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

Or

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

For the Transition Period from                     to                     

Mirant Mid-Atlantic, LLC

(Exact name of registrant as specified in its charter)

Delaware	N/A	58-2574140
(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   ¨   Non-accelerated Filer.     x (Do not check if a smaller reporting company) Accelerated Filer                  ¨   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 North America, LLC, 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 -iii
	PART I
Item 1.	Business	5
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	19
Item 2.	Properties	20
Item 3.	Legal Proceedings	21
Item 4.	Submission of Matters to a Vote of Security Holders	21
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
Item 6.	Selected Financial Data	22
Item 7.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	23
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 8.	Financial Statements and Supplementary Data	F-1
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	39
Item 9A.	Controls and Procedures	39
Item 9B.	Other Information	40
	PART III
Item 10.	Directors and Executive Officers of the Registrant	41
Item 11.	Executive Compensation	43
Item 12.	Security Ownership of Certain Beneficial Owners and Management	43
Item 13.	Certain Relationships and Related Transactions	43
Item 14.	Principal Accountant Fees and Services	43
	PART IV
Item 15.	Exhibits and Financial Statements	44

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.

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.

DOE—United States Department of Energy.

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).

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 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.

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

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ISO—Independent System Operator.

LIBOR—London InterBank Offered Rate.

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 Americas Generation—Mirant Americas Generation, LLC.

Mirant Chalk Point—Mirant Chalk Point, LLC.

Mirant Energy Trading—Mirant Energy Trading, LLC.

Mirant North America—Mirant North America, LLC.

Mirant Peaker—Mirant Peaker, LLC.

Mirant Potomac River—Mirant Potomac River, LLC.

Mirant Power Purchase—Mirant Power Purchase, LLC.

Mirant Services—Mirant Services, LLC.

MISO—Midwest Independent Transmission System Operator.

MW—Megawatt.

MWh—Megawatt hour.

NAAQS—National ambient air quality standards.

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.

NOV—Notice of violation.

NOx—Nitrogen oxides.

NSR—New source review.

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

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.

PJM—Pennsylvania-New Jersey-Maryland Interconnection, LLC.

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

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

Power Sale, Fuel Supply and Services Agreement—Power sale, fuel supply and service agreement with Mirant Americas Energy Marketing, effective January 3, 2006.

PPA—Power purchase agreement.

PUHCA—Public Utility Holding Company Act of 1935.

Reserve Margin—Excess capacity over peak demand.

RTO—Regional Transmission Organization.

SEC—U.S. Securities and Exchange Commission.

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 142—SFAS No. 142, Goodwill and Other Intangible Assets.

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.

SO2—Sulfur dioxide.

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

VaR—Value-at-risk.

Virginia DEQ—Virginia Department of Environmental Quality.

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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 affiliates’ 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 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 or affiliates 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 activities;

• our or our affiliates’ 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;

• our or our affiliates’ 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;

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• 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; 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 Mid-Atlantic’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 Mid-Atlantic” refer to Mirant Mid-Atlantic, LLC and its subsidiaries, unless the context requires otherwise.

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PART I

Item 1. Business

Overview

Mirant Mid-Atlantic.    Mirant Mid-Atlantic is a Delaware limited liability company and a direct wholly-owned subsidiary of Mirant North America and an indirect wholly-owned subsidiary of Mirant Americas Generation and Mirant.

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 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.

Mid-Atlantic Business.    We own or lease approximately 5,244 MW of electric generating capacity in the Washington, D.C. area, all of which we operate. We had a combined 2007 net capacity factor of 37%.

The following table presents the details of our 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. Historically, Mirant Potomac River and Mirant Peaker were our affiliates. Pursuant to the Plan, Mirant contributed its interest in Mirant Potomac River and Mirant Peaker to us in December 2005. The contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.”

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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). Other than transactions that we enter into directly with third-parties, we execute these transactions with an affiliate, Mirant Energy Trading, and, for periods prior to January 31, 2006, Mirant Americas Energy Marketing.

We sell capacity, energy and ancillary services from our generating facilities to Mirant Energy Trading. The price we receive from the sales of these products is equal to the price received by Mirant Energy Trading 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 times. 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 participate indirectly in standard offer service auctions in Maryland and Washington, D.C. Power sales, made either directly through these auctions or indirectly through subsequent market transactions that are a result of the auction process, serve as economic hedges for our facilities.

We use derivative financial instruments, such as commodity forwards, futures, options and swaps, to manage our exposure to fluctuations in electric energy and fuel commodity prices. In addition, we economically hedge a substantial portion of our coal-fired baseload generation through OTC transactions. While some of our hedges are executed through our affiliate, Mirant Energy Trading, a significant portion of our hedges are financial swap transactions which we have transacted directly with counterparties. Such transactions are senior unsecured obligations 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	100	%	58	%	41	%	22	%	23	%
Fuel	98	%	86	%	33	%	33	%	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.

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.

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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 be 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.

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.

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 market in which we operate needs to begin the process now of adding generating capacity to meet growing demand. PJM has implemented a capacity market 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.

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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. We and 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 the subsidiary that markets natural gas.

The FERC has authorized us and 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 us and our subsidiaries is sold pursuant to this authorization. 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. The FERC requires that we and our public utility subsidiaries and affiliates with market based rate authority adhere to certain market behavior rules. If we or any of our subsidiaries or affiliates violates the market behavior rules, the FERC may require a disgorgement of profits or revoke our or its market based rate authority. If the FERC were to revoke market based rate authority, we or 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.

We and 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 us and 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. We and our existing generating facilities are subject to a variety of state and local regulations in Virginia and Maryland, including regulations regarding the environment, health and safety, maintenance and expansion of the facilities.

We 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. We 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.

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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.

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 (in millions):

	2008		2009		2010
Maryland Healthy Air Act	$	689	$	286	$	125
Other environmental		55		28		22
Total environmental capital expenditures	$	744	$	314	$	147

The principal sources of liquidity for our capital expenditures are expected to be: (1) existing cash on hand and cash flows from operations; (2) redemptions of the preferred shares issued to us by Mirant Americas; and (3) subject to the election of Mirant North America, capital contributions or advances from Mirant North America or letters of credit under its senior credit facilities.

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. All of our facilities are located in or near the Washington D.C. area, which is classified by the EPA as not achieving certain NAAQS. As a result of the NAAQS classification of this area, our operations are subject to more stringent air pollution requirements than applicable to plants located elsewhere. 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

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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 our 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, we and our subsidiary, 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. We and 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

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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.

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.

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 signed the RGGI Memorandum of Understanding (“MOU”), which puts forth a model set of regulations to guide the states in structuring their individual programs. Maryland joined the RGGI in 2007, and as a result our generating facilities in Maryland will be affected by the implementation of 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 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 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 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.

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.

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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.

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.

Employees

Under our services agreement with Mirant Services, a direct subsidiary of Mirant, Mirant Services provides our personnel. At December 31, 2007, approximately 750 Mirant Services employees worked at our facilities.

At our facilities located in Virginia and Maryland, Mirant Services has a collective bargaining agreement with the International Brotherhood of Electrical Workers Local 1900 that covers approximately 503 employees. This agreement was reached in October 2004 and extends until June 2010.

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Item 1A. Risk Factors

The following are factors that could affect our future performance:

Our revenues are unpredictable because 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 our generating facilities to Mirant Energy Trading, under the Power Sale, Fuel Supply and Services Agreement. The price we receive from the sales of these products is equal to the price received by Mirant Energy Trading from selling into competitive power markets. 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. The price for which we can sell our output may fluctuate on a day-to-day basis. The market in which we compete remains 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:

• 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;

• actions by regulators, PJM 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;

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

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

• 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;

• 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;

• 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;

• 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;

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

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

• 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;

• weather conditions that depress demand; 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.

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Our asset management 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. Derivatives from our asset management 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 value 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 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:

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

• interruptions in fuel supply;

• disruptions in the delivery of electricity;

• adverse zoning;

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

• restrictions on emissions;

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

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

• shortages of equipment or spare parts;

• labor disputes;

• operator errors;

• curtailment of operations due to transmission constraints;

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

• implementation of unproven technologies in connection with environmental improvements; and

• 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 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.

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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. Maryland, where we own generating facilities, has 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.

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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. 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 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, we may not have sufficient cash flow to permit us to make distributions or, if more severe, to meet our 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:

• failure or delays in obtaining necessary permits and approvals;

• adverse weather conditions;

• unanticipated cost increases;

• engineering problems;

• shortages of equipment, materials or skilled labor;

• unscheduled delays in delivery of materials and equipment; and

• 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. The exact amount and timing of such expenditures, if any, 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 obligations under our leveraged leases 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, the present value of lease payments under our leveraged leases is approximately $1 billion (assuming a 10% discount rate) and the termination value of the leveraged leases is $1.4 billion. Our obligations under the leveraged leases, including the covenants thereunder, could have important consequences, including the following: (1) they may limit our ability to obtain additional debt or equity financing for working

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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 rent obligations and will not be available for other purposes, including our operations, capital expenditures and future business opportunities; (3) they may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared with our competitors that are not burdened by such obligations and restrictions; and (4) 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 indirect parent, Mirant 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.

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. 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, our facilities are subject to rules and terms of participation imposed and administered by PJM. Although these facilities are themselves ultimately regulated by the FERC, PJM 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, PJM 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.

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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 obligations, 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.

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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.

	Location	Primary Fuel	Total MW(1)	2007 Net Capacity Factor(2)
Owned facilities:
Morgantown CT, Units 1-6	Maryland	Oil	248	4	%
Dickerson CT, Units 1-3	Maryland	Oil/Gas	307	5	%
Chalk Point, Units 1-4	Maryland	Coal/Oil/Gas	1,907	31	%
Chalk Point CT, Units 1-6.	Maryland	Gas/Oil	432	2	%
Potomac River, Units 1-5	Virginia	Coal/Oil	482	34	%
Leased facilities:
Morgantown, Units 1-2	Maryland	Coal/Oil	1,244	65	%
Dickerson, Units 1-3	Maryland	Coal	546	62	%
Chalk Point, CT Unit 7	Maryland	Gas/Oil	78	3	%
Total			5,244	37	%

(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 our Chalk Point and Morgantown generating facilities.

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Item 3.    Legal Proceedings—See Note 10 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.

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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 North America. For the years ended December 31, 2007 and 2006, we made cash distributions of $334 million and $693 million, respectively, to Mirant North America. 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.

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 claims that were subject to compromise subsequent to the Petition Date. In 2003, we recorded a goodwill impairment charge of $499 million. 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.

The following table presents our selected financial information, which is derived from our consolidated and combined financial statements (in millions):

	Years Ended December 31,
	2007		2006		2005		2004		2003
Statements of Operations Data:
Operating revenues	$	1,133	$	1,901	$	1,197	$	1,022	$	856
Net income (loss)		169		922		7		106		(441	)
Balance Sheet Data:
Total assets		3,804		3,404		3,341		3,155		3,020
Long-term debt		30		34		36		39		43
Total equity	$	3,407	$	3,292	$	3,062	$	2,956	$	2,850

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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 four generating facilities with a total net generating capacity of 5,244 MW.

Exploration of Strategic Alternatives and Share Repurchases

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.

Hedging Activities

We use derivative financial instruments, such as commodity forwards, futures, options and swaps, to manage our exposure to fluctuations in electric energy and fuel commodity prices. In addition, we economically hedge a substantial portion of our coal-fired baseload generation through OTC transactions. While some of our hedges are executed through our affiliate Mirant Energy Trading, a significant portion of our hedges are financial swap transactions which we have transacted directly with counterparties. Such transactions are senior unsecured obligations 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 26, 2008, we were economically hedged as follows:

	Aggregate Hedge Levels Based on Expected Generation
	2008		2009		2010		2011		2012
Power	100	%	58	%	41	%	22	%	23	%
Fuel	98	%	86	%	33	%	33	%	5	%
SO2/NOx	100	%	100	%	100	%	100	%	100	%

Capital Expenditures and Capital Resources

For the year ended December 31, 2007, we paid $531 million of capital expenditures, primarily related to the Maryland Healthy Air Act. The following table details our estimated capital expenditures for 2008 through 2010 (in millions):

	2008		2009		2010
Maryland Healthy Air Act	$	689	$	286	$	125
Other environmental		55		28		22
Maintenance		91		127		73
Construction		71		51		18
Other		5		1		2
Total	$	911	$	493	$	240

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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. The principal sources of liquidity for our capital expenditures are expected to be: (1) existing cash on hand and cash flows from operations; (2) redemptions of the preferred shares issued to us by Mirant Americas; and (3) subject to the election of Mirant North America, capital contributions or advances from Mirant North America or letters of credit under its senior credit facilities.

Results of Operations

Operating Statistics

Our net capacity factor was 37% for the year ended December 2007, compared to 36% and 39% for the years ended December 2006 and 2005, respectively. Our power generation volumes for the year ended December 2007 (in gigawatt hours) were 16,832, compared to 16,608 and 18,201 for the years ended December 2006 and 2005, respectively.

Our gross margin and expenses from affiliates and nonaffiliates aggregated by classification are as follows (in millions):

	Years Ended December 31,
	2007			2006			Increase/ (Decrease)			2006			2005			Increase/ (Decrease)
Realized Gross Margin	$	1,084		$	834		$	250		$	834		$	552		$	282
Unrealized Gross Margin		(479	)		484			(963	)		484			(97	)		581
Total Gross Margin		605			1,318			(713	)		1,318			455			863
Operating Expenses:
Operations and maintenance
Affiliate		144			135			9			135			148			(13	)
Nonaffiliate		216			198			18			198			193			5
Depreciation and amortization.		81			74			7			74			64			10
Gain on sale of assets, net		—			(7	)		7			(7	)		—			(7	)
Total operating expenses		441			400			41			400			405			(5	)
Operating income		164			918			(754	)		918			50			868
Other expense (income), net
Affiliate		—			(2	)		2			(2	)		10			(12	)
Nonaffiliate		(5	)		(2	)		(3	)		(2	)		8			(10	)
Reorganization items, net		—			—			—			—			22			(22	)
Cumulative effect of change in accounting principles		—			—			—			—			(3	)		3
Net income	$	169		$	922		$	(753	)	$	922		$	7		$	915

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Gross Margin

Gross margin decreased by $713 million for the year ended December 31, 2007, compared to the same period for 2006 and is detailed as follows (in millions):

	Years Ended December 31,
	2007			2006		Increase/ (Decrease)			2006		2005			Increase/ (Decrease)
Energy	$	686		$	532	$	154		$	532	$	770		$	(238	)
Contracted and capacity		196			39		157			39		64			(25	)
Incremental realized value of hedges		202			263		(61	)		263		(282	)		545
Total realized gross margin		1,084			834		250			834		552			282
Unrealized gross margin		(479	)		484		(963	)		484		(97	)		581
Total gross margin	$	605		$	1,318	$	(713	)	$	1,318	$	455		$	863

Energy represents gross margin from the generation of electricity, sales and purchases of emissions allowances, fuel sales and, purchases and handling of fuel.

Contracted and capacity represents gross margin received from capacity sold in ISO administered capacity markets and revenue from 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.

2007 versus 2006

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.

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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.

2006 versus 2005

The significant increase in our gross margin 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.

Operating Expenses

Operating expenses decreased by $5 million primarily due to the following:

• an $8 million decrease in operations and maintenance offset by a $10 million increase in depreciation; 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.

Other Expense (Income), net

The decrease of $22 million in other expense (income), net was primarily due to additional interest expense in 2005 related to liabilities subject to compromise.

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Liquidity and Capital Resources

Overview

Our liquidity and capital requirements are primarily a function of our capital expenditures, rent expense for operating leases, contractual obligations, legal settlements and working capital needs. Net cash flow provided by operating activities totaled $750 million, $468 million and $170 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Sources of Funds

The principal sources of liquidity for our future operations and capital expenditures are expected to be: (1) existing cash on hand and cash flows from the operations of the Company and its subsidiaries; (2) redemptions of the preferred shares issued to us by Mirant Americas; and (3) subject to the election of Mirant North America, capital contributions or advances from Mirant North America or letters of credit under its senior credit facilities.

At December 31, 2007, we had $242 million of cash, which amount was available under the leveraged lease documents for distribution to Mirant North America.

The availability of capital contributions, advances or letters of credit under Mirant North America’s senior credit facilities is subject to the discretion of Mirant North America and such accommodations may not be available as a source of liquidity to Mirant Mid-Atlantic.

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.

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).

Under the leveraged leases, we are subject to a covenant that restricts our right to make distributions. Our ability to satisfy the criteria set by that covenant in the future could be impaired by factors which negatively affect the performance of our power generation facilities, including interruptions in operation or curtailment of operations to comply with environmental restrictions.

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 capital expenditures required to keep our power generating facilities in operation and rent expense under our operating leases.

Capital Expenditures.    Capital expenditures were $531 million, $112 million and $67 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 $911 million, $493 million and $240 million, respectively. This forecast does not assume any construction of new generating units during the forecast period. Instead, the current capital expenditure program focuses on efficiency, safety, reliability and compliance with existing environmental laws

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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.

Operating Leases.    We lease the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively, and have 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 our 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, we are 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.

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
Generating units operating leases	$	2,133	$	121	$	142	$	140	$	134	$	132	$	1,464
Other operating leases		29		4		4		4		2		1		14
Coal purchases-affiliate		506		314		192		—		—		—		—
Other purchase commitments		94		94		—		—		—		—		—
Maryland Healthy Air Act		713		689		24		—		—		—		—
Long-term Debt		42		6		5		5		5		5		16
Total payments	$	3,517	$	1,228	$	367	$	149	$	141	$	138	$	1,494

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.

Coal purchases-affiliate primarily relate to long-term coal agreements. As of December 31, 2007, our total estimated coal purchases-affiliate 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.

Other purchase commitments 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 consists of a capital lease by Mirant Chalk Point and is reflected in the current portion of long-term debt and long-term debt on our consolidated balance sheets. Long-term debt also includes estimated interest on the capital lease.

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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	$	75		$	276		$	(201	)	$	276		$	299		$	(23	)
Net cash provided by operating activities		750			468			282			468			170			298
Net cash provided by (used in) investing activities		(526	)		26			(552	)		26			(191	)		217
Net cash used in financing activities		(57	)		(695	)		638			(695	)		(2	)		(693	)
Cash and cash equivalents, end of period	$	242		$	75		$	167		$	75		$	276		$	(201	)

2007 versus 2006

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 increased $282 million for the year ended December 31, 2007, compared to the same period in 2006, primarily as a result the following:

• an increase in realized gross margin of $250 million for the year ended December 31, 2007, compared to the same period in 2006. See “Results of Operations” for additional discussion of our improved performance in 2007 compared to the same period in 2006;

• a decrease of $27 million resulting from an increase in operations and maintenance expenses. See Results of Operations for further discussion;

• a decrease of $54 million as a result of changes in posted funds on deposit, principally related to 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 in 2006;

• an increase of $31 million primarily related to changes in our materials and supplies and fuel stock and emissions allowances inventories. In 2007, fuel inventory increased $13 million and emissions inventory decreased $26 million. In 2006, fuel inventory decreased $4 million and emissions inventory increased $21 million;

• an increase of $69 million relating to net accounts receivable and accounts payable. The change in net accounts receivable and accounts payables for the year ended December 31, 2007, was a source of cash of $9 million compared to a use of cash of $60 million for the year ended December 31, 2006; and

• an increase of $13 million related to all other changes in operating assets and liabilities.

Investing Activities.    Net cash used in investing activities increased by $552 million for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the following:

• an increase of $419 million in capital expenditures for 2007 as compared to 2006, primarily due to our environmental capital expenditures in 2007;

• a decrease in cash provided by investing activities of $124 million as a result of the repayment of notes receivable from affiliate in 2006;

• a decrease of $12 million in proceeds from property sales of assets, primarily as a result of the receipt of $12 million in 2006 from the sale of a building; and

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

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Financing Activities.    Net cash provided by financing activities increased by $638 million for the year ended December 31, 2007, compared to the same period in 2006. The increase is primarily a result of the following:

• in 2007, the Company distributed $334 million to its member compared to $693 million for the same period in 2006;

• in 2007, we received capital contributions of $274 million; and

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

2006 versus 2005

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 increased $298 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 $282 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 cash paid for interest of $12 million for the year ended December 31, 2006, compared to the same period in 2005; and

• a decrease of $5 million in operating expenses for the year ended December 31, 2006, compared to the same period in 2005.

Investing Activities.    Net cash provided by investing activities increased by $217 million for the year ended December 31, 2006, compared to the same period in 2005. This difference was primarily due to the following:

• an increase of $45 million in capital expenditures for 2006 as compared to 2005, primarily due to our environmental capital expenditures in 2006;

• receipt of $124 million in 2006 on a note receivable from affiliate versus net issuing notes receivable to affiliate of $124 million in 2005; and

• receipt of $12 million in proceeds from the 2006 sale of a building and $2 million from the sale of emissions allowances to affiliate.

Financing Activities.    Net cash used in financing activities increased by $693 million for the year ended December 31, 2006, compared the same period in 2005. The decrease is due to distribution to member of $693 million in 2006.

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.

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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 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 generation revenue from the sale of energy, capacity and ancillary services. We recognize affiliate and nonaffiliate revenue when earned and collection of such revenue is probable as a result of electricity delivered to an affiliate or customer pursuant to contractual commitments that specify volume, price and delivery requirements. Some affiliate sales of energy are based on economic dispatch, or they may be ‘as-ordered’ by PJM, 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. We also recognize affiliate revenue when ancillary services have been performed and collection of such revenue is probable.

The fair value model has historically been used for derivative energy contracts that economically hedge our electricity generation assets. 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 derivative contracts is reduced to reflect the estimated risk of default of counterparties on their contractual obligations to us.

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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 No. 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 for further information on price risk management assets and liabilities.

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

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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 $14 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.

33

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.

Goodwill

Nature of Estimates Required.    We evaluate our goodwill for impairment at least annually and periodically if indicators of impairment are present in accordance with SFAS 142. The results of our impairment testing may be affected by a significant adverse change in the extent or manner in which a reporting unit’s assets are being used, a significant adverse change in legal factors or in the business climate that could affect the value of a reporting unit, as well as other economic or operational analyses. If the carrying amount of the reporting unit is not recoverable, an impairment charge is recorded. The amount of the impairment charge, if impairment exists, is calculated as the difference between the fair value of the reporting unit goodwill and its carrying value. For this test, our business constitutes a single reporting unit. We perform our annual assessment of goodwill at October 31 and whenever contrary evidence exists as to the recoverability of goodwill.

Key Assumptions and Approach Used.    The accounting estimates related to determining the fair value of goodwill require management to make assumptions about cost of capital, future revenues, operating costs and forward commodity prices over the life of the assets as well as evaluating observable market data. Our assumptions about future revenues, costs and forward prices require significant judgment because such factors have fluctuated in the past and will continue to do so in the future.

We performed our annual test for goodwill impairment effective October 31, 2007. The test was based upon our most recent business plan and market data from independent sources. We utilized multiple valuation approaches in arriving at a fair value of our reporting unit for purposes of the test, including an income approach involving discounted cash flows and a market approach involving recent comparable transactions and trading multiples of peer companies. The annual evaluation of goodwill indicated that there was no impairment in 2007.

The critical assumptions used in our income valuation approach included assumptions as to the future electricity and fuel prices, future capacity prices, future levels of gross domestic product growth, levels of supply and demand, future operating expenditures and capital expenditure requirements, and estimates of our weighted average cost of capital. The assumptions included capital expenditures through the first quarter of 2010 required to install pollution control equipment in order to comply with Maryland Healthy Air Act as well as additional operating costs associated with the ongoing operation of the pollution control equipment. The assumptions also included costs associated with complying with potential carbon emissions legislation. In addition, the assumptions exclude general corporate overhead allocations, but include overhead allocations from Mirant Energy Trading. We assigned an equal weighting to the income and the market approach to determine the fair value of the reporting unit.

Effect if Different Assumptions Used.    The above assumptions were critical to our determination of the fair value of the business unit. The combined subjectivity and sensitivity of our assumptions and estimates used in our goodwill impairment analysis could result in a reasonable person reaching a different conclusion regarding those critical assumptions and estimates, possibly resulting in an impairment charge having been required for all or a portion of our goodwill.

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

34

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 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 10 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.

35

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risks associated with commodity prices 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 to Mirant Energy Trading under the Power Sale, Fuel Supply and Services Agreement and to third parties at market 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 of our 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.

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.

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 24 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):

Net fair value of portfolio at December 31, 2006	$	326
Losses recognized in the period, net		(209	)
Contracts settled during the period, net		(270	)
Net fair value of portfolio at December 31, 2007	$	(153	)

36

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):

	Current Assets		Current Liabilities			Noncurrent Liabilities			Net Fair Value at December 31, 2007
Total	$	9	$	(31	)	$	(131	)	$	(153	)

We have additional coal contracts with a net fair value of approximately $133 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.

Of the $153 million net fair value liability at December 31, 2007, a net price risk management liability of $23 million relates to 2008, a net price risk management liability of $79 million relates to 2009, a net price risk management liability of $50 million relates to 2010 and a net price risk management liability of $1 million relates to periods thereafter.

Value at Risk

Our Risk Management Policy prohibits the trading of certain products (e.g., natural gas liquids and pulp and paper) and contains restrictions related to our asset management 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. 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 7. “Critical Accounting Estimates” for the accounting treatment of asset management activities.

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

	For the Years Ended December 31,
	2007		2006
Asset Management VaR
Year end	$	18	$	24
Average	$	20	$	29
High	$	22	$	31
Low	$	18	$	24

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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.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty failed to perform under its contractual obligations. 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.

We are also exposed to credit risk from Mirant Energy Trading to the extent that Mirant Energy Trading is unable to collect amounts owed from third parties for the resale of our energy products.

38

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Member

Mirant Mid-Atlantic, LLC:

We have audited the accompanying consolidated balance sheets of Mirant Mid-Atlantic, 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 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 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 Mid-Atlantic, 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 MID-ATLANTIC, 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	$	1,369		$	1,711		$	1,197
Operating revenues—nonaffiliate		(236	)		190			—
Total operating revenues		1,133			1,901			1,197
Cost of fuel, electricity and other products—affiliate		353			465			610
Cost of fuel, electricity and other products—nonaffiliate		175			118			132
Total cost of fuel, electricity and other products		528			583			742
Gross Margin		605			1,318			455
Operating Expenses:
Operations and maintenance—affiliate		144			135			148
Operations and maintenance—nonaffiliate		216			198			193
Depreciation and amortization		81			74			64
Loss (gain) on sales of assets, net		—			(7	)		—
Total operating expenses		441			400			405
Operating Income		164			918			50
Other Expense (Income), net:
Interest expense—affiliate		—			—			10
Interest expense—nonaffiliate		3			4			8
Interest income—affiliate		—			(2	)		—
Interest income—nonaffiliate		(8	)		(5	)		—
Other, net		—			(1	)		—
Total other expense (income), net		(5	)		(4	)		18
Income Before Reorganization Items		169			922			32
Reorganization items, net		—			—			22
Income Before Cumulative Effect of Changes in Accounting Principles		169			922			10
Cumulative Effect of Changes in Accounting Principles		—			—			(3	)
Net Income	$	169		$	922		$	7

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

F-2

MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES

(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007			2006
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	242		$	75
Receivables:
Affiliate		83			86
Nonaffiliate		9			2
Price risk management assets—affiliate		—			132
Price risk management assets—nonaffiliate		9			135
Fuel stock and emissions allowances		82			95
Materials and supplies		38			35
Prepaid rent		96			96
Funds on deposit		2			2
Other current assets		10			18
Total current assets		571			676
Property, Plant, and Equipment, net		2,050			1,495
Noncurrent Assets:
Goodwill, net		799			799
Price risk management assets—affiliate		—			5
Price risk management assets—nonaffiliate		—			54
Other intangible assets, net		150			156
Prepaid rent		234			218
Other noncurrent assets		—			1
Total noncurrent assets		1,183			1,233
Total Assets	$	3,804		$	3,404
LIABILITIES AND EQUITY
Current Liabilities:
Current portion of long-term debt	$	3		$	3
Accounts payable and accrued liabilities		137			54
Payable to affiliate		18			11
Price risk management liabilities—affiliate		19			—
Price risk management liabilities—nonaffiliate		12			—
Accrued taxes		8			—
Total current liabilities		197			68
Noncurrent Liabilities:
Long-term debt		27			31
Asset retirement obligations		14			12
Price risk management liabilities—affiliate		8			—
Price risk management liabilities—nonaffiliate		123			—
Other long-term liabilities		28			1
Total noncurrent liabilities		200			44
Commitments and Contingencies
Equity:
Member’s interest		3,636			3,513
Preferred stock in affiliate		(229	)		(221	)
Total equity		3,407			3,292
Total Liabilities and Equity	$	3,804		$	3,404

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

F-3

MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES

(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

DECEMBER 31, 2007 AND 2006, CONSOLIDATED STATEMENTS OF EQUITY

AND

DECEMBER 31, 2005, COMBINED STATEMENT OF EQUITY

	Member’s Interest			Preferred Stock in Affiliate			Investment by Mirant
	(in millions)
Balance, December 31, 2004	$	—		$	—		$	2,956
Net income		—			—			7
Contribution of net assets and liabilities from Mirant under the Plan of Reorganization		—			—			99
Change in member pursuant to the Plan of Reorganization		3,270			(208	)		(3,062	)
Balance, December 31, 2005		3,270			(208	)		—
Net income		922			—			—
Amortization of discount on preferred stock in affiliate		13			(13	)		—
Capital contribution pursuant to the Plan of Reorganization		1			—			—
Distribution to member		(693	)		—			—
Balance, December 31, 2006		3,513			(221	)		—
Net income		169			—			—
Amortization of discount on preferred stock in affiliate		13			(13	)		—
Redemption of preferred stock in affiliate		—			5
Capital contributions		274			—			—
Adoption of FIN 48		1			—
Distribution to member		(334	)		—			—
Balance, December 31, 2007	$	3,636		$	(229	)	$	—

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

F-4

MIRANT MID-ATLANTIC, 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

	For the Years Ended December 31,
	2007			2006			2005
	(in millions)
Cash Flows from Operating Activities:
Net income	$	169		$	922		$	7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		81			74			64
Price risk management activities, net		479			(484	)		97
Gain on sale of assets		—			(7	)		—
Cumulative effect of changes in accounting principles		—			—			3
Non-cash charges for reorganization items		—			—			7
Effects of the Plan		—			—			(3	)
Post-petition interest		—			—			2
Other adjustments to net income		—			(1	)		—
Changes in certain assets and liabilities:
Affiliate accounts receivable		3			(35	)		(30	)
Nonaffiliate accounts receivable		(9	)		(1	)		—
Prepaid rent		(16	)		(10	)		(9	)
Materials and supplies, fuel stock and emissions allowances		10			(21	)		37
Other assets		8			55			(51	)
Accounts payable and accrued liabilities		8			(14	)		7
Payables to affiliate		7			(10	)		67
Taxes accrued—nonaffiliate		8			—			(28	)
Other noncurrent liabilities		2			—			—
Total adjustments		581			(454	)		163
Net cash provided by operating activities		750			468			170
Cash Flows from Investing Activities:
Capital expenditures		(531	)		(112	)		(67	)
Issuance of notes receivable from affiliate		—			—			(327	)
Repayment of notes receivable from affiliates		—			124			203
Proceeds from sale of assets		2			14			—
Property insurance proceeds		3			—			—
Net cash provided by (used in) investing activities		(526	)		26			(191	)
Cash Flows from Financing Activities:
Repayment of long-term debt		(3	)		(2	)		(2	)
Capital contributions		274			—			—
Redemption of preferred stock in affiliate		5			—			—
Distribution to member		(334	)		(693	)		—
Other financing activities		1			—			—
Net cash used in financing activities		(57	)		(695	)		(2	)
Net Increase (Decrease) in Cash and Cash Equivalents		167			(201	)		(23	)
Cash and Cash Equivalents, beginning of year		75			276			299
Cash and Cash Equivalents, end of year	$	242		$	75		$	276
Supplemental Cash Flow Disclosures:
Cash paid for interest	$	3		$	4		$	16
Financing Activity:
Capital contribution—non-cash	$	—		$	1		$	—

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

F-5

MIRANT MID-ATLANTIC AND SUBSIDIARIES

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

December 31, 2007, 2006 and 2005

1.    Description of Business and Organization

Mirant Mid-Atlantic is a Delaware limited liability company and a direct wholly-owned subsidiary of Mirant North America and an indirect wholly-owned subsidiary of Mirant Americas Generation and Mirant. The Company owns or leases approximately 5,244 MW of electric generating capacity in the Washington, D.C. area, all of which the Company operates. These generating facilities serve the PJM markets. The PJM ISO operates the largest centrally dispatched control area in the United States.

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

Pursuant to the Plan, Mirant contributed its interest in Mirant Potomac River and Mirant Peaker to Mirant Mid-Atlantic and the Company became a direct wholly-owned subsidiary of Mirant North America. The contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.”

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.

2.    Accounting and Reporting Policies

Basis of Presentation

The accompanying consolidated and combined financial statements of Mirant Mid-Atlantic have been prepared in accordance with GAAP.

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

In conjunction with Mirant’s tax planning associated with the utilization of its NOLs, the Company reevaluated certain items included in its historical pro forma tax basis balance sheets used in the calculation of the Company’s pro forma deferred tax assets and liabilities. As a result of this reevaluation, the Company’s 2006 pro forma net deferred tax liabilities were decreased by $27 million. The pro forma income tax disclosures in Note 7 reflects the immaterial correction of this misstatement.

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

F-6

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 the useful lives of our long-lived assets;

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

• estimating future cash flows in determining impairments of long-lived assets, goodwill and indefinite-lived intangible assets; and

• estimating losses to be recorded for contingent liabilities.

Revenue Recognition

Mirant Mid-Atlantic recognizes revenue from the sale of energy when earned and collection is probable. The Company recognizes affiliate and nonaffiliate revenue when electric power is delivered to an affiliate or to a customer pursuant to contractual commitments that specify volume, price and delivery requirements. Some affiliate sales of energy are based on economic dispatch, or ‘as-ordered’ by PJM, based on member participation agreements, but without an underlying contractual commitment. ISO revenues and revenues from sales of energy based on economic dispatch are recorded on the basis of MWh delivered, at the relevant day-ahead or real-time prices. The Company also recognizes affiliate revenue when ancillary services have been performed and collection of such revenue is probable. 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 price risk management assets or liabilities-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 Mid-Atlantic’s derivative financial instruments are all for asset management purposes. 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.

Concentration of Revenues

In 2007, 2006 and 2005, Mirant Mid-Atlantic earned a significant portion of its operating revenue and gross margin from the PJM energy market, where the Company’s generating facilities are located.

Concentration of Labor Subject to Collective Bargaining Agreements

Under Mirant Mid-Atlantic’s services agreement with Mirant Services, a direct subsidiary of Mirant, Mirant Services provides the Company’s personnel. At December 31, 2007, approximately 750 Mirant Services

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employees worked at our facilities. At December 31, 2007, approximately 67% of the Company’s total employees are subject to collective bargaining agreements.

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.

Restricted Cash

Restricted cash is included in current assets as funds on deposit in the accompanying consolidated balance sheets. At December 31, 2007 and 2006, funds on deposit were $2 million. Restricted cash includes cash collateral posted with third parties to support certain of the Company’s capital expenditure programs.

Fuel Stock, Purchased Emissions Allowances and Materials and Supplies

Fuel stock and materials and supplies are recorded 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.

The balances of the Company’s fuel stock and emissions allowances and materials and supplies at December 31, 2007 and 2006, are as follows (in millions):

	2007		2006
Fuel stock	$	72	$	59
Emissions Allowances		10		36
Materials and supplies		38		35
Total	$	120	$	130

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.

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As a result of the capital expenditures the Company is making to comply with the requirements of the Maryland Healthy Air Act, the Company anticipates that it will have significant excess emissions allowances in future periods. The Company plans to continue to maintain some emissions allowances in excess of expected generation in case its actual generation exceeds its current forecasts for future periods and for possible future additions of generating capacity. During the fourth quarter of 2007, Mirant began a program to sell excess emissions allowances dependent upon market conditions. 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.

Operating Leases

Mirant Mid-Atlantic 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 the Company’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 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 aggregated approximately $2.1 billion. Payments made under the terms of the lease agreement in excess of the amount of lease expense recognized are recorded as prepaid rent in the accompanying consolidated balance sheets. Prepaid rent attributable to periods beyond one year is included in noncurrent assets.

Goodwill and Intangible Assets

Goodwill represents the excess of costs over the fair value of assets of businesses acquired. Goodwill acquired in a purchase business combination is not amortized, but instead tested for impairment at least annually. 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. A goodwill impairment occurs when the fair value of a reporting unit is less than its carrying value including goodwill. The amount of the impairment charge, if an impairment exists, is calculated as the difference between the implied fair value of the reporting unit goodwill and its carrying value. The Company performs an annual assessment of goodwill at October 31 and whenever contrary evidence exists as to the recoverability of goodwill. The fair value of the reporting unit is calculated using income and market approaches and underlying assumptions based on the best information available.

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

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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.

Income Taxes

The Company was formed as a limited liability company on July 12, 2000, and was treated as a partnership for income tax purposes. The Company’s members were solely liable for the federal and state taxes resulting from the Company’s operations. In October 2002, the Company was converted to a branch for income tax purposes. As a result, Mirant Americas had sole direct liability for the majority of the federal and state income taxes resulting from the Company’s operations. Those state taxes for which the Company is liable have been included in the accompanying consolidated and combined statements of operations. 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 intercompany tax obligations attributable to their operations and Mirant Americas no longer has sole liability for the Company’s intercompany tax obligations. Mirant Americas still has the sole direct liability for the state income taxes resulting from the Company’s operations.

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 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.

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 $3 million, net of tax, related to the adoption of this accounting standard.

Fair Value of Financial Instruments

SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” 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, customer accounts receivable, accounts payable and accrued liabilities and payable to 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 or their intercompany nature. 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.

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Recently Adopted Accounting Standards

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

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

On June 28, 2006, the FASB ratified the EITF’s consensus reached on EITF 06-3, which relates to the income statement presentation of taxes collected from customers and remitted to government authorities. The Task Force affirmed as a consensus on this issue that the presentation of taxes on either a gross basis or a net basis within the scope of EITF 06-3 is an accounting policy decision that should be disclosed pursuant to APB 22. A company should disclose the amount of those taxes that is recognized on a gross basis in interim and annual financial statements for each period for which an income statement is presented if those amounts are 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 $1 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

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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.

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 $3 million as a cumulative-effect adjustment to member’s interest 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

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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 have 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	$	6	$	6	$	7
Operations and maintenance expense—affiliate		70		69		76
Total	$	76	$	75	$	83

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 $50 million, $47 million and $48 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, six U.S. natural gas-fired facilities and the shutdown of Lovett units 3 and 4.

Power Sales Agreement with Mirant Energy Trading

The Company operates under a Power Sale, Fuel Supply and Services Agreement with Mirant Energy Trading. Amounts due to Mirant Energy Trading for fuel purchases and due from Mirant Energy Trading for power and capacity sales are recorded as a net payable to affiliate or accounts receivable—affiliate in the accompanying consolidated balance sheets because of the Company’s legal right to offset such amounts.

Under the Power Sale, Fuel Supply and Services Agreement, Mirant Energy Trading resells the Company’s energy products in the PJM spot and forward markets, and to other third parties. The Company is paid the amount received by Mirant Energy Trading for such capacity and energy. The Company is exposed to credit risk from Mirant Energy Trading to the extent that Mirant Energy Trading is unable to collect amounts owed from third parties for the resale of the Company’s energy products.

Services Agreements with Mirant Energy Trading

The Company receives services from Mirant Energy Trading which include the bidding and dispatch of the generating units, fuel procurement and the execution of contracts, including economic hedges, to reduce price risk. For the month ended January 31, 2006, and year ended 2005, these services were received from Mirant

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Americas Energy Marketing. Amounts due to Mirant Energy Trading and due from Mirant Energy Trading under the Services Agreements are recorded as a net payable to affiliate or accounts receivable—affiliate because of the Company’s legal right of offset. Substantially all energy marketing overhead expenses are allocated to Mirant’s operating subsidiaries. During the years ended December 31, 2007, 2006 and 2005, the Company incurred approximately $24 million, $19 million and $24 million, respectively, in costs under these agreements. These costs are included in operations and maintenance—affiliate in the accompanying consolidated and combined statements of operations.

Restructuring Charges

During the year ended December 31, 2007, the Company did not record any restructuring charges. During the years ended December 31, 2006 and 2005, the Company recorded restructuring charges of $1 million and $2 million, respectively, for 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 Mirant Mid-Atlantic locations were paid by Mirant Services and billed to Mirant Mid-Atlantic and are included in the amounts disclosed above in “Management, Personnel and Services Agreement with Mirant Services.”

Notes Receivable from Affiliate

At December 31, 2005, current notes receivable from affiliate was $124 million. This amount was repaid in full on June 5, 2006. The Company recognized $2 million in interest income-affiliate for the year ended December 31, 2006, which is recorded in interest income—affiliate in the accompanying consolidated statement of operations. At December 31, 2006 and 2007, the Company did not have any notes receivable from affiliates.

Mirant Letters of Credit

Mirant posted pre-petition letters of credit and a guarantee on behalf of the Company to provide for the rent payment reserve required in connection with the Company’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 and the Company’s emergence from bankruptcy, Mirant North America posted a $75 million letter of credit for the benefit of Mirant Mid-Atlantic to cover rent payment reserve obligations on the Company’s leases. Upon the posting of the letter of credit, the trustee returned $56 million of cash collateral to Mirant Mid-Atlantic.

Purchased Emissions Allowances

The Company purchases emissions allowances from Mirant Energy Trading at Mirant Energy Trading’s original cost to purchase the allowances. Where allowances have been purchased by Mirant Energy Trading from a Mirant affiliate, the price paid by Mirant Energy Trading is determined by market indices. For the years ended December 31, 2007, and 2006, the Company purchased $12 million and $122 million, respectively, of emissions allowances from Mirant Energy Trading. For the year ended December 31, 2005, the Company sold allowances to Mirant Americas Energy Marketing for $5 million, resulting in a gain of $1 million, which is reflected in gross margin. Emissions allowances purchased from Mirant Energy Trading or Mirant Americas Energy Marketing that were utilized in the years ended December 31, 2007, 2006 and 2005 were $35 million, $65 million and $65 million, respectively, and are recorded in cost of fuel, electricity and other products-affiliate in the accompanying consolidated and combined statements of operations. Amounts expensed as a result of writing down emissions allowances to the lower of cost or market were $3 million, $36 million and $4 million, respectively, for the years ended December 31, 2007, 2006 and 2005. As of December 31, 2007 and 2006, the Company had purchased emissions allowances of $10 million and $36 million, respectively, which are recorded in fuel stock and emissions allowances in the accompanying consolidated balance sheets.

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Sale of Granted Emissions Allowances

In 2006, the Company sold to Mirant Energy Trading emissions allowances that had been granted by the EPA to Mirant Potomac River. For the year ended December 31, 2006, the sales of $2 million are recorded in gain on sale of assets, net—affiliate in the accompanying consolidated statement of operations.

Series A Preferred Shares in Mirant Americas

Pursuant to the Plan, Mirant Americas was required to make capital contributions to Mirant Mid-Atlantic for the purpose of funding future environmental capital expenditures. These capital contributions were made in the form of mandatorily redeemable Series A preferred shares and are reflected as preferred stock in affiliate in the accompanying consolidated balance sheets at December 31, 2007 and 2006. On June 30, 2007, Mirant Americas was required to redeem $5 million in preferred stock held by Mirant Mid-Atlantic, which was completed on July 2, 2007.

The Series A Preferred Shares have a Scheduled Redemption Date at a Specified Redemption Amount as follows (in millions):

2008	$	31
2009		84
2010		95
2011		50
	$	260

The redemption of any of the Series A Preferred Shares on any Scheduled Redemption Date shall be deferred to the extent that the Company has not incurred prior to the Scheduled Redemption Date, or does not reasonably expect to incur within 180 days of such Scheduled Redemption Date, expenditures with respect to the installation of control technology related to environmental capital expenditures at facilities owned or leased by the Company. Any amounts so deferred shall be added to the amount of Series A Preferred Shares to be redeemed on the next Scheduled Redemption Date.

The Company has the right to put the Series A Preferred Shares to Mirant at an amount equal to the Specified Redemption Amount in the event that Mirant Americas fails to redeem the Series A Preferred Shares on a Scheduled Redemption Date. The Series A Preferred Shares are recorded at a fair value of $229 million and $221 million as a component of equity in the Company’s consolidated balance sheets at December 31, 2007 and 2006, respectively. The fair value was determined using a discounted cash flow method based on the Specified Redemption Amounts using a 6.21% discount rate. For each of the years ended December 31, 2007 and 2006, the Company recorded $13 million in preferred stock in affiliate and member’s interest in the consolidated balance sheets related to the amortization of the discount on the preferred stock in Mirant Americas.

4.    Price Risk Management Activities

The Company enters into commodity forward physical transactions as well as derivative financial instruments to manage its market risk and exposure to market prices for electricity and natural gas, oil and other fuels utilized by the Company’s generating facilities under an affiliate agreement discussed in Note 3 or with third parties. As of February 1, 2006, the Company’s economic hedging activities historically conducted by Mirant Americas Energy Marketing are being performed by Mirant Energy Trading as described in Note 3.

Mirant Energy Trading normally enters into an offsetting third-party derivative contract. The physical transactions include forward contracts for physical sales and purchases of electricity and natural gas. The derivative financial instruments primarily include forwards, futures, options and swaps, and may include instruments whose underlying commodity is highly correlated to the electricity produced or to the fuels utilized by the Company’s generating facilities, although the underlying fuel commodity itself is not a component fuel used to produce electricity.

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

The fair values of the Company’s price risk management assets and liabilities—affiliate and nonaffiliate, net of credit reserves, at December 31, 2007 and 2006, are included in the following table (in millions):

	Current Assets		Current Liabilities			Noncurrent Liabilities			Net Fair Value at December 31, 2007
Total	$	9	$	(31	)	$	(131	)	$	(153	)

	Current Assets		Noncurrent Assets		Net Fair Value at December 31, 2006
Total	$	267	$	59	$	326

Of the $153 million net fair value liability at December 31, 2007, a net price risk management liability of $23 million relates to 2008, a net price risk management liability of $79 million relates to 2009, a net price risk management liability of $50 million relates to 2010 and a net price risk management liability of $1 million relates to periods thereafter.

The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at December 31, 2007, was approximately 12 months. The net notional amount, or net short position, of the price risk management assets and liabilities at December 31, 2007, was approximately 24 million equivalent MWh.

5.    Long-Lived Assets

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

	2007			2006			Depreciable Lives (years)
Production	$	1,800		$	1,625		18 to 33
Oil pipeline		26			26		24
Construction work in progress		607			165
Other		16			15		2 to 10
Less: accumulated depreciation.		(399	)		(336	)
Total property, plant and equipment, net.	$	2,050		$	1,495

Depreciation of the recorded cost of property, plant and equipment is recognized on a straight-line basis over the estimated useful lives of the assets. The Company received emissions allowances in the acquisition of the Pepco assets for both SO2 and NOx emissions and the right to future allowances. Acquired emissions allowances related to owned facilities that were projected to be required to offset physical emissions are included in production assets above, and are depreciated on a straight-line basis over the average life of the related generating facilities.

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The Company evaluates its long-lived assets (property, plant and equipment) and definite-lived intangibles for impairment whenever events or changes in circumstances indicate that the Company may not be able to recover the carrying amount of the asset. There have been no impairments of these assets for the years ended December 31, 2007, 2006 and 2005.

Goodwill, net

The Company evaluates goodwill for impairment at least annually and periodically if indicators of impairment are present in accordance with SFAS 142. The results of the Company’s impairment testing may be affected by a significant adverse change in the extent or manner in which the reporting unit’s assets are being used, a significant adverse change in legal factors or in the business climate that could affect the value of a reporting unit, as well as other economic or operational analyses. If the carrying amount of the reporting unit is not recoverable, an impairment charge is recorded. The amount of the impairment charge, if an impairment exists, is calculated as the difference between the fair value of the reporting unit goodwill and its carrying value. For this test, the Company’s business constitutes a single reporting unit. The Company performs its annual assessment of goodwill at October 31 and whenever contrary evidence exists as to the recoverability of goodwill.

The Company performed its annual evaluation for goodwill impairment at October 31, 2007, based on the Company’s most recent business plan and market data from independent sources. The Company utilized multiple valuation approaches in arriving at a fair value of the business unit for purposes of the test, including an income approach involving discounted cash flows and a market approach involving recent comparable transactions and trading multiples of peer companies. The annual evaluation of goodwill indicated that there was no impairment in 2007.

The critical assumptions used in the Company’s income valuation approach included assumptions as to future electricity and fuel prices, future levels of gross domestic product growth, levels of supply and demand, future operating expenditures and capital expenditure requirements, and estimates of the Company’s weighted average cost of capital. Assumptions about future revenue, costs and forward prices require significant judgment because such factors have fluctuated in the past and will continue to do so in the future.

Additionally, the assumptions included capital expenditures through the first quarter of 2010 required to install pollution control equipment in order to comply with Maryland Healthy Air Act as well as additional operating costs associated with the ongoing operation of the pollution control equipment. The Company assigned an equal weighting to the income and the market approach to determine the fair value of the reporting unit.

The above assumptions were critical to the Company’s determination of the fair value of its business unit. The combined subjectivity and sensitivity of the assumptions and estimates used in the goodwill impairment analysis could result in a reasonable person reaching a different conclusion regarding those critical assumptions and estimates, possibly resulting in an impairment charge having been required for all or a portion of the Company’s goodwill.

Other Intangible Assets, net

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

	Weighted Average Amortization Lives	2007					2006
		Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Development rights	40 years	$	47	$	(8	)	$	47	$	(7	)
Emissions allowances	32 years		131		(29	)		131		(25	)
Other intangibles	30 years		12		(3	)		12		(2	)
Total other intangible assets		$	190	$	(40	)	$	190	$	(34	)

F-17

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

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

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

All of Mirant Mid-Atlantic’s other intangible assets are subject to amortization and are being amortized on a straight-line basis over their estimated useful lives.

Amortization expense was approximately $6 million, $5 million and $6 million for the years ended December 31, 2007, 2006 and 2005, respectively. Assuming no future acquisitions, dispositions or impairments of intangible assets, amortization expense is estimated to be $6 million for each of the next five years.

6.    Long-Term Debt and Capital Leases

Long-term debt consists of a capital lease by Mirant Chalk Point. At December 31, 2007 and 2006, the current portion of the long-term debt under this capital lease was $3 million. The amount outstanding under the capital lease, which matures in 2015, is $30 million with an 8.19% annual interest rate. This lease is of an 84 MW peaking electric power generating facility. Depreciation expense related to this lease was approximately $2 million for each of the years ended December 31, 2007, 2006 and 2005. The principal payments under this lease are approximately $3 million in 2008 through 2010, $4 million in 2011 through 2012 and $13 million thereafter. The gross amount of assets under the capital lease, recorded in property, plant and equipment, net as of December 31, 2007 and 2006, was $24 million. The related accumulated depreciation was $12 million and $10 million as of December 31, 2007 and 2006, respectively.

7.     Income Taxes

Tax Uncertainties

The Company adopted the provisions of FIN 48 on January 1, 2007. Prior to adoption of FIN 48, the Company recognized contingent liabilities related to tax uncertainties when it was probable that a loss had occurred and the loss or range of loss could be reasonably estimated. The recognition of contingent losses for tax uncertainties required management to make significant assumptions about the expected outcomes of certain tax contingencies. Upon adoption of FIN 48, the Company changed its method to recognize only liabilities for uncertain tax positions that are less than or subject to the measurement threshold of the more-likely-than-not standard. As a result of the implementation of FIN 48, the Company recognized an increase in tax receivables of approximately $1 million related to prior years when the Company was subject to U.S. income taxes. The additional tax benefit resulted in an increase of the same amount to member’s interest. The unrecognized tax benefit as a result of adopting FIN 48 is an insignificant amount and would not materially affect the Company’s effective tax rate if it were to be recognized.

The unrecognized tax benefit included the review of tax positions relating to open tax years beginning in 1999 and continuing to the present. The Company’s major tax jurisdictions were U.S. federal and multiple state jurisdictions. For U.S. federal income taxes, all tax years prior to 2004 are closed and for state purposes the earliest open tax year is 2002. The Company’s tax provision includes an immaterial amount related to the accrual for any penalties and interest subsequent to its adoption of FIN 48.

F-18

Pro Forma Income Tax Disclosures

The Company is not subject to U.S. federal or state income taxes. In connection with the transfer of all its membership interests to Mirant Americas Generation, the Company’s indirect parent, in October 2002, the Company became a single member limited liability corporation for income tax purposes. As such, the Company is treated as though it was a branch or division of Mirant Americas Generation’s parent, Mirant Americas, for income tax purposes, and not as a separate taxpayer. Mirant Americas and Mirant are directly responsible for income taxes related to the Company’s operations.

The following reflects a pro forma disclosure of the income tax provision (benefit) that would be reported if the Company were to be allocated income taxes attributable to its operations. Pro forma income tax provision (benefit) attributable to income before tax would consist of the following (in millions):

	Years Ended December 31,
	2007			2006		2005
Current provision:
Federal	$	216		$	137	$	27
State		43			23		6
Deferred provision (benefit):
Federal		(148	)		167		(23	)
State		(15	)		29		(11	)
Total income tax provision (benefit)	$	96		$	356	$	(1	)

The following table presents the pro forma reconciliation of the Company’s federal statutory income tax provision for continuing operations adjusted for reorganization items to the pro forma effective income tax provision (benefit) (in millions):

	Years Ended December 31,
	2007		2006		2005
U.S. federal statutory income tax provision	$	59	$	323	$	3
State and local income taxes, net		18		33		(3	)
Effect of Internal Revenue Code §382(l)(6)		18
Reorganization items		1		—		(1	)
Tax provision (benefit)	$	96	$	356	$	(1	)

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the consolidated balance sheets and their respective tax bases which give rise to the pro forma deferred tax assets and liabilities would be as follows at December 31, 2007 and 2006 (in millions):

	2007			2006
Deferred tax liabilities:
Property and intangible assets	$	(209	)	$	(195	)
Price risk management assets and liabilities.		—			(126	)
Other, net.		(18	)		(5	)
Total		(227	)		(326	)
Deferred tax assets:
Price risk management assets and liabilities.		62			—
Other, net		2			—
Total		64			—
Net deferred tax liabilities	$	(163	)	$	(326	)

F-19

Mirant elected in its 2006 tax return to reduce the income tax basis of its depreciable assets for any cancellation of debt income that arises from Mirant making an Internal Revenue Code section (§) 382(l)(6) election. As a result, the Company has reduced the tax basis of its depreciable assets by recording an increase to pro forma property and intangible assets tax liability of $21 million in 2007.

The Company has not provided a pro forma deferred tax liability with respect to the Company’s investment in the Mirant Americas preferred stock discussed in Note 3, since the underlying transaction is disregarded for income tax purposes.

The pro forma increase in tax benefits that would have been recognized upon adoption of FIN 48 is approximately $1 million. The pro forma unrecognized tax benefit as a result of adopting FIN 48 is an insignificant amount and would not materially affect the Company’s pro forma effective tax rate if it were recognized. The Company’s pro forma tax provision includes an immaterial amount related to the accrual for any pro forma penalties and interest subsequent to its adoption on FIN 48.

8.    Asset Retirement Obligations

Effective January 1, 2003, the Company adopted SFAS 143, which requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Additionally, effective December 31, 2005, the Company adopted FIN 47, which expands the scope of asset retirement obligations to be recognized to include asset retirement obligations that may be uncertain as to the nature or timing of settlement. Upon initial recognition of a liability for an asset retirement obligation or a conditional asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS 143 and FIN 47 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

The Company identified certain asset retirement obligations within its power generating facilities. These asset retirement obligations are primarily related to asbestos abatement in facilities on owned or leased property and other environmental obligations related to fuel storage facilities, wastewater treatment facilities, ash disposal sites and pipelines.

Asbestos abatement is the most significant type of asset retirement obligation identified for recognition in the Company’s adoption of FIN 47. The EPA has regulations in place governing the removal of asbestos. Due to the nature of asbestos, it can be difficult to ascertain the extent of contamination in older facilities unless substantial renovation or demolition takes place. Therefore, the Company incorporated certain assumptions based on the relative age and size of its facilities to estimate the current cost for asbestos abatement. The actual abatement cost could differ from the estimates used to measure the asset retirement obligation. As a result, these amounts will be subject to revision when actual abatement activities are undertaken.

F-20

The following table sets forth the balances of the asset retirement obligations as of January 1, 2006, and the additions and accretion of the asset retirement obligations for the years ended December 31, 2007 and 2006. The asset retirement obligations are included in noncurrent liabilities in the consolidated balance sheets (in millions):

	For the Years Ended December 31,
	2007		2006
Beginning balance, January 1	$	12	$	9
Liabilities recorded in the period		1		2
Accretion expense		1		1
Ending balance, December 31	$	14	$	12

The following represents, on a pro forma basis, the amount of the liability for asset retirement obligations as if FIN 47 had been applied during all periods affected (in millions):

	For the Year Ended December 31, 2005
Beginning balance, January 1	$	9
Revisions to cash flows for liabilities recognized upon adoption of SFAS 143		(1	)
Accretion expense		1
Ending balance, December 31	$	9

9.    Commitments and Contingencies

In addition to debt and other obligations in the consolidated balance sheets, the Company has the following annual commitments under various agreements at December 31, 2007, related to its operations (in millions):

	Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations by Year
	Total		2008		2009		2010		2011		2012		>5 Years
Generating units operating leases	$	2,133	$	121	$	142	$	140	$	134	$	132	$	1,464
Other operating leases		29		4		4		4		2		1		14
Coal purchases-affiliate		506		314		192		—		—		—		—
Other purchase commitments		94		94		—		—		—		—		—
Maryland Healthy Air Act		713		689		24		—		—		—		—
Total payments	$	3,475	$	1,222	$	362	$	144	$	136	$	133	$	1,478

Operating Leases

Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively. Mirant Mid-Atlantic has an option to extend the leases. Any extensions of the respective leases would be limited to 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. The Company is accounting for these leases as operating leases and recognizes rent expense on a straight-line basis. Rent expense totaled $96 million for the years ended December 31, 2007 and 2006, and $99 million for the year ended December 31, 2005, and is included in operations and maintenance-nonaffiliate in the accompanying consolidated and combined statements of operations. As of December 31, 2007 and 2006, the Company has paid approximately $330 million and $314 million, respectively, of lease payments in excess of rent expense recognized, which is recorded in prepaid rent on the consolidated balance sheets.

F-21

As of December 31, 2007, the total notional minimum lease payments for the remaining terms of the leases aggregated approximately $2.1 billion and the aggregate termination value for the leases was approximately $1.4 billion and generally decreases over time. Mirant Mid-Atlantic leases the Morgantown and the Dickerson baseload units from third party owner lessors. These owner lessors each own the undivided interests in these baseload generating facilities. The subsidiaries of the institutional investors who hold the membership interests in the owner lessors are called owner participants. Equity funding by the owner participants plus transaction expenses paid by the owner participants totaled $299 million. The issuance and sale of pass through certificates raised the remaining $1.2 billion needed for the owner lessors to acquire the undivided interests.

The pass through certificates are not direct obligations of Mirant Mid-Atlantic. Each pass through certificate represents a fractional undivided interest in one of three pass through trusts formed pursuant to three separate pass through trust agreements between Mirant Mid-Atlantic and U.S. Bank National Association (as successor in interest to State Street Bank and Trust Company of Connecticut, National Association) as pass through trustee. The property of the pass through trusts consists of lessor notes. The lessor notes issued by an owner lessor are secured by that owner lessor’s undivided interest in the lease facilities and its rights under the related lease and other financing documents.

The Company has commitments under other operating leases with various terms and expiration dates. Minimum lease payments under non-cancelable operating leases approximate $4 million in each of 2008, 2009 and 2010, $2 million in 2011, $1 million in 2012 and $14 million thereafter. Expenses associated with these commitments totaled approximately $4 million per year during 2007, 2006 and 2005.

Coal Purchases-Affiliate

Coal purchases- affiliate primarily relate to long-term coal agreements. As of December 31, 2007, the Company’s total estimated coal purchases-affiliate commitments were $506 million. In addition, the Company has transactions for which commercial terms have been negotiated but for which contracts have not yet been executed. Individual transactions may or may not be binding prior to execution of a contract.

Other Purchase Commitments

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

Maryland Healthy Air Act

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

10.    Litigation and Other Contingencies

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

F-22

Environmental Matters

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

Morgantown Particulate Emissions NOV.    On March 3, 2006, the Company received a notice sent on behalf of the MDE alleging that violations of particulate matter emissions limits applicable to unit 1 at the Morgantown facility occurred on nineteen days in June and July 2005. The notice advises that the potential civil penalty is up to $25,000 per day for each day that unit 1 exceeded the applicable particulate matter limit. The letter further advises that the MDE has asked the Maryland Attorney General to file a civil suit under Maryland law based upon the alleged violations.

Morgantown SO2 Exceedances.    The Company received an NOV dated March 8, 2006, asserting that on three days in June 2005 and January 2006, the Morgantown facility exceeded SO2 emissions limitations specified in its air permit. The NOV indicates that on two of those days the SO2 emissions limitation was exceeded by two different units of the Morgantown facility each day. The NOV did not seek a specific penalty amount but noted that the violations identified could subject the Company to a civil penalty of up to $25,000 per day.

Morgantown Emissions Observation NOV.    On June 30, 2006, the MDE issued an NOV to the Company indicating that it had failed to comply with the air permit for the Morgantown facility by operating the combustion turbines at the facility for more than 168 hours without performing an EPA Reference Method 9 observation of stack emissions for an 18-minute period. The NOV did not seek a specific penalty amount but noted that the violation identified could subject the Company to a civil penalty of up to $25,000 per day.

Mirant Potomac River NAAQS Exceedance.    On March 23, 2007, the Virginia DEQ issued an NOV to Mirant Potomac River alleging that it violated Virginia’s Air Pollution Control Law and regulations on February 23, 2007, by operating the Potomac River facility in a manner that resulted in a monitored exceedance in a twenty-four hour period of the NAAQS for SO2. As noted in the NOV, Mirant Potomac River was operating on February 23, 2007, as directed by PJM in accordance with a DOE order during a scheduled outage of the Pepco transmission lines serving Washington, D.C. The NOV asserts that plant operators did not implement appropriate actions to minimize SO2 emissions. The NOV did not seek a specific penalty amount but noted that the violations identified could subject Mirant Potomac River to civil penalties of varying amounts under different provisions of the Virginia Code, including a potential civil fine of up to $100,000.

F-23

Chapter 11 Proceedings

On July 14, 2003, and various dates thereafter, Mirant Corporation and certain of its subsidiaries (collectively, the “Mirant Debtors”), including the Company and its subsidiaries, filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Mirant, the Company and most of the Mirant Debtors emerged from bankruptcy on January 3, 2006, when the Plan became effective. The remaining Mirant Debtors, Mirant New York, Mirant Bowline, Mirant Lovett, Mirant NY-Gen, and Hudson Valley Corporation, emerged from bankruptcy on various dates in 2007. As of December 31, 2007, approximately one million of the shares of Mirant common stock to be distributed under the Plan had not yet been distributed and have been reserved for distribution with respect to claims disputed by the Mirant Debtors that have not been resolved. Under the terms of the Plan, to the extent unresolved claims are resolved now that the Company has emerged from bankruptcy, the claimants will receive the same pro rata distributions of Mirant common stock, cash, or both common stock and cash as previously allowed claims.

To the extent the aggregate amount of the payouts determined to be due with respect to disputed claims ultimately exceeds the amount of the funded claim reserve, Mirant would have to issue additional shares of common stock to address the shortfall, which would dilute existing Mirant stockholders, and Mirant and Mirant Americas Generation would have to pay additional cash amounts as necessary under the terms of the Plan to satisfy such pre-petition claims.

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

In certain market conditions, such as where congestion requires the dispatch of a generating facility that bid a higher price for electricity than other available generating facilities, PJM’s market rules (the “Offer Capping Rules”) limit the amount that the owner of a generating facility may bid to sell electricity from that facility to its incremental cost of service to produce that electricity. As approved by the FERC, the Offer Capping Rules contain exemptions for generating facilities entering service during certain years (none of which are owned by the Company) and for generating facilities (some of which are owned by the Company) that can relieve congestion arising at certain defined transmission interfaces. On January 15, 2008, the Maryland Public Service Commission (the “MD PSC”) filed a complaint with the FERC requesting that the FERC remove all exemptions to the Offer Capping Rules during hours when the PJM market reflects potentially non-competitive conditions, as determined by the PJM Market Monitor. The complaint alleges that these exemptions to the Offer Capping Rules likely result in higher market clearing prices for electricity in PJM, and higher revenues to the Company and the other owners of generation that are selling electricity, during the periods when the exemptions prevent the application of the Offer Capping Rules to one or more generating facilities. The MD PSC requested that the FERC require a rerunning of the dispatch of the PJM energy markets without application of the exemptions to the Offer Capping Rules for each day from January 15, 2008, through the date that the Commission grants the requested relief and that it require owners of generation to refund any revenues received in excess of the amounts that would have been received had the exemptions not been applied.

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

The Company disputes the allegations made by the MD PSC in its complaint and intends to oppose the complaint and the relief requested. If the FERC were to remove the exemptions to the Offer Capping Rules, and apply the removal retroactively from January 15, 2008, or an earlier date, PJM would have to rerun its day-ahead market from that date forward to determine what prices would have resulted in the absence of the exemptions. Such a rerun of the PJM day-ahead market likely would result in refunds being owed by all sellers, including the Company, but the potential amount cannot be quantified.

F-24

Other Legal Matters

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

11.    Settlements and Other Charges

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

Mirant assigned its rights and obligations under the Back-to-Back Agreement to Mirant Americas Energy Marketing. In the Chapter 11 cases of the Mirant Debtors, Pepco asserted that an Assignment and Assumption Agreement dated December 19, 2000, that included as parties Pepco, the Company, and various of the Company’s subsidiaries, caused the Company and its subsidiaries that were parties to the agreement to be jointly and severally liable to Pepco for various obligations, including the obligations under the Back-to-Back Agreement. The Mirant Debtors sought to reject the APSA, the Back-to-Back Agreement, and the Assignment and Assumption Agreement. Under the Plan, the obligations of the Mirant Debtors under the APSA (including any other agreements executed pursuant to the terms of the APSA and found by a final court order to be part of the APSA), the Back-to-Back Agreement, and the Assignment and Assumption Agreement were performed after January 3, 2006, by Mirant Power Purchase, whose performance was guaranteed by Mirant, pending resolution of the rejection motions.

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

Under the Settlement Agreement, Mirant Power Purchase assumed the remaining obligations under the APSA, and Mirant has guaranteed its performance. With respect to the other agreements executed as part of the closing of the APSA (the “Ancillary Agreements”) and other agreements between Pepco and subsidiaries of Mirant, including the Company and its subsidiaries, the Mirant subsidiary that is a party to each agreement has assumed the agreement and Mirant has guaranteed that subsidiary’s performance. Mirant Power Purchase’s obligations under the APSA do not include any obligations related to the Ancillary Agreements. The Settlement Agreement provides that a future breach of the APSA or any Ancillary Agreement by a party to such agreement will not entitle the non-defaulting party to terminate, suspend performance under, or exercise any other right or remedy under or with respect to any of the remainder of such agreements.

F-25

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

F-26

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Inherent Limitations in Control Systems

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

Effectiveness of Disclosure Controls and Procedures

As required by Exchange Act Rule 13a-15(b), our management, including our Chief Executive Officer and our Chief Financial Officer, conducted an assessment of the effectiveness of the design and operation of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of December 31, 2007. Based upon this assessment, our management concluded that, as of December 31, 2007, the design and operation of these disclosure controls and procedures were effective.

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

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined by Rules 13a-15(f) under the Exchange Act). The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Internal control over financial reporting includes those processes and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

• provide reasonable assurance that transactions are recorded properly to allow for the preparation of financial statements, in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company;

39

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the consolidated and combined financial statements; and

• provide reasonable assurance as to the detection of fraud.

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we carried out an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007. In conducting our assessment, management utilized the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2007.

Changes in Internal Controls

During the quarter ended December 31, 2007, there were no significant changes in Mirant Mid-Atlantic’s internal control over financial reporting or in other factors that could materially affect or are reasonably likely to affect such internal controls over financial reporting.

Item 9B. Other Information

None.

40

PART III

Item 10.    Directors and Executive Officers of the Registrant

The table below sets forth information on each member of the Board of Managers of the Company as of December 31, 2007. Each member of the Board of Managers is also an executive officer of Mirant.

Name	Age	Position
Edward R. Muller	56	Board Manager since January 3, 2006. Director, Chairman, President and Chief Executive Officer of Mirant Corporation since September 2005. Board Manager of Mirant Americas Generation and Mirant North America since January 3, 2006. Former President and Chief Executive Officer (1993-2000) of Edison Mission Energy, a California-based independent power producer. Mr. Muller is also a director of Transocean Inc.
James V. Iaco	63	Board Manager since January 3, 2006. Executive Vice President and Chief Financial Officer of Mirant Corporation since November 2005. Board Manager of Mirant Americas Generation and Mirant North America since January 3, 2006. Former Senior Vice President and President, Americas Division (1998–2000), and former Senior Vice President and Chief Financial Officer (1994–1998) of Edison Mission Energy.
Robert M. Edgell	61	Chairman of the Board, Mirant North America and Mirant Americas Generation since January 9, 2006. Executive Vice President (since 2006) and Chief Operating Officer (since 2007) of Mirant Corporation. Former Managing Director (2005) of Private Power International Development PTE, LTD, a Singapore registered private company engaged in consulting, development and equity investment in private power projects in Asia. Former Executive Vice President and General Manager, Asia-Pacific Division (1996–2005) of Edison Mission Energy.

41

The table below sets forth information on the principal executive officer, principal financial officer and principal accounting officer of Mirant Mid-Atlantic as of December 31, 2007. These officers are also officers of Mirant. Policy-making functions for Mirant Mid-Atlantic are performed by the Board of Managers of Mirant Mid-Atlantic and the other executive officers of Mirant. Information on the executive officers of Mirant will be provided in the Mirant definitive Proxy Statement for its 2008 Annual Meeting of Stockholders.

Name	Age	Position
Robert E. Driscoll	58	President and Chief Executive Officer of Mirant Mid-Atlantic, Mirant Americas Generation and Mirant North America since January 9, 2006. Mr. Driscoll is Senior Vice President and Head of Asset Management of Mirant Corporation. From 2001 through 2005, he was employed as Chief Executive Officer, Australia and Senior Vice President, Asia of Edison Mission Energy, and from 1995 through 2001, he was employed as Senior Vice President, Asia of Edison Mission Energy.
J. William Holden III	47	Senior Vice President, Chief Financial Officer and Treasurer since November 2002. Mr. Holden has been Senior Vice President and Treasurer of Mirant Corporation since April 2002 and has served as Senior Vice President, Chief Financial Officer and Treasurer of Mirant Americas Generation and Mirant North America since November 2002. Previously, he was Chief Financial Officer for Mirant’s Europe group from 2001 to February 2002, Vice President and Treasurer of Mirant from 1999 to 2001, Vice President, Operations and Business Development for Mirant’s South American region from 1996 to 1999, and Vice President, Business Development for Mirant’s Asia group from 1994 to 1995. He held various positions at Southern Company from 1985 to 1994, including Director of Corporate Finance.
Thomas E. Legro	56	Senior Vice President, Principal Accounting Officer and Controller since December 2005. Mr. Legro has been Senior Vice President, Principal Accounting Officer and Controller of Mirant Corporation, Mirant Americas Generation and Mirant North America since December 2005. Prior to joining Mirant, he served as Vice President, Chief Accounting Officer and Corporate Controller, National Energy & Gas Transmission, Inc. (2001-2004), Vice President, Corporate Controller, Director of Financial Planning and Analysis, and Assistant Controller, Edison Mission Energy (1990-2001).

The principal executive officer, principal financial officer and principal accounting officer of Mirant Mid-Atlantic were elected to serve until their successors are elected and have qualified or until their removal, resignation, death or disqualification.

Audit Committee and Audit Committee Financial Expert

We do not have a separately designated standing Audit Committee. Because Mirant Mid-Atlantic is an indirect wholly-owned subsidiary of Mirant Corporation, the Board of Managers does not have independent members and therefore has not separately designated a member as a financial expert.

Section 16(a) Beneficial Ownership Reporting Compliance

We do not have equity securities registered pursuant to Section 12 of the Exchange Act and therefore do not have officers with Section 16 reporting obligations.

42

Code of Ethics for Senior Financial Officers

Mirant has a Code of Ethics and Business Conduct that applies to all Mirant officers, employees, subsidiaries and the Mirant Board of Directors. In addition, Mirant has adopted a Code of Conduct for Senior Financial Officers applicable to Mirant’s senior financial officers that also applies to the senior financial officers of Mirant Mid-Atlantic. A copy of each code is posted on Mirant’s website at www.mirant.com and also will be provided, without charge, upon request made in writing to Mirant’s Corporate Secretary at 1155 Perimeter Center West, Atlanta, GA 30338. We intend to post any amendments and waivers to the Code of Ethics for senior financial officers on this website.

Shareholder Nominees to Board of Directors

We will not adopt procedures by which shareholders may recommend manager candidates because we are a wholly-owned subsidiary of Mirant North America.

Item 11.    Executive Compensation

The officers of Mirant Mid-Atlantic are also officers of Mirant. Our officers are not compensated separately in their positions with Mirant Mid-Atlantic and none of our officers has a contract or agreement in his capacity as an officer of Mirant Mid-Atlantic. Policy-making functions for Mirant Mid-Atlantic are performed by the Board of Managers of Mirant Mid-Atlantic and the other executive officers of Mirant. Information on compensation for the executive officers of Mirant will be provided in the Mirant definitive Proxy Statement for its 2008 Annual Meeting of Stockholders.

All of our equity is held by our direct parent, Mirant North America. Therefore, our equity is not publicly traded and there is no basis to compare the price performance of our equity to the price performance of an index or peer group.

Item 12.    Security Ownership of Certain Beneficial Owners and Management

We are a direct, wholly-owned subsidiary of Mirant North America; therefore, none of our managers or officers hold any equity interests in Mirant Mid-Atlantic.

Item 13.    Certain Relationships and Related Transactions

Review and Approval of Related Person Transactions

We are an indirect wholly-owned subsidiary of Mirant. Mirant’s Nominating and Governance Committee is responsible for reviewing and approving any related party transactions by Mirant, including transactions taken at the subsidiary level. Mirant’s legal department has adopted policies and procedures to assess transactions and relationships between Mirant and/or its subsidiaries and any related parties to determine if they have a direct or indirect material interest in the transaction. All related party transactions must be approved by the Nominating and Governance Committee.

Related Person Transactions

There were no reportable transactions between Mirant Mid-Atlantic and related parties in 2007.

Item 14.    Principal Accountant Fees and Services

Not Applicable.

43

PART IV

Item 15.    Exhibits and Financial Statement Schedules

a) 1.    Financial Statements

Our consolidated and combined financial statements, including the notes thereto and independent auditors’ report thereon, are set forth on pages F-1 through F-26 of the Annual Report on Form 10-K, and are incorporated herein by reference.

2.    Financial Statement Schedules

None

3.    Exhibit Index

Exhibit No.	Exhibit Name
3.1*	Certificate of Formation of Southern Energy Mid-Atlantic (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 3.1)
3.2*	Amended and Restated Limited Liability Company Agreement of Mirant Mid-Atlantic LLC, dated as of January 3, 2006 (Designated on Form 10-Q for the quarter ended September 30, 2006 as Exhibit 3.2)
4.1*	Form of 8.625% Series A Pass Through Certificate (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.1)
4.2*	Form of 9.125% Series B Pass Through Certificate (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.2)
4.3*	Form of 10.060% Series C Pass Through Certificate (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.3)
4.4(a)*	Pass Through Trust Agreement A between Southern Energy Mid-Atlantic, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.4a)
4.4(b)*	Schedule identifying substantially identical agreements to Pass Through Trust Agreement constituting Exhibit 4.4(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.4b)
4.5(a)*	Participation Agreement (Dickerson L1) among Southern Energy Mid-Atlantic, LLC, as Lessee, Dickerson OL1 LLC, as Owner Lessor, Wilmington Trust Company, as Owner Manager, SEMA OP3, as Owner Participant and State Street Bank and Trust Company of Connecticut, National Association, as Lease Indenture Trustee and as Pass Through Trustee, dated as of December 18, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.5a)
4.5(b)*	Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.5(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.5b)
4.6(a)*	Participation Agreement (Morgantown L1) among Southern Energy Mid-Atlantic, LLC, as Lessee, Morgantown OL1 LLC, as Owner Lessor, Wilmington Trust Company, as Owner Manager, SEMA OP1, as Owner Participant and State Street Bank and Trust Company of Connecticut, National Association, as Lease Indenture Trustee and as Pass Through Trustee, dated as of December 18, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.6a)
4.6(b)*	Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.6(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.6b)

44

Exhibit No.	Exhibit Name
4.7(a)*	Facility Lease Agreement (Dickerson L1) between Southern Energy Mid-Atlantic, LLC, as Lessee, and Dickerson OL1 LLC, as Owner Lessor, dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.7a)
4.7(b)*	Schedule identifying substantially identical agreements to Facility Lease Agreement constituting Exhibit 4.7(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.7b)
4.8(a)*	Facility Lease Agreement (Morgantown L1) between Southern Energy Mid-Atlantic, LLC, as Lessee, and Morgantown OL1 LLC, as Owner Lessor, dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.8a)
4.8(b)*	Schedule identifying substantially identical agreements to Facility Lease Agreement constituting Exhibit 4.8(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.8b)
4.9(a)*	Indenture of Trust, Mortgage and Security Agreement (Dickerson L1) between Dickerson OL1 LLC, as Lessor, and State Street Bank and Trust Company of Connecticut, National Association, as Lease Indenture Trustee, dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.9a)
4.9(b)*	Schedule identifying substantially identical agreements to Indenture of Trust, Mortgage and Security Agreement constituting Exhibit 4.9(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.9b)
4.10(a)*	Indenture of Trust, Mortgage and Security Agreement (Morgantown L1) between Morgantown OL1 LLC, as Lessor, and State Street Bank and Trust Company of Connecticut, National Association, as Lease Indenture Trustee, dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.10a)
4.10(b)*	Schedule identifying substantially identical agreements to Indenture of Trust, Mortgage and Security Agreement constituting Exhibit 4.10(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.10b)
4.11(a)*	Series A Lessor Note for Dickerson OL1 LLC (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.11a)
4.11(b)*	Schedule identifying substantially identical notes to Lessor Notes Constituting Exhibit 4.11(a) (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.11b)
4.12(a)*	Series A Lessor Note for Morgantown OL1 LLC (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.12a)
4.12(b)*	Schedule identifying substantially identical notes to Lessor Notes Constituting Exhibit 4.12(a) (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.12b)
4.13(a)*	Series B Lessor Note for Dickerson OL1 LLC (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.13a)
4.13(b)*	Schedule identifying substantially identical notes to Lessor Notes Constituting Exhibit 4.13(a) (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.13b)
4.14(a)*	Series B Lessor Note for Morgantown OL1 LLC (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.14a)
4.14(b)*	Schedule identifying substantially identical notes to Lessor Notes Constituting Exhibit 4.14(a) (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.14b)
4.15(a)*	Series C Lessor Note for Morgantown OL1 LLC (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.15a)

45

Exhibit No.	Exhibit Name
4.15(b)*	Schedule identifying substantially identical notes to Lessor Notes Constituting Exhibit 4.15(a) (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.15b)
4.16*	Registration Rights Agreement, between Southern Energy Mid-Atlantic, LLC and Credit Suisse First Boston, acting for itself on behalf of the Purchasers, dated as of December 18, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.16)
4.17(a)*	Supplemental Pass Through Trust Agreement A between Mirant Mid-Atlantic, LLC, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, dated as of June 29, 2001 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.17a)
4.17(b)*	Schedule identifying substantially identical to Supplemental Pass Through Trust Agreement constituting Exhibit 4.17(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 4.17b)
10.1*	Engineering, Procurement and Construction Agreement dated as of July 30, 2007, by and between the Company, Mirant Chalk Point, LLC and Stone and Webster, Inc. (Designated on Form 8-K filed August 3, 2007, as Exhibit 10.1)
10.2*	Power Sale, Fuel Supply and Services Agreement dated as of January 3, 2006 between Mirant Mid-Atlantic, LLC and Mirant Americas Energy Services, LP (Designated on Form 10-K for the year ended December 31, 2006, as Exhibit 10.17)
10.3*	Power Sale, Fuel Supply and Services Agreement dated as of January 3, 2006 between Mirant Americas Energy Marketing, LP and Mirant Chalk Point, LLC (Designated on Form 10-K for the year ended December 31, 2006, as Exhibit 10.18)
10.4*	Power Sale, Fuel Supply and Services Agreement dated January 3, 2006 between Mirant Americas Energy Marketing, LP and Mirant Potomac River, LLC (Designated on Form 10-K for the year ended December 31, 2006, as Exhibit 10.19)
10.5*	Administrative Services Agreement dated as of January 3, 2006 between Mirant Mid-Atlantic, LLC and Mirant Services, LLC (Designated on Form 10-K for the year ended December 31, 2006, as Exhibit 10.20)
10.6(a)*	Asset Purchase and Sale Agreement between Potomac Electric Power Company and Southern Energy, Inc. (currently known as Mirant Corporation) dated as of June 7, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.1a)
10.6(b)*	Amendment No. 1 to Asset Purchase and Sale agreement between Potomac Electric Power Company and Southern Energy, Inc. dated as of September 18, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.1b)
10.6(c)*	Amendment No. 2 to Asset Purchase and Sale Agreement between Potomac Electric Power Company and Southern Energy, Inc. dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.1c)
10.7(a)*	Interconnection Agreement (Dickerson) between Potomac Electric Power Company and Southern Energy Mid-Atlantic, LLC dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.2a)
10.7(b)*	Schedule identifying substantially identical agreements to Interconnection Agreement constituting Exhibit 10.2(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.2b)
10.8(a)*	Easement, License and Attachment Agreement (Dickerson) between Potomac Electric Power Company, Southern Energy Mid-Atlantic, LLC and Southern Energy MD Ash Management, LLC (currently known as Mirant MD Ash Management, LLC) dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.3a)

46

Exhibit No.	Exhibit Name
10.8(b)*	Schedule identifying substantially identical agreements to Easement, License and Attachment Agreement constituting Exhibit 10.3(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.3b)
10.9(a)*	Bill of Sale (Dickerson, Morgantown, Production Service Center and Railroad Spur) between Potomac Electric Power Company and Southern Energy Mid-Atlantic, LLC dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.4a)
10.9(b)*	Schedule identifying substantially identical documents to Bill of Sale constituting Exhibit 10.4(A) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.4b)
10.10(a)*	Facility Site Lease Agreement (Dickerson L1) between Southern Energy Mid-Atlantic, LLC, Dickerson OL1 LLC and Southern Energy MD Ash Management, LLC dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.5a)
10.10(b)*	Schedule identifying substantially identical agreements to Facility Site Lease Agreement constituting Exhibit 10.5(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.5b)
10.11(a)*	Facility Site Lease Agreement (Morgantown L1) between Southern Energy Mid-Atlantic, LLC, Morgantown OL1 LLC and Southern Energy MD Ash Management, LLC dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.6a)
10.11(b)*	Schedule identifying substantially identical agreements to Facility Site Lease Agreement constituting Exhibit 10.6(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.6b)
10.12(a)*	Facility Site Sublease Agreement (Dickerson L1) between Southern Energy Mid-Atlantic, LLC, Dickerson OL1 LLC dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.7a)
10.12(b)*	Schedule identifying substantially identical agreements to Facility Site Sublease Agreement constituting Exhibit 10.7(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.7b)
10.13(a)*	Facility Site Sublease Agreement (Morgantown L1) between Southern Energy Mid-Atlantic, LLC, Morgantown OL1 LLC dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.8a)
10.13(b)*	Schedule identifying substantially identical agreements to Facility Site Sublease Agreement constituting Exhibit 10.8(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.8b)
10.14*	Capital Contribution Agreement between Southern Energy, Inc. and Southern Energy Mid-Atlantic, LLC dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.12)
10.15*	Promissory Note between Southern Energy Mid-Atlantic, LLC and Southern Energy Peaker, LLC in the original principal amount of $71,110,000 dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.13)
10.16*	Promissory Note between Southern Energy Mid-Atlantic, LLC and Southern Energy Potomac River, LLC in the original principal amount of $152,165,000 dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.14)
10.17(a)*	Shared Facilities Agreement (Dickerson) between Southern Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC, Dickerson OL3 LLC, and Dickerson OL4 LLC, dated as of December 18, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.15a)

47

Exhibit No.	Exhibit Name
10.17(b)*	Shared Facilities Agreement (Morgantown) between Southern Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC, Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC, Morgantown OL6 LLC, and Morgantown OL7 LLC, dated as of December 18, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.15b)
10.18(a)*	Assignment and Assumption Agreement (Dickerson) between Southern Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC, Dickerson OL3 LLC, and Dickerson OL4 LLC, dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.16a)
10.18(b)*	Assignment and Assumption Agreement (Morgantown) between Southern Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC, Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC, Morgantown OL6 LLC, and Morgantown OL7 LLC, dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.16b)
10.19(a)*	Ownership and Operation Agreement (Dickerson) between Southern Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC, Dickerson OL3 LLC, and Dickerson OL4 LLC, dated as of December 18, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.17a)
10.19(b)*	Ownership and Operation Agreement (Morgantown) between Southern Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC, Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC, Morgantown OL6 LLC, and Morgantown OL7 LLC, dated as of December 18, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.17b)
10.20(a)*	Guaranty Agreement (Dickerson L1) between Southern Energy, Inc. and Dickerson OL1 LLC dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.21a)
10.20(b)*	Schedule identifying substantially identical agreements to Guaranty Agreement constituting Exhibit 10.21(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.21b)
10.21(a)*	Guaranty Agreement (Morgantown L1) between Southern Energy, Inc. and Morgantown OL1 LLC dated as of December 19, 2000 (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.22a)
10.21(b)*	Schedule identifying substantially identical agreements to Guaranty Agreement constituting Exhibit 10.22(a) hereto (Designated on Form S-4 in Registration No. 333-61668 as Exhibit 10.22b)
21.1	Subsidiaries of Mirant Mid-Atlantic, LLC
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a)).
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a)).
32.1	Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b)).
32.2	Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b)).

* Asterisk indicates exhibits incorporated by reference.

48

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 9^th day of March 2008.

MIRANT MID-ATLANTIC, LLC
By:	/s/ ROBERT E. DRISCOLL
	Robert E. Driscoll Chief Executive Officer (Principal Executive Officer)

MIRANT MID-ATLANTIC, LLC

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 9, 2008, by the following persons on behalf of the registrant and in the capacities indicated.

Signatures	Title
/s/ ROBERT E. DRISCOLL         Robert E. Driscoll	Chief Executive Officer and Manager of Mirant Mid-Atlantic, LLC     (Principal Executive Officer)
/s/ J. WILLIAM HOLDEN III         J. William Holden III	Senior Vice President, Chief Financial Officer and Treasurer of Mirant Mid-Atlantic, LLC     (Principal Financial Officer)
/s/ THOMAS E. LEGRO       Thomas E. Legro	Vice President and Controller Mirant Mid-Atlantic, LLC (Principal Accounting Officer)
/s/ EDWARD R. MULLER       Edward R. Muller	Manager of Mirant Mid-Atlantic, LLC
/s/ JAMES V. IACO         James V. Iaco	Manager of Mirant Mid-Atlantic, LLC
/s/ ROBERT M. EDGELL         Robert M. Edgell	Manager of Mirant Mid-Atlantic, LLC

Supplemental Information to be Furnished with Reports Filed Pursuant to

Section 15(d) of the Act by Registrants Which Have Not Registered

Securities Pursuant to Section 12 of the Act

No annual report or proxy materials has been sent to securities holders and no such report or proxy material is to be furnished to securities holders subsequent to the filing of the annual report on this Form 10-K.