Other Expense (Income), net:
Interest expense—affiliate		1			—			23
Interest expense—nonaffiliate		245			289			759
Interest income—affiliate		—			(1	)		—
Interest income—nonaffiliate		(58	)		(39	)		(6	)
Gain on sales of investments, net		—			(74	)		(44	)
Other, net		(1	)		(30	)		(3	)

Total other expense, net		187			145			729

Income (Loss) From Continuing Operations Before Reorganization Items and Income Taxes		(70	)		1,038			(665	)
Reorganization items, net		(2	)		(164	)		85
Provision for income taxes		—			5			5

Income (Loss) From Continuing Operations		(68	)		1,197			(755	)
Income (Loss) From Discontinued Operations, net		8			3			(9	)

Income (Loss) Before Cumulative Effect of Changes in Accounting Principles		(60	)		1,200			(764	)
Cumulative Effect of Changes in Accounting Principles		—			—			(15	)

Net Income (Loss)	$	(60	)	$	1,200		$	(779	)

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

F-2

MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES

(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

CONSOLIDATED BALANCE SHEETS


	At December 31,
	2007			2006
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	698		$	750
Funds on deposit		302			233
Receivables:
Affiliate		2			12
Nonaffiliate, less allowance for uncollectibles of $2 for 2007 and 2006		250			371
Price risk management assets—affiliate		—			3
Price risk management assets—nonaffiliate		173			728
Inventories		357			287
Prepaid rent and other payments		131			131
Assets held for sale		—			532

Total current assets		1,913			3,047

Property, Plant and Equipment, net		2,569			2,179

Noncurrent Assets:
Intangible assets, net		204			212
Price risk management assets—affiliate		—			1
Price risk management assets—nonaffiliate		30			104
Prepaid rent		234			218
Debt issuance costs, net		49			59
Other		8			17

Total noncurrent assets		525			611

Total Assets	$	5,007		$	5,837

LIABILITIES AND EQUITY
Current Liabilities:
Notes payable—affiliate	$	6		$	13
Current portion of long-term debt		141			141
Accounts payable and accrued liabilities		282			324
Payable to affiliate		32			48
Price risk management liabilities—affiliate		—			13
Price risk management liabilities—nonaffiliate		196			286
Accrued property taxes		7			75
Other		1			41

Total current liabilities		665			941

Noncurrent Liabilities:
Long-term debt		2,952			3,131
Price risk management liabilities—affiliate		—			4
Price risk management liabilities—nonaffiliate		137			39
Asset retirement obligations		44			40
Other		40			4

Total noncurrent liabilities		3,173			3,218

Liabilities Subject to Compromise		—			34

Commitments and Contingencies
Equity:
Member’s interest		1,524			1,983
Preferred stock in affiliate		(355	)		(339	)

Total equity		1,169			1,644

Total Liabilities and Equity	$	5,007		$	5,837

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

F-3

MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES

(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

DECEMBER 31, 2007 AND 2006, CONSOLIDATED STATEMENTS OF EQUITY

AND COMPREHENSIVE INCOME (LOSS)

AND

DECEMBER 31, 2005, COMBINED STATEMENT OF EQUITY (DEFICIT)

AND COMPREHENSIVE INCOME (LOSS)

(in millions)


	Member’s Interest			Preferred Stock in Affiliate			Investment by Mirant			Accumulated Other Comprehensive Income (Loss)			Comprehensive Income (Loss)
Balance, at December 31, 2004	$	—		$	—		$	(326	)	$	—
Net loss		—			—			(779	)		—		$	(779	)
Contribution of net assets and liabilities from Mirant under the Plan		—			—			1,781			—			—
Other comprehensive income		—			—			—			27			27

Comprehensive loss													$	(752	)

Change in member pursuant to the Plan		995			(319	)		(676	)		—

Balance, at December 31, 2005		995			(319	)		—			27
Net income		1,200			—			—			—		$	1,200
Amortization of discount on preferred stock in affiliate		20			(20	)		—			—			—
Distribution to member		(236	)		—			—			—			—
Capital contributions		4			—			—			—			—
Other comprehensive loss		—			—			—			(27	)		(27	)

Comprehensive income													$	1,173

Balance, at December 31, 2006		1,983			(339	)		—			—
Net loss		(60	)		—			—			—		$	(60	)
Amortization of discount on preferred stock in affiliate		21			(21	)		—			—			—
Redemption of preferred stock in affiliate		—			5			—			—			—
Distribution to member		(534	)		—			—			—			—
Capital contribution pursuant to the Plan		2			—			—			—			—
Adoption of FIN 48		51			—			—			—			—
Effect of the Supplemental Plan		22			—			—			—			—
Capital contributions		39			—			—			—			—

Comprehensive loss													$	(60	)

Balance, at December 31, 2007	$	1,524		$	(355	)	$	—		$	—

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

F-4

MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES

(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

DECEMBER 31, 2007 AND 2006, CONSOLIDATED STATEMENTS OF CASH FLOWS

AND

DECEMBER 31, 2005, COMBINED STATEMENT OF CASH FLOWS

(in millions)


	Years Ended December 31,
	2007			2006			2005
Cash Flows from Operating Activities:
Net income (loss)	$	(60	)	$	1,200		$	(779	)
Income (loss) from discontinued operations		8			3			(9	)

Income (loss) from continuing operations		(68	)		1,197			(770	)

Adjustments to reconcile net income (loss) from continuing operations to net cash provided by (used in) operating activities:
Amortization of transition power agreements and other obligations		—			—			(9	)
Depreciation and amortization		130			132			120
Impairment losses		175			119			—
Gain on sales of assets and investments, net		(39	)		(83	)		(45	)
Non-cash post-petition interest expense		—			—			746
Cumulative effect of changes in accounting principles		—			—			15
Non-cash reorganization items		—			1			8
Effect of the Plan		—			—			(30	)
Price risk management activities, net		624			(609	)		23
Deferred income taxes		—			—			(11	)
Non-cash gain on property tax settlement		—			(71	)		—
Other, net		(1	)		(23	)		4
Changes in operating assets and liabilities:
Affiliate accounts receivable, net		—			9			(296	)
Customer accounts receivable, net		133			115			(107	)
Funds on deposit		(69	)		457			(371	)
Prepaid rent		(16	)		(9	)		(9	)
Inventories		(70	)		(11	)		(16	)
Other assets		4			3			(5	)
Accounts payable and accrued liabilities		(110	)		(170	)		109
Settlement of claims payable		(20	)		(765	)		—
Payable to affiliate		(16	)		(7	)		404
Property taxes accrued		(16	)		56			26
Other liabilities		11			7			3

Total adjustments		720			(849	)		559

Net cash provided by (used in) operating activities of continuing operations		652			348			(211	)
Net cash provided by (used in) operating activities of discontinued operations		(19	)		20			19

Net cash provided by (used in) operating activities		633			368			(192	)

Cash Flows from Investing Activities:
Capital expenditures, excluding capitalized interest		(553	)		(127	)		(96	)
Capitalized interest expense for projects under construction		(28	)		(6	)		—
Repayments of notes receivable from affiliate, net		—			—			10
Proceeds from the sales of assets and other investments		49			97			52
Property insurance proceeds		3			—			—

Net cash used in investing activities of continuing operations		(529	)		(36	)		(34	)
Net cash provided by (used in) investing activities of discontinued operations		503			(6	)		(4	)

Net cash used in investing activities		(26	)		(42	)		(38	)

Cash Flows from Financing Activities:
Issuance (repayment) of debt-affiliate, net		7			(9	)		21
Proceeds from issuance of long-term debt-nonaffiliate		—			2,015			—
Repayment of long-term debt-nonaffiliate		(179	)		(474	)		(3	)
Settlement of debt under the Plan		—			(990	)		—
Debt issuance costs		—			(51	)		—
Capital contributions		39			—			—
Redemption of preferred stock in affiliate		5			—			—
Payment to affiliate under the Plan		—			(250	)		—
Distribution to member		(534	)		(236	)		—

Net cash provided by (used in) financing activities of continuing operations		(662	)		5			18
Net cash used in financing activities of discontinued operations		—			(2	)		—

Net cash provided by (used in) financing activities		(662	)		3			18

Net Increase (Decrease) in Cash and Cash Equivalents		(55	)		329			(212	)
Cash and Cash Equivalents, beginning of period		750			424			636
Plus: Cash and Cash Equivalents in Assets Held for Sale, beginning of period		3			—			—
Less: Cash and Cash Equivalents in Assets Held for Sale, end of period		—			3			—

Cash and Cash Equivalents, end of period	$	698		$	750		$	424

Supplemental Cash Flow Disclosures:
Cash paid for interest, net of amounts capitalized	$	264		$	220		$	29
Cash paid for claims and professional fees from bankruptcy	$	22		$	1,773		$	103

Financing Activity:
Effect of the Supplemental Plan—non-cash	$	22		$	—		$	—
Capital contribution pursuant to the Plan—non-cash	$	2		$	4		$	—

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

F-5

MIRANT AMERICAS GENERATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

December 31, 2007, 2006 and 2005

1. Description of Business and Organization

Mirant Americas Generation is a competitive energy company that produces and sells electricity. 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. The Company also operates an integrated asset management and energy marketing organization based in Atlanta, Georgia.

In the third quarter of 2006, Mirant commenced auction processes to sell six U.S. natural gas-fired facilities including the Company’s indirectly owned Zeeland and Bosque facilities. On May 1, 2007, the Company completed the sale of the Zeeland and Bosque natural gas-fired facilities. In addition, on May 7, 2007, the Company completed the sale of Mirant NY-Gen, an indirect wholly-owned subsidiary. In accordance with Mirant North America’s debt covenants, approximately $524 million of the proceeds from the sale of the Zeeland and Bosque facilities are being reinvested in the business of Mirant North America. At December 31, 2007, $273 million of such proceeds have been reinvested in Mirant North America. See Note 10 for additional information regarding the accounting for these facilities as discontinued operations.

The accompanying consolidated financial statements include the accounts of Mirant Americas Generation and reflect the effects of the Plan as of December 31, 2005, including:

•

The contribution by Mirant of its interest in Mirant Potomac River and Mirant Peaker to the Company’s indirect wholly-owned subsidiary, Mirant Mid-Atlantic, and its interest in Mirant Zeeland and in Mirant Americas Energy Marketing, Mirant Americas Development, Inc., Mirant Americas Production Company, Mirant Americas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas Retail Energy Marketing, LP, and Mirant Americas Gas Marketing I-XV, LLCs (collectively, the “Trading Debtors”) to Mirant North America. All of the contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.”

•

The accompanying 2005 combined financial statements present the results of operations and cash flows based on the assets, liabilities and operations of the predecessor Contributed Subsidiaries.

F-6

2. Accounting and Reporting Policies

Basis of Presentation

The accompanying consolidated and combined financial statements of Mirant Americas Generation have been prepared in accordance with GAAP.

The accompanying consolidated and combined financial statements include the accounts of Mirant Americas Generation and its wholly-owned subsidiaries and the Contributed Subsidiaries as discussed in Note 1 and have been prepared from the records maintained by Mirant Americas Generation, its subsidiaries and the Contributed Subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

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.

In accordance with SFAS 144, the results of operations of the Company’s 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.

Use of Estimates

The preparation of consolidated and combined 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 and combined financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates. The Company’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 the Company’s long-lived assets;

•

determining the value of the Company’s asset retirement obligations;

•

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

•

estimating losses to be recorded for contingent liabilities.

Revenue Recognition

Mirant Americas Generation 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

F-7

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 Americas Generation’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 and combined statements of operations.

Derivative Financial Instruments

Derivative financial instruments are recorded in the accompanying consolidated balance sheets at fair value as either price risk management assets or liabilities-affiliate or nonaffiliate, 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 Americas Generation’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 purchase or normal sale 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-affiliate and nonaffiliate and changes in fair value of fuel derivative contracts are reflected in cost of fuel, electricity and other products-affiliate and nonaffiliate in the accompanying consolidated and combined 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-affiliate and nonaffiliate in the accompanying consolidated and combined statements of operations.

Concentration of Revenues

In 2007, 2006 and 2005, the Company 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 the Company’s total revenues and gross margin from continuing operations are as follows:


	Years Ended December 31,
	2007		2006		2005
Operating revenues	56	%	58	%	41	%
Gross margin	60	%	68	%	55	%

Concentration of Labor Subject to Collective Bargaining Agreements

Under Mirant Americas Generation’s services agreement with Mirant Services, a direct subsidiary of Mirant, Mirant Services provides the Company’s personnel. At December 31, 2007, approximately 1,255 Mirant Services employees worked at the Company’s facilities. At December 31, 2007, approximately 66% of the Company’s total 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

The Company 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.

F-8

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 $302 million and $7 million, respectively. At December 31, 2006, current and noncurrent funds on deposit were $233 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 and combined 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

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 and combined 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 and combined statements of operations.

As a result of the capital expenditures Mirant North America 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

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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 the Company take into account the effect of interim retirements.

Capitalization of Interest Cost

The Company 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 on debt to nonaffiliates (in millions):


	Years Ended December 31,
	2007			2006			2005
Total interest costs	$	270		$	298		$	759
Capitalized and included in property, plant and equipment, net		(25	)		(9	)		—

Interest expense—nonaffiliate	$	245		$	289		$	759

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 the Plan and, accordingly, recorded approximately $746 million of interest expense in 2005 on liabilities subject to compromise.

Operating Leases

Mirant Americas Generation leases various assets under non-cancelable leasing arrangements, including generating facilities, office space and other equipment. The rent 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—nonaffiliate in the consolidated and combined 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. The Company has an option to extend these leases. Any extensions

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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.

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 and combined statements of operations.

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

The Company 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

The Company is a limited liability company treated as a branch for income tax purposes. As a result, Mirant Americas and Mirant have direct liability for the majority of the federal and state income taxes relating to the Company’s operations. Through December 31, 2005, the Company has allocated current and deferred income taxes to each regarded corporate entity of its consolidated group as if each regarded corporate entity were a single taxpayer utilizing the asset and liability method to account for income taxes except with respect to recognizing certain current period tax benefits. Specifically, the Company did not record current period tax benefits on each regarded corporate entity’s ability to carry back its separate company current year NOL as realization of such losses is dependent on reimbursements from Mirant, which were at Mirant’s discretion under the tax sharing agreement. 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. When necessary, deferred tax assets are reduced by a valuation allowance to reflect the amount that is estimated to be recoverable. In assessing the recoverability of its

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deferred tax assets, the Company considers whether it is likely that some portion or all of the deferred tax assets will be realized. 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.

Several significant changes to the Company’s tax posture occurred as a result of the Plan. Implementation of the Plan included the conversion of certain of the Company’s regarded corporate entities to limited liability companies coupled with the liquidation and/or merger of these regarded corporate entities into other disregarded corporate entities for income tax purposes. As a result, certain subsidiaries previously treated as regarded corporate entities for income tax purposes have either been liquidated or converted into disregarded entities for income tax purposes pursuant to the Plan. Additionally, certain partnerships owned by the regarded corporate entities were also liquidated, and now form part of these disregarded entities for income tax purposes. The result of the above Plan effects was to eliminate the Company’s recording of tax expense and benefit prospectively with respect to the liquidated regarded corporate entities. Furthermore, with respect to those liquidated regarded corporate entities, all previously existing deferred tax assets and liabilities were eliminated as of December 31, 2005. Certain of the Company’s other subsidiaries continue to exist as regarded corporate entities for income tax purposes, including Hudson Valley Gas, Mirant Kendall and Mirant Special Procurement, Inc. In May 2007, Mirant New York was converted to a limited liability company, resulting in the elimination of any existing deferred tax assets and liabilities related to Mirant New York.

When it emerged from bankruptcy, Mirant terminated the tax sharing agreement with its direct and indirect wholly owned regarded corporate entities. As a result, Mirant’s direct and indirect wholly owned regarded corporate entities are no longer responsible for reimbursing Mirant for their intercompany tax obligations attributable to their operations. Accordingly, the Company’s income tax receivables and payables with Mirant or Mirant Americas were resolved pursuant to a global settlement under the Plan whereby intercompany receivables and payables received no distribution. The income tax payables and receivables related to Mirant New York, which remained in bankruptcy at December 31, 2006, were resolved upon its emergence from Bankruptcy, which became effective on April 16, 2007; however, for financial statement purposes, Mirant Americas Generation recorded the effects of the plan of reorganization on March 31, 2007.

For those subsidiaries that continue to exist as corporate regarded entities, the Company continues to allocate current and deferred income taxes to each corporate regarded entity as if such entity were a single taxpayer utilizing the asset and liability method to account for income taxes. To the extent the Company provides tax expense or benefit, any related tax payable or receivable to Mirant is reclassified to equity in the same period.

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.

Impairment of Long-Lived Assets

The Company 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

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carrying amount of the asset may not be recoverable. Such evaluations are performed in accordance with SFAS 144. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value. 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.

Fair Value of Financial Instruments

SFAS No. 107 requires the disclosure of the fair value of all financial instruments that are not otherwise recorded at fair value in the financial statements. At December 31, 2007 and 2006, financial instruments recorded at contractual amounts that approximate market or fair value include cash and cash equivalents, funds on deposit, receivables from affiliate and customer accounts receivable, accounts payable and accrued liabilities, payable to affiliate and notes payable-affiliate. The market values of such items are not materially sensitive to shifts in market interest rates because of the short term to maturity of these instruments. At December 31, 2007 and 2006, the fair value of the Company’s long-term accounts receivable of $1 million is not readily determinable due to uncertainty regarding the amount and timing of collection from the Company’s customers.

The fair value of the Company’s long-term debt is estimated using quoted market prices when available. At December 31, 2007 and 2006, the carrying value of the Company’s long-term debt approximated fair value.

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.

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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 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 member’s interests of $51 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 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. The Company 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 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.

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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.

3. Related Party Arrangements and Transactions

Management, Personnel and Services Agreement with Mirant Services

Mirant Services provides the Company with various management, personnel and other services. The Company reimburses Mirant Services for amounts equal to Mirant Services’ direct costs of providing such services. The total costs incurred under the Management, Personnel and Services Agreement with Mirant Services has been included in the accompanying consolidated and combined statements of operations as follows (in millions):


	Years Ended December 31,
	2007		2006		2005
Cost of fuel, electricity and other products—affiliate	$	8	$	9	$	10
Operations and maintenance expense—affiliate		152		148		162

Total	$	160	$	157	$	172

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Services and Risk Management Agreements with Affiliates

Historically, the Company provided energy marketing and fuel procurement services through Mirant Energy Trading to the following affiliates: Mirant Las Vegas, Mirant Sugar Creek, Shady Hills, West Georgia and Mirant Wichita Falls. Mirant Wichita Falls was sold by Mirant in the second quarter of 2006. On May 1, 2007, Mirant completed the sale of the other four affiliates. For the years ended December 31, 2007, 2006 and 2005, the total energy marketing costs were $47 million, $45 million and $54 million, respectively. For the years ended December 31, 2007, 2006 and 2005, the Company recorded a reduction to operations and maintenance of approximately $1 million, $6 million and $8 million, respectively, related to the allocation of costs to affiliates. Subsequent to the sale of these affiliates, the Company no longer recognizes a reduction to operations and maintenance associated with providing services to these affiliates.

Administration Arrangements with Mirant Services

Substantially all of Mirant’s corporate overhead costs are allocated to Mirant’s operating subsidiaries. For the years ended December 31, 2007, 2006 and 2005, the Company incurred approximately $125 million, $132 million and $133 million, respectively, in costs under these arrangements, which are included in operations and maintenance—affiliate in the accompanying consolidated and combined statements of operations.

The Company’s allocation of Mirant’s overhead costs has increased as a result of the recent disposition of Mirant’s Philippine and Caribbean businesses and six U.S. natural gas-fired facilities.

Restructuring Charges

For the years ended December 31, 2007 and 2006, the Company recorded restructuring charges of $1 million and for the year ended December 31, 2005, the Company recorded $3 million of severance costs and other charges, which are included in operations and maintenance—affiliate in the accompanying consolidated and combined statements of operations. The severance costs and other employee termination-related charges associated with the restructuring at the Company’s locations were paid by Mirant Services and billed to the Company and are included in the amounts disclosed above for management, personnel and services.

Notes Payable to Affiliate

During the pendency of the Chapter 11 proceedings, the Company and certain of its subsidiaries and Mirant and certain of its subsidiaries (excluding the Company and its subsidiaries) participated in separate intercompany cash management programs whereby cash balances at the respective participating subsidiaries were transferred to central concentration accounts to fund working capital and other needs of the respective participants. At December 31, 2007 and 2006, the Company had current notes payable to affiliate of $6 million and $13 million, respectively, arising out of the balances owed by Mirant Zeeland under Mirant’s pre-emergence cash management program and by Mirant NY-Gen under its pre-emergence debtor in possession facility with Mirant Americas. The Company incurred interest expense-affiliate of $1 million for the year ended December 31, 2007, and $23 million for the year ended December 31, 2005. Interest expense-affiliate for the year ended December 31, 2006, was less than $1 million.

Payable to Mirant Americas Pursuant to the Plan

Mirant North America, the Company’s wholly-owned subsidiary, was required to pay $250 million to Mirant Americas within five days of the effective date of the Plan in return for Mirant’s contribution of its interest in the following: Mirant Americas Energy Marketing, Mirant Americas Development, Inc., Mirant Americas Production Company, Mirant Americas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas Retail Energy Marketing, LP, and Mirant Americas Gas Marketing, I-XV, LLCs. This amount was paid in January 2006.

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Mirant Letters of Credit

Mirant posted pre-petition letters of credit and a guarantee on behalf of Mirant Mid-Atlantic to provide for the rent payment reserve required in connection with Mirant Mid-Atlantic’s lease obligations in the event that it was unable to pay its lease payment obligations. On January 3, 2006, as part of the settlement of disputes in respect of the Mirant Mid-Atlantic leveraged leases and the Company’s emergence from bankruptcy, Mirant North America posted a $75 million letter of credit for rent payment reserve obligations under the Mirant Mid-Atlantic leveraged leases. Upon the posting of the letter of credit, the trustee under the leveraged leases returned $56 million of cash collateral to Mirant Mid-Atlantic.

Mirant posted a post-petition letter of credit in the amount of $5 million on behalf of Mirant Texas, LP (“Mirant Texas”) as of December 31, 2004, related to a tolling agreement. This post-petition letter of credit was set to expire in January 2006. Upon emergence from bankruptcy, Mirant North America replaced this post-petition letter of credit with a letter of credit issued under its senior secured credit facilities. The letter of credit expired in February 2007.

Prior to 2005, Mirant entered into pre-petition letters of credit to support the Company’s asset management activities. In September 2005, several of these letters of credit were drawn in the amount of $39 million. In January 2006, the remaining pre-petition letter of credit of $7 million was drawn in full. In addition, Mirant entered into post-petition letters of credit to support its asset management activities. In Janua

MIRANT AMERICAS GENERATION LLC 10-K