PART I

Item 1. Business

Overview

We are an independent power provider that produces and sells electricity. We are a direct wholly-owned subsidiary of Mirant North America, a holding company subsidiary of Mirant Americas Generation, and an indirect wholly-owned subsidiary of Mirant. We were formed as a Delaware limited liability company on July 12, 2000. We began operations on December 19, 2000, in conjunction with Mirant’s acquisition of certain generating assets and other related assets from Pepco. Mirant previously assigned its rights and obligations under its acquisition agreement to us, our subsidiaries and certain of our affiliates.

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. We historically executed these transactions with Mirant Americas Energy Marketing, one of our affiliates. Pursuant to the Plan of Reorganization (the “Plan”) and effective on February 1, 2006, we now execute these transactions with Mirant Energy Trading, a wholly-owned subsidiary of Mirant North America. We also have a number of service agreements for labor and administrative services with Mirant Services.

We economically hedge a substantial portion of our coal-fired baseload generation through OTC transactions. In 2006 and through February 26, 2007, we entered into financial swap transactions resulting in us being economically hedged for approximately 92%, 93%, 97% and 38% of our expected on-peak coal-fired baseload generation in 2007, 2008, 2009 and 2010, respectively. The financial swap transactions include new hedges in addition to the previously disclosed January 2006 hedges. These transactions are senior unsecured obligations and do not require the posting of cash collateral either for initial margin or for securing exposure due to changes in power prices. As of February 26, 2007, our total portfolio is economically hedged approximately 92%, 58%, 43% and 17% for 2007, 2008, 2009 and 2010, respectively. The corresponding fuel hedges are approximately 97%, 33%, 18% and 0% for 2007, 2008, 2009 and 2010, respectively.

We own or lease four generation facilities with a total generation capacity of 5,256 MW: Chalk Point, Morgantown, Dickerson and Potomac River. We had a combined 2006 capacity factor (average percentage of full capacity used over a year) of 36%. Our facilities are located in Maryland and Virginia and were acquired from Pepco in December 2000. The Chalk Point facility is our largest generation facility in the region. It consists of two coal-fired baseload units, two oil and gas-fired intermediate units and two oil-fired and five gas and oil-fired peaking units, for a total generation capacity of 2,429 MW. Our next largest facility in the region is the Morgantown facility. It consists of two dual-fueled (coal and oil) baseload units and six oil-fired peaking units, for a total generation capacity of 1,492 MW. The Dickerson facility has three coal-fired baseload units, and one oil-fired and two gas and oil-fired peaking units, for a total generation capacity of 853 MW. The Potomac River station has three coal-fired baseload units and two coal-fired intermediate units, for a total generation capacity of 482 MW.

Power generated by our facilities is sold into the PJM market. For a discussion of the PJM market, see “Regulatory Environment” below. We have participated 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 assets.

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.

On August 24, 2005, power production at all five units of the Potomac River generating facility was temporarily halted in response to a letter from the Virginia DEQ. On August 25, 2005, the District of

Columbia Public Service Commission filed an emergency petition and complaint with the FERC and the DOE to prevent the shutdown of the Potomac River facility. The matter remains pending before the FERC and the DOE. On December 20, 2005, due to a determination by the DOE that an emergency situation existed with respect to the reliability of the supply of electricity to central Washington, D.C., the DOE ordered Mirant Potomac River to generate electricity at the Potomac River generating facility, as requested by PJM, during any period in which one or both of the transmission lines serving central Washington, D.C. are out of service due to a planned or unplanned outage. In addition, the DOE ordered Mirant Potomac River, at all other times, for electric reliability purposes, to keep as many units in operation as possible and to reduce the start-up time of units not in operation without contributing to any NAAQS exceedances. The DOE required Mirant Potomac River to submit a plan that met these requirements, on or before December 30, 2005. The order further provides that Mirant Potomac River and its customers should agree to mutually satisfactory terms for any costs incurred by it under this order or just and reasonable terms shall be established by a supplemental order. Certain parties filed for rehearing of the DOE order, and on February 17, 2006, the DOE issued an order granting rehearing solely for purposes of considering further the rehearing requests. Mirant Potomac River submitted an operating plan in accordance with the order. On January 4, 2006, the DOE issued an interim response to Mirant Potomac River’s operating plan authorizing operation of the units of the Potomac River generating facility on a reduced basis, but making it possible to bring the entire plant into service within approximately 28 hours when necessary for reliability purposes. The DOE’s order expires July 1, 2007, but Mirant Potomac River expects it will be able to continue to operate these units after that expiration.

In a letter received December 30, 2005, the EPA invited Mirant Potomac River and the Virginia DEQ to work with the EPA to ensure that Mirant Potomac River’s operating plan submitted to the DOE adequately addressed NAAQS issues. The EPA also asserted in its letter that Mirant Potomac River did not immediately undertake action as directed by the Virginia DEQ’s August 19, 2005, letter and failed to comply with the requirements of the Virginia State Implementation Plan established by that letter. Mirant Potomac River received a second letter from the EPA on December 30, 2005, requiring Mirant to provide certain requested information as part of an EPA investigation to determine the Clean Air Act compliance status of the Potomac River generating facility.

On June 1, 2006, Mirant Potomac River and the EPA executed an ACO by Consent to resolve the EPA’s allegations that Mirant Potomac River violated the Clean Air Act by not immediately shutting down all units at the Potomac River facility upon receipt of the Virginia DEQ’s August 19, 2005, letter and to assure an acceptable level of reliability to the District of Columbia. The ACO (i) specifies certain operating scenarios and SO2 emissions limits for the Potomac River facility, which scenarios and limits take into account whether one or both of the 230kV transmission lines serving Washington, D.C. are out of service; (ii) requires the operation of trona injection units to reduce SO2 emissions; and (iii) requires Mirant Potomac River to undertake a model evaluation study to predict ambient air quality impacts from the facility’s operations. In accordance with the specified operating scenarios, the ACO permits the facility to operate using a daily predictive modeling protocol. This protocol allows Mirant Potomac River to schedule the facility’s level of operations based on whether computer modeling predicts an NAAQS exceedance, based on weather and certain operating parameters. On June 2, 2006, the DOE issued a letter modifying its January 6, 2006, order to direct Mirant Potomac River to comply with the ACO in order to ensure adequate electric reliability to the District of Columbia. Mirant Potomac River is operating the Potomac River facility in accordance with the ACO and has been able to operate all five units of the facility most of the time under the ACO. This ACO expires in June 2007.

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 in this website is not incorporated into this Form 10-K.

Competitive Environment

Historically, vertically integrated electric utilities with monopolistic control over franchised territories dominated the power generation industry in the United States. The enactment of the PURPA and the subsequent passage of the Energy Policy Act of 1992, fostered the growth of independent power producers. During the 1990s, a series of regulatory policies were partially implemented at both the federal and state levels to encourage competition in wholesale electricity markets.

As a result, independent power producers built new generating plants, purchased plants from regulated utilities and marketed wholesale power. ISOs and RTOs were created to administer the new markets and maintain system reliability. Beginning in 2001, however, in response to extreme price volatility and electricity shortages in California, regulators began to re-examine the nature and pace of deregulation of wholesale electricity markets and that re-examination is continuing.

Independent power producers, as well as utilities, constructed primarily natural gas-fired plants in the 1990s because natural gas prices were low and such plants could be constructed more quickly and were less expensive to permit and build than nuclear and coal-fired plants. Stagnation in the growth of natural gas supplies, the increased demand from new generation facilities and the damage caused by hurricanes Katrina and Rita resulted in a sharp increase in the price of natural gas during 2005. In 2006, there was volatility in natural gas prices, with a substantial decline from their 2005 highs. Although natural gas prices have declined from 2005, natural gas prices remain high compared to historical prices. High natural gas prices have contributed to high electricity prices.

A number of factors combined to create excess generating capacity in certain markets, including a substantial increase in construction of generation facilities following the deregulation efforts described above, capital investments by utilities aimed at extending the lives of older units and the inability to decommission certain plants for reliability reasons. In certain markets, including the area where our plants are located, that excess has been absorbed or is close to being absorbed. Electricity demand has been growing and supply has not appreciably increased. Given the substantial time necessary to permit and construct new power plants, we think that the markets in which we operate need to begin the process now of adding generating capacity to meet growing demand. A number of key ISOs have implemented capacity markets as a way to encourage such construction of additional generation, but it is not clear whether independent power producers will be sufficiently incentivized to build this 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. Coal-fired generation and nuclear generation currently account for approximately 50% and 20%, respectively, of the electricity produced in the United States. There is substantial environmental opposition to building either coal-fired or nuclear plants.

In light of the foregoing market conditions, some regulated utilities are proposing to construct coal-fired units or nuclear plants, in some cases with governmental subsidies or under legislative mandate. Unlike independent power producers like us, these utilities often are able to recover fixed costs through regulated retail rates, allowing them to build without relying on market prices to recover their investments.

Many regulated utilities are also seeking to acquire distressed assets or make substantial environmental improvements to existing coal plants, in each case with regulatory assurance that the utility will be permitted to recover its costs, plus earn a return on its investment. Success by utilities in those efforts may put independent power producers at a disadvantage because they rely heavily on market prices rather than regulatory assurances.

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 our subsidiaries that own generating facilities selling at wholesale or that market electricity at wholesale are each a “public utility” subject to the FERC’s jurisdiction under the Federal Power Act. We and each such subsidiary 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 and capacity at wholesale at market-based rates and has authorized us and some of these subsidiaries to sell certain ancillary services at wholesale at market-based rates. The majority of the output of the generation facilities owned by us and our subsidiaries that constitute public utilities 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 market. The FERC requires that we and our subsidiaries with market-based rate authority, as well as those with blanket certificate authorization permitting market-based sales of natural gas, adhere to certain market behavior rules and codes of conduct, respectively. If we or any of our subsidiaries violate the market behavior rules or codes of conduct, the FERC may require a disgorgement of profits or revoke our or our subsidiary’s market-based rate authority or blanket certificate authority. If the FERC were to revoke market-based rate authority, we or our subsidiary would have to file a cost-based rate schedule for all or some of our or its sales of electricity at wholesale. If the FERC revoked the blanket certificate authority of our subsidiary, certain sales of natural gas would be prohibited.

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

State and local regulatory authorities have historically overseen the distribution and sale of electricity at retail to the ultimate end user, as well as the siting, permitting and construction of generating and transmission facilities. Our existing generation may be subject to a variety of state and local regulations, including regulations regarding the environment, health and safety, maintenance and expansion of generation facilities. To the extent that a subsidiary sells electricity at retail in a state with a retail access program, it may be subject to state certification requirements and to bidding rules that provide default service to customers who choose to remain with their regulated utility distribution companies.

We sell power 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 generators. PJM administers day-ahead and real-time marginal cost 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 cheaper power 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 capacity. PJM operates a capacity market whereby load-serving entities can procure their capacity requirements through a system-wide single clearing price auction. In PJM, all capacity is assumed to be universally deliverable, regardless of its location. PJM has greatly expanded its system to include Allegheny Power, Commonwealth Edison,

AEP, DP&L and Dominion-Virginia Power. As a result, capacity prices have significantly declined. The PJM expansions have resulted in an apparent system-wide surplus of capacity, despite the fact that certain regions in PJM-Mid-Atlantic are currently in need of capacity additions.

On December 22, 2006, the FERC approved, with conditions, a settlement between PJM and multiple market participants regarding PJM’s RPM, which was originally filed with the FERC on August 31, 2005, to replace the existing system-wide single clearing price capacity market. The RPM settlement is intended to ensure reliability and reasonable rates in the PJM region. The RPM settlement provides for a three-year forward capacity auction using a modified demand curve from the original RPM filing and locational deliverability zones that will be phased in over several years. Demand curves are administrative mechanisms used to establish electricity generation capacity prices. The RPM settlement will provide increased opportunities for our power plants to receive more revenues for their capacity. The order approving the RPM is subject to rehearing and a motion to vacate. Parties opposed to the RPM settlement have filed requests with the FERC to rehear, vacate or stay the effectiveness of the December 22, 2006, order, which are currently pending before the FERC.

In addition, PJM and the MISO have been directed by the FERC to establish a common and seamless market, an effort that is largely dependent upon the MISO’s ability to first establish and operate its markets. 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. This requires us to comply with applicable laws and regulations, and to obtain and comply with the terms of government issued permits. Our costs of complying with environmental laws, regulations and permits are substantial. We expect that cash flows from operations and from the preferred shares in Mirant Americas will be sufficient to fund these capital expenditures.

Maryland Healthy Air Act. 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 plants. We will install flue gas desulphurization (“FGD”) emissions controls at our Chalk Point, Dickerson and Morgantown plants. In addition, we will install selective catalytic reduction (“SCR”) systems at the Morgantown (as contemplated by the pending NOx Consent Decree described in “Item 3. Legal Proceedings, Environmental Matters”) and Chalk Point facilities that will reduce NOx emissions by approximately 80%. Together, the FGDs and the SCRs will reduce by approximately 80% the emissions of ionic mercury from the three Maryland power plants.

The Maryland Healthy Air Act requires deeper reductions in NOx and SO2 in 2010 and 2015 than reductions required under federal law including the CAIR. As a result of passage of the more restrictive Maryland state standard on NOx and SO2 emissions, our plan to install control equipment will allow the Maryland facilities to meet or exceed the CAIR limits. We anticipate that the capital expenditures to achieve compliance for SO2 and NOx emissions will be approximately $1.6 billion through 2009. The Maryland Healthy Air Act also requires reductions of mercury emissions by the year 2010. As a result of our installation of equipment to satisfy the more restrictive Maryland state standard on mercury emissions, our facilities will also meet or exceed the CAMR limits. The state law also requires Maryland to join the Regional Greenhouse Gas Initiative (“RGGI”), a seven state plan to reduce CO2 emissions by 2018. The State of Maryland will initiate a rule-making proceeding in 2007 to determine the regulatory framework for RGGI participation.

At the federal level, there are efforts to pass legislation to mandate reductions of CO2 emissions from generation facilities. There are several pieces of legislation being advanced that vary in levels of reductions and mechanisms for compliance.

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. 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, our operations are subject to more stringent air pollution requirements, including, in some cases, further emissions reductions. In the future, we anticipate increased regulation of generation facilities under the Clean Air Act and applicable state laws and regulations concerning air quality. Significant air regulatory programs to which we are subject include those described below.

Clean Air Interstate Rule (CAIR). In May 2005, the EPA promulgated the CAIR regulations, which established in the eastern United States an SO2 and NOx cap-and-allowance trading program applicable to generation facilities. These cap-and-trade programs will be implemented in two phases, with the first phase going into effect in 2010 and more stringent caps going into effect in 2015. In order to comply with the first phase of those regulations, we will have to install additional pollution control equipment and/or purchase additional emissions allowances, at significant cost. We are planning to install pollution control equipment at some of our facilities to address, in part, our requirements under the first phase of the CAIR. The costs of that equipment are included in our estimate of anticipated environmental capital expenditures from 2007 through 2010. However, since the determination of how much pollution control equipment to install is based upon factors such as the cost of emissions allowances and the operational demands on our generation facilities, our plans may change significantly. For our Maryland facilities, compliance with the Maryland Healthy Air Act meets or exceeds the requirements under CAIR.

Clean Air Mercury Rule (CAMR). In May 2005, the EPA issued the CAMR, which limits total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program. The first phase begins in 2010 and the second phase begins in 2018. The EPA expects that, in the first stage, the necessary reductions in mercury will be achieved as a co-benefit using the same pollution control equipment required to achieve the reductions of SO2 and NOx under the CAIR. All states are required to adopt either the EPA rule or a state rule meeting the minimum requirements outlined in the CAMR. Under the EPA rule, we will receive an allocation of mercury emissions allowances associated with our coal-fired plants nationwide, unless there are restrictions imposed at the state level. We expect our coal-fired facilities to comply with the CAMR regulations by taking advantage of the co-benefits derived from NOx and SO2 controls that are, or will soon be, installed.

NSR enforcement initiative. In 1999, the DOJ, on behalf of the EPA, commenced enforcement actions against a number of companies in the power generation industry for alleged violations of the NSR regulations, which require permitting and impose other requirements for certain maintenance, repairs and replacement work on facilities. These enforcement actions can result in a facility owner having obligations to, among other things, install emissions controls at significant cost. These enforcement actions were broadly challenged by the industry in the courts, among other reasons for being a new interpretation of longstanding regulations. In an effort to provide additional clarity, it is expected that in 2007 the Bush administration will adopt new air pollution rules to clarify what constitutes an emissions increase under the NSR program.

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 or our subsidiaries’ acquisition or lease of the plants.

If a violation is determined to have occurred at any of the plants, we and our subsidiary owning or leasing the plant may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. We and our subsidiaries will be installing a variety of emissions control equipment on the Chalk Point, Dickerson and Morgantown plants in Maryland to comply with the Maryland Healthy Air Act, but that equipment may not include all of the emissions control equipment that would be required if a violation of the EPA’s NSR regulations is determined to have occurred at one or more of those plants. If such a violation is determined to have occurred after we and our subsidiaries acquired or leased the plants or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, we and our subsidiary owning or leasing the plant at issue could also be subject to fines and penalties by the state or federal government for the period after our or its acquisition or lease of the plant, 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.

Virginia CAIR and CAMR Implementation. In April 2006, Virginia enacted the Clean Smokestacks Law, which granted the Virginia State Air Pollution Control Board the discretion to limit the ability of a facility in a non-attainment area to purchase additional mercury, SO2 and NOx allowances to achieve compliance with CAIR and CAMR. The State Air Pollution Control Board has approved the implementing regulations to the Clean Smokestacks Law but they have not yet been promulgated. The State Air Pollution Control Board has interpreted the current form of these regulations as restricting facilities in non-attainment areas from purchasing emission allowances to achieve compliance with CAIR and CAMR. If the regulations are promulgated in their current form and the State Air Pollution Control Board’s interpretation is correct, such restrictions would reduce our flexibility in complying with CAIR and CAMR and could result in operating restrictions for our Potomac River generating facility in Virginia.

Climate change. Concern over climate change has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.

In 1998, the United States became a signatory to the Kyoto Protocol of the United Nations Framework Convention on Climate Change. The Kyoto Protocol, which became effective in February 2005 after Russia’s ratification in November 2004, calls for developed nations to reduce their emissions of greenhouse gases to 5% below 1990 levels by 2012. CO2, which is a major byproduct of the combustion of fossil fuel, is a greenhouse gas that would be regulated under the Kyoto Protocol. The United States Senate indicated that it would not enact the Kyoto Protocol, and in 2002 President Bush confirmed that the United States would not enter into the Kyoto Protocol. Instead, the President indicated that the United States would support voluntary measures for reducing greenhouse gases and technologies that would use or dispose of CO2 effectively and economically. As the Kyoto Protocol becomes effective in other countries, there is increasing pressure for sources in the United States to be subject to mandatory restrictions on CO2 emissions. In the last year, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions, but such bills have not received sufficient Congressional approval to date to become law. If the United States ultimately ratifies the Kyoto Protocol and/or if the United States Congress or individual states or groups of states in which we operate ultimately pass legislation regulating the emissions of greenhouse gases such as the RGGI discussed below, any resulting limitations on generation facility CO2 emissions could have a material adverse impact on all fossil fuel-fired generation facilities (particularly coal-fired facilities), including ours.

On August 16, 2006, a model rule was finalized and seven states in the Northeast will move forward with the implementation of the RGGI. This is a multi-state regional initiative that uses a regional cap and trade program to reduce CO2 emissions from power plants of 25 MW or greater. The program aims to stabilize CO2 emissions to current levels from 2009 to 2015. This is to be followed by a 10% reduction in emissions by 2019. At this time, our assets in Maryland will be affected, and we are evaluating our options to comply with the requirements of the rule.

At the federal level Congress is expected to advance several mandatory CO2 bills which may require reductions of CO2 emissions nationwide.

Water regulations. We are required under the Clean Water Act to comply with effluent and intake requirements, technological controls requirements and operating practices. Our wastewater discharges are subject to permitting under the Clean Water Act, and our permits under the Clean Water Act are subject to review every five years. As with air quality regulations, federal and state water regulations are expected to increase and impose additional and more stringent requirements or limitations in the future. This is particularly true for regulatory requirements governing cooling water intake structures, which are subject to regulation under section 316(b) of the Clean Water Act. A recent decision by the United States Court of Appeals for the Second Circuit in Riverkeeper Inc. et al v. EPA, in which the court remanded numerous provisions of the EPA’s current 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. Until the EPA acts on the issues remanded, it is impossible to say exactly what requirements will be imposed or what they will cost.

Wastes, hazardous materials and contamination. Our facilities are subject to several waste management laws and regulations. The Resource Conservation and Recovery Act of 1976 set forth 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 from these facilities. The EPA 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.

Additionally, CERCLA, or Superfund, establishes a framework for dealing with the cleanup of contaminated sites. Many states have enacted similar state superfund statutes as well as other laws imposing obligations to investigate and clean up contamination.

Employees

Under our services agreement with Mirant Services, a direct subsidiary of Mirant, Mirant Services provides the personnel who operate our facilities. At December 31, 2006, approximately 709 Mirant Services employees worked at our facilities, of whom approximately 642 were employed by Mirant Services at our power plants.

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 482 employees. This agreement was reached in October 2004 and extends until June 2010.

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, and formerly to Mirant Americas Energy Marketing, 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. The prices for wholesale electric capacity, energy and energy services in the PJM market are largely based on prevailing market forces, subject to regulatory caps, and, therefore we are not guaranteed any return on our capital investments through mandated rates. The price for which we can sell our output may fluctuate on a day-to-day basis. However, rules regarding such things as price and bid caps restrict the absolute movement of prices, different from what would occur in a truly deregulated market. Among the factors that will influence the PJM market prices, all of which are beyond our control, are:

· the failure of market regulators to develop 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 sufficient for recovery of our costs, our investment and an adequate return on our investment;

· 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, refusal by regulators to allow utilities to fully recover their wholesale power costs and investments through rates, catastrophic losses, and losses from investments 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 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;

· 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 or increase the supply of hydro power; and

· changes in the rate of growth in electricity usage as a result of such factors as 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, and we may be unsuccessful at managing this risk.

Our generation business is subject to changes in power prices and fuel costs, which 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. In addition, actual power prices and fuel costs may differ from our expectations.

We engage in price risk management activities related to sales of electricity and purchases of fuel and we receive income and incur losses from these activities. We may use forward contracts and derivative financial instruments, such as futures contracts and options, to manage market risk and exposure to volatility in electricity, coal, natural gas, emissions and oil prices. 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 and fuel markets.

Many factors influence commodity prices, including weather, market liquidity, transmission and transportation inefficiencies, availability of competitively priced alternative energy sources, demand for energy commodities, natural gas, crude oil and coal production, natural disasters, wars, embargoes and other catastrophic events, and federal and state environmental regulation and legislation.

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. As a result of these and other factors, we cannot predict the impact 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 natural gas, coal and oil fuel supply.

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.

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

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

· the output and efficiency levels at which those generation 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 asset management activities may increase the volatility of our quarterly and annual financial results.

We engage in asset management activities to economically hedge our exposure to market risk with respect to: (1) electricity sales from our generation 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 No. 133. None of our derivatives recorded at fair market value are designated as hedges under SFAS No. 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 5 to our consolidated and combined financial statements, included herein.

Our 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 corresponding energy and fuel prices; and

· variations in levels of production.

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 generation 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. In addition, we may be required to shut down facilities if we are unable to comply with the requirements, such as with CO2 regulations for which there currently is not a technical compliance solution, or if we determine the expenditures required to comply are uneconomic.

In addition, environmental laws, particularly with respect to air emissions, wastewater discharge and cooling water intake structures, are generally becoming more stringent, which may require us to make expensive facility upgrades or restrict our operations to meet more stringent standards. 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 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 recently finalized CAIR and CAMR. This legislation affects our Chalk Point, Dickerson and Morgantown facilities. We anticipate that the capital expenditures to achieve compliance for SO2 and NOx emissions will be approximately $1.6 billion through 2009.

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 any environmental regulatory approvals or if onerous conditions are imposed, the operation of our generation 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.

Certain environmental laws, including CERCLA and comparable state laws, impose strict and, in many circumstances, joint and several liability for costs of contamination in soil, groundwater and elsewhere. Releases of hazardous substances at our generation 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 generation facilities, at disposal sites we currently utilize or have formerly utilized, 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 additional emissions allowances to meet the mandated levels. To meet these requirements, we plan to install scrubbers on all of our Maryland coal facilities. We may not meet this construction schedule by January 2010 due to a number of factors, which may 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 generation facilities may negatively affect our cash flows.

We expect that certain of our generation 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 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.

Generally, 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 generation 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 generation 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 assets are subject to rules and terms of participation imposed and administered by PJM. While PJM is itself 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.

Changes in the markets in which we compete may have an adverse impact on the results of our operations. For example, in the fall of 2004, PJM completed its integration of AEP, Duquesne Light and DP&L into PJM. Under PJM rules, AEP, Duquesne Light and DP&L were then deemed by PJM to be capable of providing capacity to all areas of PJM. The integration of these companies into PJM in conjunction with the existing market rules depressed the prices that can be charged for capacity in PJM.

To conduct our business, we must obtain 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 generation technologies, which will subsidize certain of our competitors. Many 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 suffer. We cannot provide assurance that the introductions of new laws, or other future regulatory developments, will not have a material adverse impact on our business, operations or financial condition.

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

A basic premise of our generation business is that generating power at central facilities achieves economies of scale and produces electricity at a low price. There are other technologies that can produce electricity, most notably fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technology will reduce the cost of alternative methods of electricity production to levels that are equal to or below that of most central station electric production, which could have a material impact 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 generation 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 meet our obligations, our ability to raise capital and our future growth opportunities.

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

Our operations are subject to many hazards associated with the power generation 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 may be subject to claims that were not discharged in the bankruptcy cases, which could have a material adverse effect on our results of operations and profitability.

The nature of our business frequently subjects us to litigation. Substantially all of the material claims against us that arose prior to the bankruptcy filing in July 2003 were resolved during our Chapter 11 proceedings. In addition, the Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation and certain debts arising afterwards. With a few exceptions, all claims that arose prior to our bankruptcy filing and before confirmation of the Plan in December 2005 are (1) subject to compromise and/or treatment under the Plan or (2) discharged, in accordance with the Bankruptcy Code and terms of the Plan. Circumstances in which claims and other obligations that arose prior to our bankruptcy filing were not discharged primarily relate to certain actions by governmental units under police power authority, where we have agreed to preserve a claimant’s claims, as well as, potentially, instances where a claimant had inadequate notice of the bankruptcy filing. The ultimate resolution of such claims and other obligations may have a material adverse effect on our results of operations and profitability.

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 vigorously defend against those claims that we are unable to settle, but the results of this litigation cannot be determined. Adverse outcomes for us in this litigation could require significant expenditures by us and could have a material adverse effect on our results of operations and profitability.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The following properties were owned or leased as of December 31, 2006:

	Location	Primary Fuel	Leasehold and Ownership Percentage Interest			Total MW Owned, Operated and/or Leased(1)		2006 Capacity Factor
Owned facilities:
Morgantown CT, Units 1-6	Maryland	Oil		100	%		248		2	%
Dickerson CT, Units 1-3	Maryland	Oil/Gas		100			307		3
Chalk Point, Units 1-4	Maryland	Coal/Oil/Gas		100			1,907		28
Chalk Point CT, Units 1-6.	Maryland	Gas/Oil		100			438		2
Potomac River, Units 1-5	Virginia	Coal/Oil		100			482		26
Leased facilities:
Morgantown, Units 1-2	Maryland	Coal/Oil		100			1,244		70
Dickerson, Units 1-3	Maryland	Coal		100			546		64
Chalk Point, CT Unit 7	Maryland	Gas/Oil		100			84		1
Total							5,256		36	%

(1) MW amounts reflect net dependable capacity.

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

Item 3. Legal Proceedings

Chapter 11 Proceedings

On July 14, 2003, and various dates thereafter, Mirant Corporation and certain of its subsidiaries (collectively, the “Mirant Debtors”), including us and our subsidiaries, filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Most of the material claims filed against the Mirant Debtors’ estates were disallowed or were resolved and became “allowed” claims before confirmation of the Plan that became effective for Mirant, us and most of the Mirant Debtors on January 3, 2006. Mirant, as the distribution agent under the Plan, has made distributions pursuant to the terms of the Plan on those allowed claims. Some claims, however, remain unresolved.

As of December 31, 2006, approximately 21 million of the shares of Mirant common stock to be distributed under the Plan have not yet been distributed and have been reserved for distribution with respect to claims that are disputed by the Mirant Debtors and have not been resolved. A settlement entered into on May 30, 2006, among Pepco, Mirant, MC 2005, LLC f/k/a Mirant Corporation (“Old Mirant”), and various subsidiaries of Mirant, including us and our subsidiaries, if approved by final order in the Chapter 11 proceedings, would result in the distribution of up to 18 million of the reserved shares to Pepco, as described below in Pepco Litigation. Under the terms of the Plan, to the extent other such unresolved claims are resolved now that we have emerged from bankruptcy, the claimants will be paid from the reserved shares on the same basis as if they had been paid when the Plan became effective. That means that their allowed claims will receive the same pro rata distributions of Mirant common stock, cash, or both common stock and cash as previously allowed claims in accordance with the terms of the Plan. To the extent the aggregate amount of the payouts determined to be due with respect to such 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 shareholders, 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.

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 a contractual agreement (the “Back-to-Back Agreement”) with respect to certain PPAs, including Pepco’s long-term PPA with Panda, 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 Panda PPA runs until 2021, and the Back-to-Back Agreement does not expire until all obligations have been performed under the Panda PPA. Under the Back-to-Back Agreement, Mirant is obligated to purchase power from Pepco at prices that typically are 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 includes as parties Pepco, us and various of our subsidiaries causes us and our subsidiaries that are 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 have sought to reject the APSA, the Back-to-Back Agreement, and the Assignment and Assumption Agreement, and the rejection motions have not been resolved. 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 are to be performed by Mirant Power Purchase, whose performance is guaranteed by Mirant. If any of the agreements is successfully rejected, the obligations of Mirant Power Purchase and Mirant’s guarantee obligations terminate with respect to that agreement, and Pepco would be entitled to a claim in the Chapter 11 proceedings for any resulting damages. That claim would then be addressed under the terms of the Plan. If the Bankruptcy Court were to conclude that the Assignment and Assumption Agreement imposed liability upon us and our subsidiaries for the obligations under the Back-to-Back Agreement and the Back-to-Back Agreement were to be rejected, the resulting rejection damages claim could result in a claim in the Chapter 11 proceedings against us and our subsidiaries but any such claim would be reduced by the amount recovered by Pepco on its comparable claim against Mirant.

On May 30, 2006, Mirant, Mirant Power Purchase, Old Mirant, various subsidiaries of Mirant (including us and our subsidiaries), and a trust established pursuant to the Plan to which ownership of Old Mirant and Mirant Americas Energy Marketing was transferred (collectively the “Mirant Settling Parties”) entered into a Settlement Agreement and Release (the “Settlement Agreement”) with Pepco and various affiliates of Pepco (collectively the “Pepco Settling Parties”). Once it becomes effective, the Settlement Agreement will fully resolve the contract rejection motions that remain pending in the bankruptcy proceedings, as well as other matters currently disputed between Pepco and Mirant and its subsidiaries. The Pepco Settling Parties and the Mirant Settling Parties will release each other from all claims known as of May 30, 2006, including the fraudulent transfer claims brought by Old Mirant and several of its subsidiaries against Pepco in July 2005. The Settlement Agreement will become effective once it has been approved by the Bankruptcy Court and that approval order has become a final order no longer subject to appeal. On August 9, 2006, the Bankruptcy Court entered an order approving the Settlement Agreement, but certain holders of unsecured claims against Old Mirant in the bankruptcy proceedings appealed that order. On December 26, 2006, the United States District Court for the Northern District of Texas affirmed the bankruptcy court order approving the settlement, but the claims holders have appealed that ruling to the United States Court of Appeals for the Fifth Circuit, and the approval order has not yet become a final order.

Under the Settlement Agreement, Mirant Power Purchase will perform any remaining obligations under the APSA, and Mirant will guaranty its performance. The Back-to-Back Agreement will be rejected and terminated effective as of May 31, 2006, unless Mirant exercises an option given to it under the Settlement Agreement to have the Back-to-Back Agreement assumed under certain conditions. If the closing price of Mirant’s stock is less than $16.00 on four business days in a 20 consecutive business day period prior to any distribution of shares to Pepco on its claim, then Mirant can elect to have the Back-to-Back Agreement assumed and assigned to Mirant Power Purchase rather than rejecting it, and the claim received by Pepco will be reduced as described below.

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 us and our subsidiaries, the Mirant subsidiary that is a party to each agreement will assume the agreement and Mirant will guaranty that subsidiary’s performance. Mirant Power Purchase’s obligations under the APSA do not include any obligations related to the Ancillary Agreements. If the Back-to-Back Agreement is rejected pursuant to the terms of the Settlement Agreement, 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. If, however, Mirant elects to have the Back-to-Back Agreement assumed and assigned to Mirant Power Purchase under the conditions set out in the Settlement Agreement, then the Settlement Agreement provides that nothing in its terms prejudices the argument currently being made by Pepco in the contract rejection proceedings that the APSA, the Back-to-Back Agreement, and the Ancillary Agreements constitute a single non-severable agreement, the material breach of which would entitle Pepco to suspend or terminate its performance thereunder, or any defense of Mirant and its subsidiaries to such an argument by Pepco.

The Settlement Agreement grants Pepco a claim against Old Mirant in Old Mirant’s bankruptcy proceedings that will result in Pepco receiving common stock of Mirant and cash having a value, after liquidation of the stock by Pepco, equal to $520 million, subject to certain adjustments. Upon the Settlement Agreement becoming effective, Mirant will distribute up to 18 million shares of Mirant common stock to Pepco to satisfy its claim and Pepco will liquidate those shares. The shares to be distributed to Pepco will be determined by Mirant after the Settlement Agreement becomes effective so as to produce upon liquidation total net proceeds as near to $520 million as possible, subject to the overall cap on the shares to be distributed of 18 million shares. If the net proceeds received by Pepco from the liquidation of the shares are less than $520 million, Mirant will pay Pepco cash equal to the difference. If Mirant exercises the option to have the Back-to-Back Agreement assumed, then the $520 million is reduced to $70 million, Mirant Power Purchase would continue to perform the Back-to-Back Agreement through its expiration in 2021, and Mirant would guarantee its performance. The Settlement Agreement allocates the $70 million to various claims asserted by Pepco that do not arise from the rejection of the Back-to-Back Agreement, including claims asserted under the Local Area Support Agreement between Pepco and Mirant Potomac River that are discussed below in Pepco Assertion of Breach of Local Area Support Agreement.

Environmental Matters

violation is determined to have occurred at any of the plants, we or our subsidiary owning or leasing the plant may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. We or our subsidiaries will be installing a variety of emissions control equipment on the Chalk Point, Dickerson and Morgantown plants in Maryland to comply with the Maryland Healthy Air Act, but that equipment may not include all of the emissions control equipment that could be required if a violation of the EPA’s NSR regulations is determined to have occurred at one or more of those plants. If such a violation is determined to have occurred after we or our subsidiaries acquired or leased the plants or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, we or our subsidiary owning or leasing the plant at issue could also be subject to fines and penalties by the state or federal government for the period after our or its acquisition or lease of the plant, 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 plants.

Mirant Potomac River Notice of Violation. On September 10, 2003, the Virginia DEQ issued an NOV to Mirant Potomac River alleging that it violated its Virginia Stationary Source Permit to Operate by emitting NOx in excess of the “cap” established by the permit for the 2003 summer ozone season. Mirant Potomac River responded to the NOV, asserting that the cap was unenforceable, noting that when the cap was made part of the permit it could comply through the purchase of emissions allowances and raising other equitable defenses. Virginia’s civil enforcement statute provides for injunctive relief and penalties. On January 22, 2004, the EPA issued an NOV to Mirant Potomac River alleging the same violation of its Virginia Stationary Source Permit to Operate as set out in the NOV issued by the Virginia DEQ.

On September 27, 2004, we, Mirant Potomac River, the Virginia DEQ, the MDE, the DOJ and the EPA entered into, and filed for approval with the United States District Court for the Eastern District of Virginia, a proposed consent decree (the “Original Consent Decree”) that, if approved, would have resolved Mirant Potomac River’s potential liability for matters addressed in the NOVs previously issued by the Virginia DEQ and the EPA. The Original Consent Decree would have required Mirant Potomac River and us to (1) install pollution control equipment at the Potomac River plant in Virginia and at the Morgantown plant in Maryland leased by us, (2) comply with declining system-wide ozone season NOx emissions caps from 2004 through 2010, (3) comply with system-wide annual NOx emissions caps starting in 2004, (4) meet seasonal system average emissions rate targets in 2008 and (5) pay civil penalties and perform supplemental environmental projects in and around the Potomac River plant expected to achieve additional environmental benefits. Except for the installation of the controls planned for the Potomac River units and the installation of selective catalytic reduction (“SCR”) or equivalent technology at our Morgantown units 1 and 2 in 2007 and 2008, the Original Consent Decree would not have obligated us to install specifically designated technology, but rather to reduce emissions sufficiently to meet the various NOx caps. Moreover, as to the required installations of SCRs at Morgantown, we may choose not to install the technology by the applicable deadlines and leave the units off either permanently or until such time as the SCRs are installed. The Original Consent Decree was subject to the approval of the district court and the Bankruptcy Court. As described below, the Original Consent Decree was not approved and the parties have filed an amended proposed consent decree that supersedes the Original Consent Decree.

On July 22, 2005, the district court granted a motion filed by the City of Alexandria seeking to intervene in the district court action, although the district court imposed certain limitations on the City of Alexandria’s participation in the proceedings. On September 23, 2005, the City of Alexandria filed a motion seeking authority to file an amended complaint in the action seeking injunctive relief and civil penalties under the Clean Air Act for alleged violations by Mirant Potomac River of its Virginia Stationary Source Permit to Operate and the State of Virginia’s State Implementation Plan. Based upon a computer modeling described below in Mirant Potomac River Downwash Study, the City of Alexandria asserted that emissions from the Potomac River plant cause or contribute to exceedances of NAAQS for SO2, NO2 and particulate matter. The City of Alexandria also contended based on its modeling analysis that the plant’s

emissions of hydrogen chloride and hydrogen fluoride exceed Virginia state standards. Mirant Potomac River disputes the City of Alexandria’s allegations that it has violated the Clean Air Act and Virginia law. On December 2, 2005, the district court denied the City of Alexandria’s motion seeking to file an amended complaint.

In early May 2006, the parties to the Original Consent Decree and Mirant Chalk Point entered into and filed for approval with the United States District Court for the Eastern District of Virginia an amended consent decree (the “Amended Consent Decree”) that, if approved, will resolve Mirant Potomac River’s potential liability for matters addressed in the NOVs previously issued by the Virginia DEQ and the EPA. The Amended Consent Decree includes the requirements that were to be imposed under the terms of the Original Consent Decree as described above. It also defines the rights and remedies of the parties in the event of a rejection in bankruptcy or other termination of any of the long-term leases under which we lease the coal units at the Dickerson and Morgantown plants. The Amended Consent Decree provides that if we reject or otherwise lose one or more of our leasehold interests in the Morgantown and Dickerson plants and cease to operate one or both of the plants, we, Mirant Chalk Point and/or Mirant Potomac will (i) provide the EPA, Virginia DEQ and the MDE with the written agreement of the new owner or operator of the affected plant or plants to be bound by the obligations of the Amended Consent Decree and (ii) where the affected plant is the Morgantown plant, offer to any and all prospective owners and/or operators of the Morgantown plant to pay for completion of engineering, construction and installation of the SCRs required by the Amended Consent Decree. If the new owner or operator of the affected plant or plants does not agree to be bound by the obligations of the Amended Consent Decree, it requires us, Mirant Chalk Point and/or Mirant Potomac to install an alternative suite of environmental controls at the plants we or they continue to own. The district court and the Bankruptcy Court must approve the Amended Consent Decree for it to become effective. The City of Alexandria and certain individuals and organizations have opposed entry of the Amended Consent Order. The Bankruptcy Court approved the Amended Consent Decree on June 1, 2006. The district court has not yet approved the Amended Consent Decree.

On April 26, 2006, we and the MDE entered into an agreement to allow us to implement the consent decree with respect to the Morgantown plant, if the consent decree receives the necessary approvals. Under the agreement, we agreed to certain ammonia and particulate matter emissions limits and to submit testing results to the MDE.

Mirant Potomac River Downwash Study. On September 23, 2004, the Virginia DEQ and Mirant Potomac River entered into an order by consent with respect to the Potomac River plant under which Mirant Potomac River agreed to perform a modeling analysis to assess the potential effect of “downwash” from the plant (1) on ambient concentrations of SO2, NO2, CO and PM10 for comparison to the applicable NAAQS and (2) on ambient concentrations of mercury for comparison to Virginia Standards of Performance for Toxic Pollutants. Downwash is the effect that occurs when aerodynamic turbulence induced by nearby structures causes emissions from an elevated source, such as a smokestack, to move rapidly toward the ground resulting in higher ground-level concentrations of emissions.

respect to the reliability of the supply of electricity to central Washington, D.C., the DOE ordered Mirant Potomac River to generate electricity at the Potomac River generating facility, as requested by PJM, during any period in which one or both of the transmission lines serving the central Washington, D.C. area are out of service due to a planned or unplanned outage. In addition, the DOE ordered Mirant Potomac River, at all other times, for electric reliability purposes, to keep as many units in operation as possible and to reduce the start-up time of units not in operation without contributing to any NAAQS exceedances. The DOE required Mirant Potomac River to submit a plan, on or before December 30, 2005, that met these requirements. The order further provides that Mirant Potomac River and its customers should agree to mutually satisfactory terms for any costs incurred by it under this order or just and reasonable terms shall be established by a supplemental order. Certain parties filed for rehearing of the DOE order, and on February 17, 2006, the DOE issued an order granting rehearing solely for purposes of considering further the rehearing requests. Mirant Potomac River submitted an operating plan in accordance with the order. On January 4, 2006, the DOE issued an interim response to Mirant Potomac River’s operating plan authorizing operation of the units of the Potomac River generating facility on a reduced basis, but making it possible to bring the entire plant into service within approximately 28 hours when necessary for reliability purposes. The DOE’s order expires July 1, 2007, but Mirant Potomac River expects it will be able to continue to operate these units after that expiration.

On June 1, 2006, Mirant Potomac River and the EPA executed an ACO by Consent to resolve the EPA’s allegations that Mirant Potomac River violated the Clean Air Act by not immediately shutting down all units at the Potomac River facility upon receipt of the Virginia DEQ’s August 19, 2005, letter and to assure an acceptable level of reliability to the District of Columbia. The ACO (i) specifies certain operating scenarios and SO2 emissions limits for the Potomac River facility, which scenarios and limits take into account whether one or both of the 230kV transmission lines serving Washington, D.C. are out of service; (ii) requires the operation of trona injection units to reduce SO2 emissions; and (iii) requires Mirant Potomac River to undertake a model evaluation study to predict ambient air quality impacts from the facility’s operations. In accordance with the specified operating scenarios, the ACO permits the facility to operate using a daily predictive modeling protocol. This protocol allows Mirant Potomac River to schedule the facility’s level of operations based on whether computer modeling predicts a NAAQS exceedance, based on weather and certain operating parameters. On June 2, 2006, the DOE issued a letter modifying its January 6, 2006, order to direct Mirant Potomac River to comply with the ACO in order to ensure adequate electric reliability to the District of Columbia. Mirant Potomac River is operating the Potomac River facility in accordance with the ACO and has been able to operate all five units of the facility most of the time under the ACO. This ACO expires in June 2007.

City of Alexandria Nuisance Suit. On October 7, 2005, the City of Alexandria filed a suit against Mirant Potomac River and us in the Circuit Court for the City of Alexandria. The suit asserted nuisance claims, alleging that the Potomac River plant’s emissions of coal dust, flyash, NOx, SO2, particulate matter, hydrogen chloride, hydrogen fluoride, mercury and oil pose a health risk to the surrounding community and harm property owned by the City. The City sought injunctive relief, damages and attorneys’ fees. On February 17, 2006, the City amended its complaint to add additional allegations in support of its nuisance claims relating to noise and lighting, interruption of traffic flow by trains delivering coal to the Potomac

River plant, particulate matter from the transport and storage of coal and flyash, and potential coal leachate into the soil and groundwater from the coal pile. On December 13, 2006, the City withdrew the suit.

Suit Regarding Chalk Point Emissions. By letter dated June 15, 2006, four environmental advocacy organizations—Environmental Integrity Project, Chesapeake Climate Action Network, Patuxent Riverkeeper and Environment Maryland Research and Policy Center—notified Mirant and us that they intended to file suit alleging that Mirant Chalk Point had violated the opacity limits set by the permits for Chalk Point unit 3 and unit 4 during thousands of six minute time intervals between January 2002 and March 2006. The letter indicated that the organizations intend to file suit to enjoin the violations alleged, to obtain civil penalties for past noncompliance to the extent that liability for these violations was not discharged by the bankruptcy of Mirant Chalk Point, and to recover attorneys’ fees. On August 3, 2006, we, Mirant, and Mirant Chalk Point filed a complaint in the Bankruptcy Court seeking an injunction barring the four organizations from filing suit as threatened in the June 15, 2006, notice on the grounds that the notice and any claim for civil penalties or other monetary relief for alleged violations occurring before January 3, 2006, violated the discharge of claims and causes of action granted Mirant Chalk Point under the Plan. On August 14, 2006, the Bankruptcy Court entered an order agreed to by the parties enjoining the four organizations from seeking monetary damages for any alleged violations occurring on or before January 3, 2006. As part of that order, the organizations agreed not to file a complaint initiating litigation concerning the alleged violations until August 30, 2006.

On August 29, 2006, MDE filed a complaint against Mirant Chalk Point in the Circuit Court for Prince George’s County, Maryland, based upon the alleged violations of the opacity limits applicable to Chalk Point units 3 and 4 that were the focus of the June 15, 2006, notice letter from the environmental organizations and seeking civil penalties, injunctive relief and costs. Simultaneously with the filing of the complaint, Mirant Chalk Point and the MDE filed a proposed Consent Decree to resolve the issues raised by the Complaint. That Consent Decree was approved by the Maryland court on September 11, 2006. The Consent Decree subjects Chalk Point unit 3 to more stringent opacity and particulate standards and requires it when burning fuel oil to use fuel oil with a lower sulfur content than previously allowed under its permits. Mirant Chalk Point agreed in the Consent Decree to burn natural gas in Chalk Point units 3 and 4 for 95% of their heat input during certain months, subject to certain exceptions.

On August 30, 2006, the four environmental organizations filed suit in the United States District Court for the District of Maryland against Mirant, us, and Mirant Chalk Point asserting that emissions from Chalk Point units 3 and 4 had violated opacity limits set under the Clean Air Act and state law on numerous occasions since January 4, 2006. The plaintiffs sought an injunction prohibiting further violations by Chalk Point units 3 and 4 of the Clean Air Act, civil penalties of up to $32,500 for each violation of the Clean Air Act, additional civil penalties for mitigation projects, and attorneys’ fees. On September 22, 2006, the Mirant defendants filed a motion to dismiss, arguing that under the Clean Air Act the MDE’s prosecution of the same alleged violations in the Maryland state court proceeding and their resolution through the Consent Decree barred the plaintiffs’ suit. On January 3, 2007, the district court granted the motion and dismissed the complaint, and that order has become final.

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

Morgantown SO2 Exceedances. Mirant Mid-Atlantic received an NOV dated March 8, 2006, asserting that on three days in June 2005 and January 2006, the Morgantown facility exceeded SO2

emissions limitations specified in its air permit. The NOV indicates that on two of those days the SO2 emissions limitation was exceeded by two different units of the Morgantown facility each day. The NOV did not seek a specific penalty amount but noted that the violations identified could subject Mirant Mid-Atlantic to a civil penalty of up to $25,000 per day.

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

City of Alexandria Zoning Action

On December 18, 2004, the City Council for the City of Alexandria, Virginia (the “City Council”) adopted certain zoning ordinance amendments recommended by the City Planning Commission that resulted in the zoning status of Mirant Potomac River’s generating plant being changed from “noncomplying use” to “nonconforming use subject to abatement.” Under the nonconforming use status, unless Mirant Potomac River applies for and is granted a special use permit for the plant during the seven-year abatement period, the operation of the plant must be terminated within a seven-year period, and no alterations that directly prolong the life of the plant will be permitted during the seven-year period. If Mirant Potomac River were to apply for and receive a special use permit for the plant, the City Council would likely impose various conditions and stipulations as to the permitted use of the plant and seek to limit the period for which it could continue to operate.

At its December 18, 2004, meeting, the City Council also approved revocation of two special use permits issued in 1989 (the “1989 SUPs”), one applicable to the administrative office space at Mirant Potomac River’s plant and the other for the plant’s transportation management plan. Under the terms of the approved action, the revocation of the 1989 SUPs was to take effect 120 days after the City Council’s action, provided, however, that if Mirant Potomac River within such 120-day period filed an application for the necessary special use permits to bring the plant into compliance with the zoning ordinance provisions then in effect, the effective date of the revocation of the 1989 SUPs would be stayed until final decision by the City Council on such application. The approved action further provides that if such special use permit application is approved by the City Council, revocation of the 1989 SUPs will be dismissed as moot, and if the City Council does not approve the application, the revocation of the 1989 SUPs will become effective and the plant will be considered a nonconforming use subject to abatement.

On January 18, 2005, we and Mirant Potomac River filed a complaint against the City of Alexandria and the City Council in the Circuit Court for the City of Alexandria. The complaint sought to overturn the actions taken by the City Council on December 18, 2004, changing the zoning status of Mirant Potomac River’s generating plant and approving revocation of the 1989 SUPs, on the grounds that those actions violated federal, state and city laws. The complaint asserted, among other things, that the actions taken by the City Council constituted unlawful spot zoning, were arbitrary and capricious, constituted an unlawful attempt by the City Council to regulate emissions from the plant, and violated Mirant Potomac River’s due process rights. We and Mirant Potomac River requested the court to enjoin the City of Alexandria and the City Council from taking any enforcement action against Mirant Potomac River or from requiring it to obtain a special use permit for the continued operation of its generating plant. On January 18, 2006, the court issued an oral ruling following a trial that the City of Alexandria acted unreasonably and arbitrarily in changing the zoning status of Mirant Potomac River’s generating plant and in revoking the 1989 SUPs. On February 24, 2006, the court entered judgment in favor of Mirant Potomac River and Mirant Mid-Atlantic declaring the change in the zoning status of Mirant Potomac River’s generating plant adopted December 18, 2004, to be invalid and vacating the City Council’s revocation of the 1989 SUPs. The City of

Alexandria filed a petition with the Virginia Supreme Court seeking to appeal this judgment, and on September 11, 2006, the Virginia Supreme Court agreed to hear the appeal.

Pepco Assertion of Breach of Local Area Support Agreement

Following the shutdown of the Potomac River plant on August 24, 2005, Mirant Potomac River notified Pepco on August 30, 2005, that it considered the circumstances resulting in the shutdown of the plant to constitute a force majeure event under the Local Area Support Agreement dated December 19, 2000, between Pepco and Mirant Potomac River. That agreement imposes obligations upon Mirant Potomac River to dispatch the Potomac River plant under certain conditions, to give Pepco several years advance notice of any indefinite or permanent shutdown of the plant and to pay all or a portion of certain costs incurred by Pepco for transmission additions or upgrades when an indefinite or permanent shutdown of the plant occurs prior to December 19, 2010. On September 13, 2005, Pepco notified Mirant Potomac River that it considers Mirant Potomac River’s shutdown of the plant to be a material breach of the Local Area Support Agreement that is not excused under the force majeure provisions of the agreement. Pepco contends that Mirant Potomac River’s actions entitle Pepco to recover as damages the cost of constructing additional transmission facilities. Pepco, on January 24, 2006, filed a notice of administrative claims in the bankruptcy proceedings asserting that Mirant Potomac River’s shutdown of the Potomac River plant causes Mirant Potomac River to be liable for the cost of such transmission facilities, which cost it estimates to be in excess of $70 million. Mirant Potomac River disputes Pepco’s interpretation of the agreement. The outcome of this matter cannot be determined at this time.

If it is approved by a final order of the Bankruptcy Court, the Settlement Agreement entered into on May 30, 2006, by the Mirant Settling Parties and the Pepco Settling Parties would resolve all claims asserted by Pepco against Mirant Potomac River arising out of the suspension of operations of the Potomac River plant in August 2005. On August 9, 2006, the Bankruptcy Court entered an order approving the Settlement Agreement, but certain holders of unsecured claims in the bankruptcy proceedings have appealed that order, and the order has not yet become a final order. Under the Settlement Agreement, Pepco would release all claims it has asserted against Mirant Potomac River related to the shutdown of the plant in return for the claim Pepco receives in the Mirant bankruptcy proceeding.

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

None.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

We are an indirect wholly-owned subsidiary of Mirant. Our membership interests are not publicly traded and all of our membership interests are held by our parent Mirant North America. We did not make cash distributions to our Member from the Petition Date through December 31, 2005. In 2006, we made $693 million of cash distributions to our Member. 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.

From July 14, 2003 (the “Petition Date”), through emergence, 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 of Reorganization 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,
	2006		2005		2004		2003			2002
Statements of Operations Data:
Operating revenues	$	1,901	$	1,197	$	1,022	$	856		$	947
Net income (loss)	922		7		106		(441		)	183
Balance Sheet Data:
Total assets	3,404		3,341		3,155		3,020			3,337
Long-term debt	34		36		39		43			44
Total equity	3,292		3,062		2,956		2,850			3,219

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.

The primary factors affecting the earnings and cash flows of our operations are the prices for power, emissions allowances, natural gas, oil and coal, which are largely driven by supply and demand. The increase in new generation capacity that followed the restructuring of the power markets in the late 1990s has created an oversupply situation in most markets which is expected to continue until 2008 to 2010. In certain markets, excess supply has been absorbed or is close to being absorbed. Electricity demand has been growing and supply has not appreciably increased.

Demand for power can also vary regionally and seasonally due to, among other things, weather and general economic conditions. Power supplies similarly vary by region and are affected significantly by available generating capacity, transmission capacity and federal and state regulation. We also are affected by the relationship between the prices for power and the prices for fuel, such as natural gas, coal and oil that affect our cost of generating electricity.

Hedging Activities. Prior to 2006, we hedged a substantial portion of our baseload coal-fired generation through OTC transactions. As a result, we achieved a significant increase in our realized gross margin for the year ended December 31, 2006, as compared to the same period in 2005 because our generation was hedged at higher gross margins for this period than for the same period in 2005. Our intermediate and peaking generation volumes generally were lower in the year ended December 31, 2006, than in 2005, due primarily to lower generation from our oil-fired units as a result of lower power prices combined with sharply higher oil prices in 2006.

In 2006 and through February 26, 2007, we entered into financial swap transactions resulting in us being economically hedged for approximately 92%, 93%, 97% and 38% of our expected on-peak coal-fired baseload generation in 2007, 2008, 2009 and 2010, respectively. The financial swap transactions include new hedges in addition to the previously disclosed January 2006 hedges. These transactions are senior unsecured obligations and do not require the posting of cash collateral either for initial margin or for securing exposure due to changes in power prices. As of February 26, 2007, our total portfolio is economically hedged approximately 92%, 58%, 43% and 17% for 2007, 2008, 2009 and 2010, respectively. The corresponding fuel hedges are approximately 97%, 33%, 18% and 0% for 2007, 2008, 2009 and 2010, respectively.

Capital Resources. Our business is subject to extensive environmental regulation by federal, state and local authorities. Our costs of complying with environmental laws, regulations and permits are substantial and difficult to estimate because we cannot always assess what regulations may be adopted or modified in the future or what costs might be associated with complying with the regulation. To comply with the requirements for SO2 and NOx emissions under the Maryland Healthy Air Act, we anticipate total capital expenditures of approximately $1.6 billion through 2009, including $80 million incurred through 2006. We expect that cash flows from operations and preferred shares in Mirant Americas will be sufficient to fund these capital expenditures.

Bankruptcy Considerations

While in bankruptcy, our financial results were volatile as restructuring activities, contract terminations and rejections, and claims assessments significantly affected our consolidated and combined financial results. As a result, our historical financial performance is not indicative of our financial performance post-bankruptcy.

Results of Operations

Operating Statistics

Our capacity factor (average percentage of full capacity used over a year) was 36% for the year ended December 2006, compared to 39% and 40% for the years ended December 2005 and 2004, respectively. Our power generation volumes for the year ended December 2006 (in gigawatt hours) were 16,607, compared to 18,200 and 18,712 for the years ended December 2005 and 2004, respectively.

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

	Years Ended December 31,
	2006			2005			Increase/ (Decrease)				2005			2004			Increase/ (Decrease)
Realized Gross Margin	$	834		$	552			$	282		$	552		$	576			$	(24	)
Unrealized Gross Margin	484			(97		)		581			(97		)	(75		)		(22		)
Total Gross Margin	1,318			455				863			455			501				(46		)
Operating Expenses:
Operations and maintenance
Affiliate	135			148				(13		)	148			152				(4		)
Nonaffiliate	198			193				5			193			184				9
Depreciation and amortization.	74			64				10			64			62				2
Gain on sale of assets, net	(7		)	—				(7		)	—			—				—
Total operating expenses	400			405				(5		)	405			398				7
Operating income	918			50				868			50			103				(53		)
Other expense (income), net
Affiliate	(2		)	10				(12		)	10			3				7
Nonaffiliate	(2		)	8				(10		)	8			—				8
Reorganization items, net	—			22				(22		)	22			(6		)		28
Cumulative effect of change in accounting principles	—			(3		)		3			(3		)	—				(3		)
Net income	$	922		$	7			$	915		$	7		$	106			$	(99	)

Gross Margin

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

	Years Ended December 31,
	2006		2005			Increase/ (Decrease)				2005			2004			Increase/ (Decrease)
Energy	$	558	$	867			$	(309	)	$	867		$	481			$	386
Contracted and capacity	39		64				(25		)	64			62				2
Incremental realized value of hedges	237		(379		)		616			(379		)	33				(412		)
Unrealized gains (losses)	484		(97		)		581			(97		)	(75		)		(22		)
Total	$	1,318	$	455			$	863		$	455		$	501			$	(46	)

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

Contracted and capacity represents revenue received through installed capacity arrangements 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 gains/losses represent the unrealized portion of our derivative contracts.

2006 versus 2005

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

· an increase of $581 million related to unrealized gains and losses on 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 $616 million in incremental realized value of hedges of our generation output. In 2006, the incremental realized value of our hedges contributed $237 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 $379 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 $309 million in energy primarily related to lower power prices and lower generation volume 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 $7 million gain related to the sale of the Mirant Service Center in 2006.

Other Expense (Income), net

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

2005 versus 2004

The decrease in our gross margin is primarily due to the following:

· a decrease of $412 million in incremental realized value of hedges primarily related to the impact of rising energy prices on the realized economic hedges of our generation output during the 2005 period;

· a decrease of $22 million related to unrealized gains and losses on hedging activities. In 2005, unrealized losses of $97 million included $207 million related to decreased value associated with forward power contracts for future periods resulting from increases in forward power prices late in the year, partially offset by $49 million related to increased value associated with forward fuel contracts for future periods resulting from increases in forward fuel prices late in the year. This was partially offset by unrealized gains of $61 million primarily due to the settlement of power contracts during the year for which unrealized losses had been recorded in prior periods; and

· an increase of $386 million in energy primarily related to higher market prices for power, partially offset by higher fuel costs during the year ended December 31, 2005, compared to the same period in 2004.

Operating Expenses

Operating expenses increased by $7 million primarily due to the following:

· a decrease of $4 million in operations and maintenance—affiliate primarily due to the following:

· an increase of $6 million related to our corporate overhead allocations from Mirant Services; and

· a decrease of $8 million due to a reduction in charges under the service agreement with Mirant Americas Energy Marketing.

· an increase of $9 million in operations and maintenance—nonaffiliate primarily due to the following:

· an increase of $11 million due to higher maintenance, of which $3 million is related to unplanned outages at the Morgantown and Chalk Point facilities; and $2 million related to the Potomac River downwash project;

· an increase of $3 million due to an increase in the reserve for obsolete spare parts inventory; and

· a decrease of $4 million due to additional rent expense in 2004 for our Morgantown and Dickerson baseload units;

Other Expense, net

The increase in other expense, net of $15 million is primarily due to additional interest expense recorded in 2005 related to liabilities subject to compromise.

Liquidity and Capital Resources

Overview

Our liquidity and capital requirements are primarily a function of our capital expenditures, contractual obligations, legal settlements and working capital needs. Net cash flow provided by operating activities totaled $468 million, $170 million and $106 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Sources of Funds

The principal sources of liquidity for our future operations and capital expenditures are expected to be: (i) existing cash on hand and cash flows from the operations of the Company’s and its subsidiaries and (ii) letters of credit issued under and intercompany advances of borrowings under Mirant North America’s senior credit facility.

In addition, we expect to fund $265 million of our environmental capital expenditures with proceeds from the preferred shares issued to us by Mirant Americas. See Note 8 to our consolidated and combined financial statements contained elsewhere in this report for further discussion.

Our operating cash flows may be affected by, among other things: (i) demand for electricity; (ii) the difference between the cost of fuel used to generate electricity and the market value of the electricity generated; (iii) commodity prices (including prices for electricity, emissions allowances, natural gas, coal

and oil); (iv) the cost of ordinary course operations and maintenance expenses; (v) planned and unplanned outages; (vi) terms with trade creditors; and (vii) 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 generation facilities, are significantly influenced by capital expenditures required to keep our power generation facilities in operation.

Capital Expenditures. Capital expenditures were $112 million, $67 million and $41 million for the years ended December 31, 2006, 2005 and 2004, respectively. Our capital expenditures for 2007 are expected to be approximately $573 million for environmental capital expenditures needed to achieve compliance with the SO2 and NOx emissions requirements of 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 rental expense for these leases on a straight-line basis in accordance with the applicable accounting literature. As of December 31, 2006, the total notional minimum lease payments for the remaining term of the leases aggregated approximately $2.2 billion and the aggregate termination value for the leases was approximately $1.4 billion and generally decreases over time. Our rent expenses under the Morgantown and Dickerson operating leases were $96 million, $99 million and $103 million for the years ended December 31, 2006, 2005 and 2004, respectively. 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 twelve months’ rent or $75 million.

Cash Flows

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. 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 was $26 million for the year ended December 31, 2006, compared to net cash used in investing activities of $191 million for 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 the Mirant Service Center and $2 million from the sale of emissions allowances to affiliate.

Financing Activities

Net cash used in financing activities was $695 million for the year ended December 31, 2006, compared to $2 million for the same period in 2005. The increase is due to distribution to member of $693 million in 2006.

2005 versus 2004

Operating Activities

Net cash provided by operating activities increased $64 million for the year ended December 31, 2005, compared to 2004. Net cash provided by operating activities excluding the effects of working capital decreased by $65 million primarily due to:

· a decrease in realized gross margin of $24 million for the year ended December 31, 2005, compared to the same period in 2004. See “Results of Operations” for additional discussion;

· a decrease of $28 million related to an increase in payments related to the bankruptcy proceedings; and

· a decrease of $7 million primarily related to an increase in operating expenses.

Investing Activities

Net cash used in investing activities was $191 million for the year ended December 31, 2005, compared to $41 million for the same period in 2004. The increase of $150 million was primarily due to the following:

· in 2005, we had capital expenditures of $67 million compared to $41 million for the same period in 2004; and

· in 2005, we issued a note receivable from affiliate in the amount of $327 million and we received payments on note receivable from affiliate of $203 million in 2005.

Financing Activities

Net cash used in financing activities was $2 million for the years ended December 31, 2005 and 2004, related to payments of capitalized lease obligations.

Off-Balance Sheet Arrangements and Contractual Obligations

Our off-balance sheet arrangements and contractual obligations as of December 31, 2006, are as follows (in millions):

	Off-Balance Sheet Arrangements and Contractual Obligations by Year
	Total		2007		2008		2009		2010		2011		>5 years
Morgantown & Dickerson operating leases	$	2,246	$	112	$	121	$	142	$	140	$	134		$	1,597
Other operating leases	34		4		4		4		4		3			15
Long-term debt	48		6		5		5		5		6			21
Purchase commitments:
Synthetic fuel	82		82		—		—		—		—			—
Coal purchases-affiliate	312		157		89		66		—		—			—
Other purchase commitments	140		140		—		—		—		—			—
Total	$	2,862	$	501	$	219	$	217	$	149	$	143		$	1,633

Operating leases are off-balance sheet arrangements and are discussed in Note 13 to our consolidated and combined financial statements contained elsewhere in this report. These amounts primarily relate to our minimum lease payments associated with our lease of the Morgantown and Dickerson baseload units.

Long-term debt includes the current portion of long-term debt and long-term debt on the consolidated balance sheets, which are discussed in Note 9 to our consolidated and combined financial statements contained elsewhere in this report. Long-term debt also includes estimated interest on debt based on a U.S. Dollar LIBOR curve as of January 2, 2007.

Fuel purchase commitments include a long-term synthetic fuel purchase agreement and amounts related to our coal purchase commitment with Mirant Energy Trading. The fair value of certain contracts is included in price risk management assets or price risk management liabilities on our consolidated balance sheets.

Other purchase commitments represent the 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 generation facilities.

Critical Accounting Policies and 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 impact on our consolidated and combined results of operations or financial condition.

We have discussed the selection and application of these accounting estimates with the Board of Managers and our independent auditors. It is management’s view that the current assumptions and other considerations used to estimate amounts reflected in our consolidated and combined financial statements are appropriate. However, actual results can differ significantly from those estimates under different

assumptions and conditions. The sections below contain information about our most critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop the estimates.

Revenue Recognition and Accounting for Energy 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 electric power 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 No. 133, derivative contracts are reflected in our financial statements at fair value, with changes in fair value recognized currently in earnings unless they qualify for a scope exception. Management considers fair value techniques, 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—affiliate and nonaffiliate and liabilities—affiliate in our consolidated balance sheets. Transactions that do not qualify for accounting under SFAS No. 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—affiliate and nonaffiliate and liabilities—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.

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 No. 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 due to changes in energy and fuel prices. Due to the complexity of the models used to value some of the derivative instruments each period, a significant change in estimate could have a material impact on our results of operations and cash flows at the time contracts are ultimately settled. See Note 5 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.

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 No. 143 and under FIN 47. SFAS No. 143 and FIN 47 require an entity to recognize the fair value of a liability for conditional and unconditional asset retirement obligations in the period in which they are incurred. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 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 generation operations. 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 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, due to 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 goodwill and other 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 No. 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. 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.

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. 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 No. 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 an 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, 2006. 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 2006.

The critical assumptions used in our income valuation approach included assumptions as to the 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 our weighted average cost of capital. The assumptions included capital expenditures through 2009 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. 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 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

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

See “Item 3. Legal Proceedings” and Note 14 to our consolidated and combined financial statements for further information related to our legal proceedings.

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 power generation business, we enter into a variety of short and long-term agreements with Mirant Energy Trading and third parties to acquire the fuel for generating electricity and to sell the electricity produced. 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 these commodities.

The financial performance of our power generation business is influenced by the difference between the variable cost of converting a source 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 generation facilities in the PJM region, plant 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 generation facility widening or narrowing (or becoming negative) over time.

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 risk and changes in conversion spreads. These derivatives have varying terms and durations, or tenors, which range from a few days to a number of years, depending on the instrument.

Derivative energy contracts required to be reflected at fair value are presented as price risk management assets—affiliate and nonaffiliate and price risk management liabilities-affiliate in the accompanying consolidated balance sheets. The net changes in their market values are recognized in income in the period of change. The fair value of the PPAs which we account for as derivatives are included in price risk management assets—affiliate and nonaffiliate and liabilities-affiliate on the accompanying consolidated balance sheets at December 31, 2006 and 2005. 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 and contracts.

The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at December 31, 2006, was thirteen months. The net notional amount, or net short position, of the price risk management assets and liabilities—affiliate and nonaffiliate at December 31, 2006, was approximately 23 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 2006 (in millions):

Net fair value of portfolio at December 31, 2005	$	(158	)
Gains recognized in the period, net	312
Contracts settled during the period, net	172
Net fair value of portfolio at December 31, 2006	$	326

The fair values of our price risk management assets—affiliate and nonaffiliate, net of credit reserves, as of December 31, 2006, are as follows (in millions):

	Current Assets			Noncurrent Assets			Net Fair Value at December 31, 2006
Electricity		$	254		$	59		$	313
Coal/other		13			—			13
Total		$	267		$	59		$	326

Of the total $326 million net fair value asset at December 31, 2006, a net price risk management asset of $267 million relates to contracts to be settled in 2007, a net price risk management asset of $31 million relates to contracts to be settled in 2008, a net price risk management asset of $29 million relates to contracts to be settled in 2009 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 limits and restrictions related to our asset management activities. There is no VaR limit with respect to our asset management activities, as these activities are only allowable if they reduce the commodity price exposure of our generation assets. We manage the market risks associated with our asset management activities in conjunction with the physical generation assets that they are designed to economically hedge.

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 in nature. To ensure compliance with this restriction, each transaction is classified as either a conversion spread transaction or fuel oil management transaction. Each conversion spread transaction is tested at the transaction level to ensure that each individual transaction executed is risk-reducing relative to the overall asset position. Fuel oil management activities include management of physical fuel oil burns, physical fuel oil infrastructure and time and product spread positions. While these fuel oil activities are designed primarily to manage the risk associated with physical specifications and availability of fuel oil for the power plants, at any given time the fuel oil portfolio contains open market price risk. Each individual fuel oil transaction is not tested for risk reduction, but these activities are tested in aggregate to ensure that the overall activity is risk-reducing.

See “Critical Accounting Policies and Estimates” for accounting treatment for asset management activities.

Credit and Collection 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 measure credit risk as the loss we would record if our customers failed to perform pursuant to the terms of their contractual obligations less the value of collateral held by us, if any, to cover such losses. 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.

Item 8. Financial Statements and Supplementary Data

MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

DECEMBER 31, 2006, CONSOLIDATED STATEMENT OF OPERATIONS
and
DECEMBER 31, 2005 and 2004, COMBINED STATEMENTS OF OPERATIONS

	For the Years Ended December 31,
	2006			2005			2004
	(in millions)
Operating revenues—affiliate	$	1,711		$	1,197		$	1,021
Operating revenues—nonaffiliate	190			—			1
Total operating revenues	1,901			1,197			1,022
Cost of fuel, electricity and other products—affiliate	465			610			372
Cost of fuel, electricity and other products—nonaffiliate	118			132			149
Total cost of fuel, electricity and other products	583			742			521
Gross Margin	1,318			455			501
Operating Expenses:
Operations and maintenance—affiliate, including restructuring charges of $1, $2 and $3, respectively	135			148			152
Operations and maintenance—nonaffiliate	198			193			184
Depreciation and amortization	74			64			62
Gain on sale of assets, net—affiliate	(2		)	—			—
Gain on sale of assets, net—nonaffiliate	(5		)	—			—
Total operating expenses	400			405			398
Operating Income	918			50			103
Other Expense (Income), net:
Interest expense—affiliate	—			10			3
Interest expense—nonaffiliate	4			8			3
Interest income—affiliate	(2		)	—			—
Interest income—nonaffiliate	(5		)	—			—
Other, net	(1		)	—			(3		)
Total other expense (income), net	(4		)	18			3
Income Before Reorganization Items	922			32			100
Reorganization items, net	—			22			(6		)
Income Before Cumulative Effect of Changes in Accounting Principles	922			10			106
Cumulative Effect of Changes in Accounting Principles	—			(3		)	—
Net Income	$	922		$	7		$	106

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

MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

CONSOLIDATED BALANCE SHEETS

	December 31,
	2006			2005
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	75		$	276
Receivables:
Affiliate	86			51
Nonaffiliate	2			1
Notes receivable from affiliate	—			124
Price risk management assets—affiliate	132			—
Price risk management assets—nonaffiliate	135			—
Fuel stock and emissions allowances	95			78
Materials and supplies	35			30
Prepaid rent	96			96
Funds on deposit	2			56
Assets held for sale	—			7
Other current assets	18			19
Total current assets	676			738
Property, Plant, and Equipment, net	1,495			1,408
Noncurrent Assets:
Goodwill, net	799			799
Price risk management assets—affiliate	5			26
Price risk management assets—nonaffiliate	54			—
Other intangible assets, net	156			161
Prepaid rent	218			208
Other noncurrent assets	1			1
Total noncurrent assets	1,233			1,195
Total Assets	$	3,404		$	3,341
LIABILITIES AND EQUITY
Current Liabilities:
Current portion of long-term debt	$	3		$	3
Accounts payable and accrued liabilities	54			28
Payable to affiliate	11			21
Price risk management liabilities—affiliate	—			184
Total current liabilities	68			236
Noncurrent Liabilities:
Long-term debt	31			33
Asset retirement obligations	12			9
Other long-term liabilities	1			1
Total noncurrent liabilities	44			43
Commitments and Contingencies
Equity:
Member’s interest	3,513			3,270
Preferred stock in affiliate	(221		)	(208		)
Total equity	3,292			3,062
Total Liabilities and Equity	$	3,404		$	3,341

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

MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

DECEMBER 31, 2006, CONSOLIDATED STATEMENT OF CASH FLOWS
and
DECEMBER 31, 2005 and 2004, COMBINED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2006			2005			2004
	(in millions)
Cash Flows from Operating Activities:
Net income	$	922		$	7		$	106
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	74			64			62
Price risk management activities, net	(484		)	97			75
Gain on sale of assets	(7		)	—			—
Cumulative effect of changes in accounting principles	—			3			—
Non-cash charges for reorganization items	—			7			(1		)
Effects of the Plan of Reorganization	—			(3		)	—
Post-petition interest	—			2			—
Other adjustments to net income	(1		)	—			—
Changes in certain assets and liabilities:
Affiliate accounts receivable	(35		)	(30		)	(8		)
Nonaffiliate accounts receivable	(1		)	—			3
Prepaid rent	(10		)	(9		)	(23		)
Materials, fuel stock and emissions allowances	(21		)	37			(80		)
Other assets	55			(51		)	(1		)
Accounts payable and accrued liabilities	(14		)	7			(16		)
Payables to affiliate	(10		)	67			(10		)
Taxes accrued—nonaffiliate	—			(28		)	(1		)
Total adjustments	(454		)	163			—
Net cash provided by operating activities	468			170			106
Cash Flows from Investing Activities:
Capital expenditures	(112		)	(67		)	(41		)
Issuance of notes receivable from affiliate	—			(327		)	(33		)
Repayment of notes receivable from affiliates	124			203			33
Proceeds from sale of assets	14			—			—
Net cash provided by (used in) investing activities	26			(191		)	(41		)
Cash Flows from Financing Activities:
Repayment of long-term debt	(2		)	(2		)	(2		)
Distribution to member	(693		)	—			—
Net cash used in financing activities	(695		)	(2		)	(2		)
Net Increase (Decrease) in Cash and Cash Equivalents	(201		)	(23		)	63
Cash and Cash Equivalents, beginning of year	276			299			236
Cash and Cash Equivalents, end of year	$	75		$	276		$	299
Supplemental Cash Flow Disclosures:
Cash paid for interest	$	4		$	16		$	5
Financing Activity:
Capital contribution—non-cash	$	1		$	—		$	—

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

MIRANT MID-ATLANTIC AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

1. Description of Business and Organization

Mirant Mid-Atlantic or the Company was formed as a Delaware limited liability company on July 12, 2000. Mirant Mid-Atlantic historically has been 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, and is the successor to a corporation of the same name that was formed in Delaware on April 3, 1993. This succession occurred by virtue of the transfer of substantially all of Old Mirant’s assets to New Mirant in conjunction with Old Mirant’s emergence from bankruptcy protection on January 3, 2006. Old Mirant was then renamed and transferred to a trust that is not affiliated with New Mirant.

Pursuant to the Plan of Reorganization (the “Plan”) that was approved in conjunction with Mirant’s emergence from bankruptcy, in December 2005 Mirant contributed its interest in Mirant Potomac River and Mirant Peaker to Mirant Mid-Atlantic and Mirant Mid-Atlantic became a direct wholly-owned subsidiary of Mirant North America, a newly organized holding company subsidiary of Mirant Americas Generation. The contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.”

The Company is an independent power provider that earns revenue primarily by producing and selling electricity. The Company uses derivative financial instruments, such as commodity forwards, futures, options and swaps to manage its exposure to fluctuations in electric energy and fuel prices. Mirant Mid-Atlantic owns or leases approximately 5,256 MW of electric generation 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.

On January 31, 2006, the trading and marketing business of Mirant Americas Energy Marketing, Mirant Americas Development, Inc., Mirant Americas Production Company, Mirant Americas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas Retail Energy Marketing, LP, and Mirant Americas Gas Marketing, LLC (collectively, the “Trading Debtors”) was transferred to Mirant Energy Trading, a wholly-owned subsidiary of Mirant North America, which, pursuant to the Plan, has no successor liability for any unassumed obligations of the Trading Debtors. After these transfers took place, the Trading Debtors were transferred to a trust created under the Plan that is not affiliated with the Company. As a result, the Company now executes the affiliate transactions previously executed with the Trading Debtors with Mirant Energy Trading.

The Company has a number of service agreements with subsidiaries of Mirant related to the sales of its electric power and the procurement of fuel, labor and administrative services essential to operating its business. These related parties are primarily Mirant Energy Trading and Mirant Services. The Company also has a number of service agreements for labor and administrative services with Mirant Services. See Note 8 to the consolidated and combined financial statements for further discussion of arrangements with these related parties.

2. Accounting and Reporting Policies

Basis of Presentation

The accompanying consolidated and combined financial statements of Mirant Mid-Atlantic and its wholly-owned subsidiaries 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 historical 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.

Use of Estimates

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

· determining the fair value of certain derivative contracts;

· 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 generation 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 for sales of energy based on economic-dispatch are recorded on the basis of MWh delivered, at the relevant day-ahead or real-time prices. The Company also recognizes affiliate revenue when ancillary services have been performed and collection of such revenue is probable.

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—nonaffiliate, and changes in fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. Electricity sales and fuel supply derivative financial instruments that qualify as normal purchases and normal sales transactions pursuant to SFAS No. 133 are exempt from fair value accounting treatment and are accounted for on the accrual method of accounting. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized currently in earnings. If the derivative is designated as a cash flow hedge, the changes in the fair value of the derivative are recorded in OCI and the realized gains and losses related to these derivatives are recognized in earnings in the same period as the settlement of the underlying hedged transaction. Any ineffectiveness relating to cash flow hedges is recognized currently in earnings. The assets and liabilities related to derivative instruments that have not been designated as

hedges for accounting purposes are included in price risk management assets and liabilities—affiliate and price risk management assets—nonaffiliate. For the years ended December 31, 2006, 2005 and 2004, the Company did not have any derivative instruments that it had designated as fair value or cash flow hedges for accounting purposes. All derivative contracts are recorded at fair value, except for a limited number of transactions that qualify for the normal purchases or normal sales exclusion from SFAS No. 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. Changes in fair value of electricity derivative financial instruments are reflected in generation 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 2006, 2005 and 2004, Mirant Mid-Atlantic earned its operating revenue and gross margin from the PJM energy market, where the Company’s generation facilities are located.

Concentration of Labor Subject to Collective Bargaining Agreements

Personnel at the Company’s facilities are employed through Mirant Services. As of December 31, 2006, approximately 68% of such personnel employed through contracts with Mirant Services are subject to collective bargaining agreements.

Cash and Cash Equivalents

Mirant Mid-Atlantic considers all short-term investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash

Restricted cash is included in current assets as funds on deposit in the accompanying consolidated balance sheets and amounted to $2 million and $56 million at December 31, 2006 and 2005, respectively. Restricted cash includes deposits with brokers and cash collateral posted with third parties to support the Company’s commodity positions.

Fuel Stock 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.

Emissions Allowances

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-affiliate 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.

Emissions allowances granted by the EPA related to generation facilities owned by the Company are recorded at fair value at the date of the acquisition of the facility and are included in property, plant and equipment. These emissions allowances are depreciated on a straight-line basis over the estimated useful

life of the respective generation facility, which ranges from 18 to 34 years, and are charged to depreciation and amortization expense in the accompanying consolidated and combined statements of operations.

Emissions allowances granted by the EPA related to generation facilities leased by the Company are recorded at fair value at the commencement of the lease in other intangible assets. These emissions allowances are amortized on a straight-line basis over the term of the lease, and are charged to depreciation and amortization expense in the accompanying consolidated and combined statements of operations.

The Company has determined that certain exchanges of emissions allowances that the Company may periodically transact qualify as nonmonetary exchanges under SFAS No. 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 plant 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.

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 discounted cash flow techniques and assumptions as to business prospects using the best information available.

Environmental Remediation Costs

Mirant Mid-Atlantic accrues for costs associated with environmental remediation when such costs are probable and can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial 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. In December 2005, pursuant to the Plan, Mirant rejected and thereby eliminated 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 No. 144. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value. Assets to be disposed of are separately presented in the accompanying consolidated balance sheets and are reported at the lower of the carrying amount or fair value less costs to sell, and are not depreciated. The assets and liabilities of a disposal group classified as held for sale are presented separately in the appropriate asset and liability sections of the accompanying consolidated balance sheets.

Cumulative Effect of Changes in Accounting Principles

The Company adopted FIN 47, effective December 31, 2005, related to the costs associated with conditional legal obligations to retire tangible, long-lived assets. Conditional asset retirement obligations are recorded at the fair value in the period in which they are incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its fair value and the capitalized costs are depreciated over the useful life of the related asset. For the year ended December 31, 2005, the Company recorded a charge as a cumulative effect of a change 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, 2006 and 2005, financial instruments recorded at contractual amounts that approximate market or fair value include cash and cash equivalents, funds on deposit, receivables from affiliate (excluding pre-petition amounts discussed below) and customer accounts receivable, notes receivable from affiliate, 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, 2006, the carrying value of the Company’s long-term debt approximated fair value.

Rent Expense

Rent expense related to the Company’s operating leases is recognized on a straight-line basis over the terms of the leases. Rent expense for generation facilities is included in operations and maintenance—nonaffiliate in the accompanying consolidated and combined statements of operations. 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.

Recently Adopted Accounting Standards

In September 2005, the FASB ratified EITF 04-13, which requires companies to account for certain purchases and sales of inventory with the same counterparty as a single transaction. The Company adopted EITF 04-13 on April 1, 2006. The application of EITF 04-13 has not had a material impact on the Company’s statement of operations, financial position or cash flows.

In April 2006, the FASB issued FSP FIN 46R-6. The variability that is considered in applying FIN 46R affects the determination of whether an entity is a VIE, which interests are variable interests in the entity and which party, if any, is the primary beneficiary of the VIE. According to FSP FIN 46R-6, the variability to be considered should be based on the nature of the risks of the entity and the purpose for which the entity was created. The guidance in FSP FIN 46R-6 is applicable prospectively to an entity at the time a company first becomes involved with such entity and is applicable to all entities previously required to be analyzed under FIN 46R when a reconsideration event has occurred beginning with the first reporting period after June 15, 2006. Retrospective application to the date of the initial application of FIN 46R is permitted but not required. The Company adopted FSP FIN 46R-6 on July 1, 2006, on a prospective basis. Upon adoption there was no material impact on the Company’s statements of operations, financial position or cash flows.

On September 13, 2006, the SEC issued SAB No. 108, which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. SAB No. 108 provides that a registrant should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. SAB No. 108 is effective for fiscal years ending on or after November 15, 2006. The adoption of SAB No. 108 had no material impact on the Company’s statements of operations, financial position or cash flows.

New Accounting Standards Not Yet Adopted

In February 2006, the FASB issued SFAS No. 155, which allows fair value measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. SFAS No. 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 will adopt SFAS No. 155 on January 1, 2007. The adoption of SFAS No. 155 is not expected to have a material impact on the Company’s statements of operations, financial position or cash flows.

In March 2006, the FASB issued SFAS No. 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. SFAS No. 156 is effective at the beginning of the first fiscal year after September 15, 2006. The Company will adopt SFAS No. 156 on January 1, 2007. All requirements for recognition and initial measurement of servicing assets and servicing liabilities will be applied prospectively to transactions occurring after the adoption of this statement. The adoption of SFAS No. 156 is not expected to have a material impact on the Company’s statements of operations, financial position or cash flows.

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 No. 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.

The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is recognition based on a determination of whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority having full knowledge of all relevant information. The second step is to measure a tax position that meets the more-likely-than-not threshold. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company will adopt FIN 48 on January 1, 2007. Upon initial adoption, the provisions of FIN 48 will be applied to all tax positions. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized. The adoption of FIN 48 is not expected to have a material impact 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 Opinion No. 22, “Disclosure of Accounting Policies.” 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 will adopt EITF 06-3 on January 1, 2007. The adoption of EITF 06-3 is not expected to have a material impact on the Company’s statements of operations, financial position or cash flows.

On July 13, 2006, the FASB finalized FSP FAS 13-2, which addresses how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the accounting by a lessor for that lease. The Company will adopt FSP FAS 13-2 on January 1, 2007. The adoption of FSP FAS 13-2 is not expected to have a material impact on the Company’s statements of operations, financial position or cash flows.

On September 8, 2006, the FASB issued FSP AUG AIR-1. FSP AUG AIR-1 permits the following methods for accounting for major maintenance activities: direct expense, built-in overhaul and deferral. It specifically prohibits accruing in advance for major maintenance. The guidance in FSP AUG AIR-1 is to be applied to the first fiscal year beginning after December 15, 2006. The Company will adopt FSP AUG AIR-1 on January 1, 2007. The adoption of FSP AUG AIR-1 is not expected to have a material impact on the Company’s statements of operations, financial position or cash flows given that the Company currently uses the deferral or direct expense methods of accounting for major maintenance activities.

On September 15, 2006, the FASB issued SFAS No. 157, which establishes a framework for measuring fair value in GAAP and expands disclosure about fair value measurements. SFAS No. 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. SFAS No. 157 is effective at the beginning of the first fiscal year after November 15, 2007. The Company will adopt SFAS No. 157 on January 1, 2008. At the date of adoption, the Company will evaluate the fair value of its assets and liabilities according to the hierarchy established by the FASB. The Company has not

yet determined the impact of SFAS No. 157 on its statements of operations, financial position or cash flows.

On February 15, 2007, the FASB issued SFAS No. 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 No. 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 No. 159 is effective at the beginning of the first fiscal year after November 15, 2007. The Company will adopt SFAS No. 159 on January 1, 2008. The Company has not yet determined the impact of SFAS No. 159 on its statements of operations, financial position or cash flows.

3. Assets Held for Sale

No assets were held for sale at December 31, 2006. Assets held for sale at December 31, 2005, included $7 million related to the Mirant Service Center building and accompanying land. The sale of the Mirant Service Center closed in the second quarter of 2006, and the Company recognized a gain of approximately $6 million.

4. Inventory

Inventory, at December 31, 2006 and 2005, consisted of (in millions):

	2006		2005
Fuel	$	59	$	63
Emissions allowances	36		15
Materials and supplies	35		30
Total	$	130	$	108

5. 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 generation facilities under an affiliate agreement discussed in Note 8 or with third parties. As discussed in Note 1, on January 31, 2006, Mirant contributed the trading and marketing operations of Mirant Americas Energy Marketing to Mirant Energy Trading. 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 8.

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 generation facilities, although the underlying fuel commodity itself is not a component fuel used to produce electricity.

In 2006 and through February 26, 2007, Mirant Mid-Atlantic entered into financial swap transactions resulting in the Company being economically hedged for approximately 92%, 93%, 97% and 38% of its expected on-peak coal-fired baseload generation for 2007, 2008, 2009 and 2010, respectively.

Power sales agreements, such as the Power Sale, Fuel Supply and Service Agreement, and other contracts that are used to mitigate exposure to commodity prices but which either do not meet the definition of a derivative or are excluded under certain exceptions under SFAS No. 133, are accounted for

on the accrual basis of accounting and are not included in price risk management assets—affiliate or nonaffiliate or price risk management liabilities—affiliate in the accompanying consolidated balance sheets.

As discussed in Note 2, a majority of the Company’s derivative financial instruments are recorded in the accompanying consolidated balance sheets at fair value. Derivative financial instruments with Mirant Energy Trading are recorded on a net basis pursuant to provisions of the Power Sale, Fuel Supply and Services Agreement. All realized and unrealized gains or losses associated with these derivative financial instruments have been recognized in earnings in the period incurred.

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

	Current Assets			Noncurrent Assets			Net Fair Value at December 31, 2006
Electricity		$	254		$	59		$	313
Coal/other		13			—			13
Total		$	267		$	59		$	326

Of the $326 million net fair value asset at December 31, 2006, a net price risk management asset of $267 million relates to 2007, a net price risk management asset of $31 million relates to 2008, a net price risk management asset of $29 million relates to 2009 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, 2006, was approximately 13 months. The net notional amount of the price risk management assets and liabilities at December 31, 2006, was a net short position of approximately 23 million equivalent MWh.

The fair values of the Company’s price risk management assets—affiliate and price risk management liabilities—affiliate, net of credit reserves, at December 31, 2005, are included in the following table (in millions):

	Noncurrent Assets			Current Liabilities				Net Fair Value at December 31, 2005
Electricity		$	4		$	(210	)		$	(206	)
Coal		22			26				48
Total		$	26		$	(184	)		$	(158	)

6. Property, Plant and Equipment, net

Property, plant and equipment, net consisted of the following at December 31, 2006 and 2005 (in millions):

	2006			2005			Depreciable Lives (years)
Production	$	1,625		$	1,576			18 to 32
Oil pipeline	26			26				24
Other	15			15				2 to 10
Construction work in progress	165			60				—
Less: accumulated depreciation.	(336		)	(269		)
Property, plant and equipment, net.	$	1,495		$	1,408

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. The acquired allowances related to owned facilities are included in production assets above, and are depreciated over the average life of the related assets.

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, 2006, 2005 and 2004.

7. Goodwill and Other Intangible Assets

Goodwill, net

The Company evaluates goodwill for impairment at least annually and periodically if indicators of impairment are present in accordance with SFAS No. 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, 2006, 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 2006.

The critical assumptions used in the Company’s income valuation approach included assumptions as to the 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 2009 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, 2006 and 2005 (in millions):

	Weighted		2006							2005
	Average Amortization Lives		Gross Carrying Amount			Accumulated Amortization				Gross Carrying Amount			Accumulated Amortization
Development rights		40 years		$	47		$	(7	)		$	47		$	(6	)
Emissions allowances		32 years		131			(25		)		131			(21		)
Other intangibles		30 years		12			(2		)		12			(2		)
Total other intangible assets				$	190		$	(34	)		$	190		$	(29	)

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 generation facilities.

Emissions allowances recorded in intangible assets relate to allowances granted for the leasehold baseload units at the Morgantown and Dickerson facilities. Allowances granted by the EPA for other 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 $5 million, $6 million and $6 million for the years ended December 31, 2006, 2005 and 2004, respectively. Assuming no future acquisitions, dispositions or impairments of intangible assets, amortization expense is estimated to continue at this level for each of the next five years.

8. Related Party Arrangements and Transactions

Power Sales Agreement with Mirant Energy Trading

In 2004 and 2005, all of the Company’s capacity and energy was sold at market prices to Mirant Americas Energy Marketing. Effective January 3, 2006, the Company operated under a new Power Sale, Fuel Supply and Services Agreement with Mirant Americas Energy Marketing with the same terms and conditions as the 2005 and 2004 agreements. As of February 1, 2006, the energy marketing operations historically conducted by Mirant Americas Energy Marketing are being performed by Mirant Energy Trading. Pursuant to the Plan, Mirant contributed its interest in the trading and marketing operations conducted by Mirant Americas Energy Marketing to Mirant Energy Trading. The remaining assets and liabilities of Mirant Americas Energy Marketing were transferred to a trust that is not affiliated with Mirant on January 31, 2006.

Amounts due to Mirant Energy Trading, and previously to Mirant Americas Energy Marketing, for fuel purchases and due from Mirant Americas Energy Marketing 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, and previously Mirant Americas Energy Marketing, 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.

Mirant Americas Energy Marketing was party to transition power agreements with Pepco. The first agreement expired in June 2004 and the second expired in January 2005. Under these agreements, Pepco had an option to purchase energy with respect to Pepco’s load requirements at fixed rates. Since the expiration of the transition power agreements, the Company has been economically hedging its capacity and energy, through physical bilateral transactions as well as economic financial hedges with Mirant Energy Trading. In addition, the Company has entered into structured transactions with Mirant Energy Trading who had similar transactions with entities serving load in the greater Washington, D.C. area. By entering into structured transactions, the Company looks to extract value for its generation facilities that is over the mid-point of the market for such 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,
	2006			2005			2004
Cost of fuel, electricity and other products—affiliate		$	6		$	7		$	7
Operations and maintenance expense—affiliate		69			76			78
Total		$	75		$	83		$	85

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 years ended 2005 and 2004, these services were received from Mirant 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, 2006, 2005 and 2004, the Company incurred approximately $19 million, $24 million and $32 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.

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, 2006, 2005 and 2004, the Company incurred approximately $47 million, $48 million and $42 million, respectively, in costs under these arrangements, which are included in operations and maintenance—affiliate in the accompanying consolidated and combined statements of operations.

Restructuring Charges

During the years ended December 31, 2006, 2005 and 2004, the Company recorded restructuring charges of $1 million, $2 million and $3 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

During 2005, Mirant Americas Energy Marketing borrowed $327 million from the Company under Mirant’s Chapter 11 cash management program. Mirant Americas Energy Marketing repaid $203 million during 2005. 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 and combined statements of operations.

Mirant Guarantees

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. In June 2005 and September 2005, the full amount of the pre-petition letters of credit was drawn in the amount of $61 million. On January 3, 2006, as part of 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 emissions 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 year ended December 31, 2006, the Company purchased $122 million of emissions allowances from Mirant Energy Trading. For the years ended 2005 and 2004, the Company purchased $15 million and $128 million, respectively, of emissions allowances from Mirant Americas Energy Marketing. 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, 2006, 2005 and 2004, were $65 million, $65 million and $55 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 $36 million for the year ended December 31, 2006, compared to $4 million for the year ended December 31, 2005. As of December 31, 2006 and 2005, the Company had purchased emissions allowances of $36 million and $15 million, respectively, which are recorded in fuel stock and emissions allowances in the accompanying consolidated balance sheets.

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. The sale for $2 million is recorded in gain on sale of assets, net—affiliate in the accompanying consolidated and combined statements of operations.

Preferred Stock 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 mandatory redeemable Series A Preferred Shares and are reflected as preferred stock in affiliate in the accompanying consolidated balance sheets. The Series A Preferred Shares have a Scheduled Redemption Date at a Specified Redemption Amount as follows (in millions):

2007	$	5
2008	31
2009	84
2010	95
2011	50
	$	265

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 $221 million and $208 million as a component of equity in the Company’s consolidated balance sheets at December 31, 2006 and 2005, 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 the year ended December 31, 2006, the Company recorded $13 million in Preferred Stock in affiliate and Member’s Interest in the consolidated balance sheet related to the amortization of the discount on the preferred stock in Mirant Americas.

9. Long-term Debt and Capital Leases

Long-term debt includes a capital lease by Mirant Chalk Point. At December 31, 2006 and 2005, 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 $34 million with an 8.19% annual interest rate. This lease is of an 84 MW peaking electric power generation facility. Depreciation expense related to this lease was approximately $2 million for each of the years ended December 31, 2006, 2005 and 2004. The principal payments under this lease are approximately $3 million annually in 2007 through 2010, $4 million in 2011 and $18 million thereafter. The gross amount of assets under the capital lease, recorded in property, plant and equipment, net as of December 31, 2006 and 2005, was $24 million. The related accumulated depreciation was $10 million and $8 million as of December 31, 2006 and 2005, respectively.

10. Bankruptcy Related Disclosures

Mirant’s Plan was confirmed by the Bankruptcy Court on December 9, 2005, and Mirant and the Company emerged from bankruptcy on January 3, 2006. For financial statement presentation purposes, Mirant and the Company recorded the effects of the Plan at December 31, 2005.

Reorganization Items, net

Reorganization items, net represents expense, income and gain or loss amounts that were recorded in the financial statements as a result of the bankruptcy proceedings. For the year ended December 31, 2005, the company recorded an expense of $22 million, which included an expense of $38 million related to costs arising from the settlement agreement related to the assumption of the Mirant Mid-Atlantic leveraged leases offset by interest income of $13 million and a gain of $3 million related to the net effects of the Plan in the accompanying combined statement of operations. For the year ended December 31, 2004, the Company recorded income of $6 million in the accompanying combined statement of operations.

11. 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,
	2006		2005			2004
Current provision:
Federal	$	137	$	27			$	42
State	23		6				8
Deferred provision (benefit):
Federal	167		(23		)		(7		)
State	29		(11		)		(1		)
Total income tax provision (benefit)	$	356	$	(1	)		$	42

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

	Years Ended December 31,
	2006		2005				2004
U.S. federal statutory income tax provision	$	323		$	3			$	37
State and local income taxes, net	33			(3		)		5
Reorganization items	—			(1		)		—
Tax provision (benefit)	$	356		$	(1	)		$	42

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, 2006 and 2005 (in millions):

	2006			2005
Deferred tax liabilities:
Property and intangible assets	$	(231	)	$	(224	)
Price risk management assets and liabilities—affiliate.	(117		)	—
Other, net.	(5		)	(5		)
Total	(353		)	(229		)
Deferred tax assets:
Price risk management assets and liabilities—affiliate.	—			70
Other, net	—			2
Total	—			72
Net deferred tax liabilities	$	(353	)	$	(157	)

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 8, since the underlying transaction is disregarded for income tax purposes.

12. Asset Retirement Obligations

SFAS No. 143 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 No. 143 and FIN 47 are those for which a legal obligation exists under enacted laws, statutes and written or oral contractions, including obligations arising under the doctrine of promissory estoppel.

The Company identified certain asset retirement obligations within its power generation operations. 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, closing of ash disposal sites and closing of owned 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 acquired 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. However, the actual abatement cost could differ from the estimates used to measure the asset retirement obligation. As a result, these amounts will be subject to revision when actual abatement activities are undertaken.

The following table sets forth the balances of the asset retirement obligations as of January 1, 2005, and the additions and accretion of the asset retirement obligations for the years ended December 31, 2006

and 2005. The asset retirement obligations are included in noncurrent liabilities in the consolidated balance sheets (in millions):

	For the Years Ended December 31,
	2006			2005
Beginning balance, January 1		$	9		$	3
Revisions to cash flows for liabilities recognized upon adoption of SFAS No. 143		—			(1		)
Liabilities recognized upon adoption of FIN 47		—			6
Liabilities recorded in the period		2			—
Accretion expense		1			1
Ending balance, December 31		$	12		$	9

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 Years Ended December 31,
	2005				2004
Beginning balance, January 1		$	9			$	8
Revisions to cash flows for liabilities recognized upon adoption of SFAS No. 143		(1		)		—
Accretion expense		1				1
Ending balance, December 31		$	9			$	9

13. Commitments and Contingencies

Mirant Mid-Atlantic has made firm commitments to buy materials and services in connection with its ongoing operations.

In addition to debt and other obligations in the consolidated balance sheets, Mirant Mid-Atlantic has the following annual commitments under various agreements at December 31, 2006 (in millions):

	2007		2008		2009		2010		2011		Thereafter			Total
Morgantown & Dickerson operating leases	$	112	$	121	$	142	$	140	$	134		$	1,597	$	2,246
Other operating leases	4		4		4		4		3			15		34
Synthetic fuel purchase commitments	82		—		—		—		—			—		82
Coal purchase commitments—affiliate	157		89		66		—		—			—		312
Other purchase commitments	140		—		—		—		—			—		140
Total payments	$	495	$	214	$	212	$	144	$	137		$	1,612	$	2,814

Operating Leases

Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively, and 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 expenses totaled $96 million, $99 million and $103 million for the years ended December 31, 2006, 2005 and 2004, respectively, which are included in operations and maintenance—nonaffiliate in the accompanying consolidated and combined statements of operations. As of December, 31, 2006 and 2005,

the Company has paid approximately $314 million and $304 million, respectively, of lease payments in excess of rent expense recognized.

As of December 31, 2006, the total notional minimum lease payments for the remaining terms of the leases aggregated approximately $2.2 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 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.

Significant disputes arose between the Mirant Debtors and the owner lessors and the indenture trustee for the Mirant Mid-Atlantic leveraged leases regarding among other things, whether or not the leveraged lease transactions constituted a “lease” (or “leases”) within the meaning of section 365 of the Bankruptcy Code, or instead evidenced a financing arrangement. On November 30, 2005, the Company entered into a settlement agreement with the Morgantown and Dickerson facilities’ owner lessors and the indenture trustee as part of a resolution of disputed matters in the Chapter 11 proceedings. Pursuant to this settlement agreement and the Plan, the Company made several payments including a settlement payment of $6.5 million each to the owner lessors and the indenture trustee, $2.9 million as restoration payments under the leases, and a reimbursement of legal and consulting fees of approximately $22 million. With the exception of $6.5 million paid to the indenture trustee in January 2006, the remaining amounts were paid in December 2005. The total costs of $38 million have been recorded in reorganization items, net in the 2005 combined statement of operations.

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 2007 through 2010, $3 million in 2011 and $15 million thereafter. Expenses associated with these commitments totaled approximately $4 million per year during 2006, 2005 and 2004.

Fuel Commitments

As of December 31, 2006, the total estimated commitments associated with fuel commitments is $394 million. Of this amount, approximately $312 is related to a coal purchase arrangement with Mirant Energy Trading.

Other Purchase Commitments

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

Mirant Mid-Atlantic entered into an agreement on June 24, 2005, for an SCR System at the Morgantown generating station. The system shall be furnished and installed to comply with a State of

Maryland environmental consent decree to reduce the emissions of NOx. The contract value of this capital expenditure is approximately $94 million.

14. 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 No. 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 and combined financial position, results of operations or cash flows.

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. Most of the material claims filed against the Mirant Debtors’ estates were disallowed or were resolved and became “allowed” claims before confirmation of the Plan that became effective for Mirant, the Company and most of the Mirant Debtors on January 3, 2006. Mirant, as the distribution agent under the Plan, has made distributions pursuant to the terms of the Plan on those allowed claims. Some claims, however, remain unresolved.

As of December 31, 2006, approximately 21 million of the shares of Mirant common stock to be distributed under the Plan have not yet been distributed and have been reserved for distribution with respect to claims that are disputed by the Mirant Debtors and have not been resolved. A settlement entered into on May 30, 2006, among Pepco, Mirant, MC 2005, LLC f/k/a Mirant Corporation (“Old Mirant”), and various subsidiaries of Mirant, including the Company and its subsidiaries, if approved by final order in the Chapter 11 proceedings, would result in the distribution of up to 18 million of the reserved shares to Pepco, as described below in Pepco Litigation. Under the terms of the Plan, to the extent other such unresolved claims are resolved now that the Company has emerged from bankruptcy, the claimants will be paid from the reserved shares on the same basis as if they had been paid when the Plan became effective. That means that their allowed claims will receive the same pro rata distributions of Mirant common stock, cash, or both common stock and cash as previously allowed claims in accordance with the terms of the Plan. To the extent the aggregate amount of the payouts determined to be due with respect to such 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 shareholders, 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.

Pepco Litigation

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 includes as parties Pepco, the Company and various of its subsidiaries causes the Company and its subsidiaries that are 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 have sought to reject the APSA, the Back-to-Back Agreement, and the Assignment and Assumption Agreement, and the rejection motions have not been resolved. 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 are to be performed by Mirant Power Purchase, whose performance is guaranteed by Mirant. If any of the agreements is successfully rejected, the obligations of Mirant Power Purchase and Mirant’s guarantee obligations terminate with respect to that agreement, and Pepco would be entitled to a claim in the Chapter 11 proceedings for any resulting damages. That claim would then be addressed under the terms of the Plan. If the Bankruptcy Court were to conclude that the Assignment and Assumption Agreement imposed liability upon the Company and its subsidiaries for the obligations under the Back-to-Back Agreement and the Back-to-Back Agreement were to be rejected, the resulting rejection damages claim could result in a claim in the Chapter 11 proceedings against the Company and its subsidiaries but any such claim would be reduced by the amount recovered by Pepco on its comparable claim against Mirant.

On May 30, 2006, Mirant, Mirant Power Purchase, Old Mirant, various subsidiaries of Mirant (including the Company and its subsidiaries), and a trust established pursuant to the Plan to which ownership of Old Mirant and Mirant Americas Energy Marketing was transferred (collectively the “Mirant Settling Parties”) entered into a Settlement Agreement and Release (the “Settlement Agreement”) with Pepco and various affiliates of Pepco (collectively the “Pepco Settling Parties”). Once it becomes effective, the Settlement Agreement will fully resolve the contract rejection motions that remain pending in the bankruptcy proceedings, as well as other matters currently disputed between Pepco and Mirant and its subsidiaries. The Pepco Settling Parties and the Mirant Settling Parties will release each other from all claims known as of May 30, 2006, including the fraudulent transfer claims brought by Old Mirant and several of its subsidiaries against Pepco in July 2005. The Settlement Agreement will become effective once it has been approved by the Bankruptcy Court and that approval order has become a final order no longer subject to appeal. On August 9, 2006, the Bankruptcy Court entered an order approving the Settlement Agreement, but certain holders of unsecured claims against Old Mirant in the bankruptcy proceedings appealed that order. On December 26, 2006, the United States District Court for the Northern District of Texas affirmed the bankruptcy court order approving the settlement, but the claims holders have appealed that ruling to the United States Court of Appeals for the Fifth Circuit, and the approval order has not yet become a final order.

rejected pursuant to the terms of the Settlement Agreement, 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. If, however, Mirant elects to have the Back-to-Back Agreement assumed and assigned to Mirant Power Purchase under the conditions set out in the Settlement Agreement, then the Settlement Agreement provides that nothing in its terms prejudices the argument currently being made by Pepco in the contract rejection proceedings that the APSA, the Back-to-Back Agreement, and the Ancillary Agreements constitute a single non-severable agreement, the material breach of which would entitle Pepco to suspend or terminate its performance thereunder, or any defense of Mirant and its subsidiaries to such an argument by Pepco.

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 plant in Virginia and the Chalk Point, Dickerson and Morgantown plants in Maryland. The requested information concerns the period of operations that predates the Company’s and its subsidiaries’ ownership and lease of those plants. 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 plants. If a violation is determined to have occurred at any of the plants, the Company or its subsidiary owning or leasing the plant may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. The Company or its subsidiaries will be installing a variety of emissions control equipment on the Chalk Point, Dickerson and Morgantown plants in Maryland to comply with the Maryland Healthy Air Act, but that equipment may not include all of the emissions control equipment that could be required if a violation of the EPA’s NSR regulations is determined to have occurred at one or more of those plants. If such a violation is determined to have occurred after the Company or its subsidiaries acquired or leased the plants 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 plant 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 plant, 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 plants.

On September 27, 2004, the Company, Mirant Potomac River, the Virginia DEQ, the MDE, the DOJ and the EPA entered into, and filed for approval with the United States District Court for the Eastern District of Virginia, a proposed consent decree (the “Original Consent Decree”) that, if approved, would have resolved Mirant Potomac River’s potential liability for matters addressed in the NOVs previously issued by the Virginia DEQ and the EPA. The Original Consent Decree would have required Mirant Potomac River and the Company to (1) install pollution control equipment at the Potomac River plant in Virginia and at the Morgantown plant in Maryland leased by the Company, (2) comply with declining system-wide ozone season NOx emissions caps from 2004 through 2010, (3) comply with system-wide annual NOx emissions caps starting in 2004, (4) meet seasonal system average emissions rate targets in 2008 and (5) pay civil penalties and perform supplemental environmental projects in and around the Potomac River plant expected to achieve additional environmental benefits. Except for the installation of the controls planned for the Potomac River units and the installation of selective catalytic reduction (“SCR”) or equivalent technology at the Company’s Morgantown units 1 and 2 in 2007 and 2008, the Original Consent Decree would not have obligated the Company to install specifically designated technology, but rather to reduce emissions sufficiently to meet the various NOx caps. Moreover, as to the required installations of SCRs at Morgantown, the Company may choose not to install the technology by the applicable deadlines and leave the units off either permanently or until such time as the SCRs are installed. The Original Consent Decree was subject to the approval of the district court and the Bankruptcy Court. As described below, the Original Consent Decree was not approved and the parties have filed an amended proposed consent decree that supersedes the Original Consent Decree.

Decree provides that if the Company rejects or otherwise loses one or more of its leasehold interests in the Morgantown and Dickerson plants and ceases to operate one or both of the plants, the Company, Mirant Chalk Point and/or Mirant Potomac will (i) provide the EPA, Virginia DEQ and the MDE with the written agreement of the new owner or operator of the affected plant or plants to be bound by the obligations of the Amended Consent Decree and (ii) where the affected plant is the Morgantown plant, offer to any and all prospective owners and/or operators of the Morgantown plant to pay for completion of engineering, construction and installation of the SCRs required by the Amended Consent Decree. If the new owner or operator of the affected plant or plants does not agree to be bound by the obligations of the Amended Consent Decree, it requires the Company, Mirant Chalk Point and/or Mirant Potomac to install an alternative suite of environmental controls at the plants they continue to own. The district court and the Bankruptcy Court must approve the Amended Consent Decree for it to become effective. The City of Alexandria and certain individuals and organizations have opposed entry of the Amended Consent Order. The Bankruptcy Court approved the Amended Consent Decree on June 1, 2006. The district court has not yet approved the Amended Consent Decree.

On April 26, 2006, the Company and the MDE entered into an agreement to allow the Company to implement the consent decree with respect to the Morgantown plant, if the consent decree receives the necessary approvals. Under the agreement, the Company agreed to certain ammonia and particulate matter emissions limits and to submit testing results to the MDE.

The computer modeling analysis predicted that emissions from the Potomac River plant have the potential to contribute to localized, modeled instances of exceedances of the NAAQS for SO2, NO2 and PM10 under certain conditions. Based on those results, the Virginia DEQ issued a directive to Mirant Potomac River on August 19, 2005, to undertake immediately such action as was necessary to ensure protection of human health and the environment and eliminate NAAQS violations. On August 24, 2005, power production at all five units of the Potomac River generating facility was temporarily halted in response to the directive from the Virginia DEQ. On August 25, 2005, the District of Columbia Public Service Commission filed an emergency petition and complaint with the FERC and the DOE to prevent the shutdown of the Potomac River facility. The matter remains pending before the FERC and the DOE. On December 20, 2005, due to a determination by the DOE that an emergency situation existed with respect to the reliability of the supply of electricity to central Washington, D.C., the DOE ordered Mirant Potomac River to generate electricity at the Potomac River generating facility, as requested by PJM, during any period in which one or both of the transmission lines serving the central Washington, D.C. area are out of service due to a planned or unplanned outage. In addition, the DOE ordered Mirant Potomac River, at all other times, for electric reliability purposes, to keep as many units in operation as possible and to reduce the start-up time of units not in operation without contributing to any NAAQS exceedances. The DOE required Mirant Potomac River to submit a plan, on or before December 30, 2005, that met these requirements. The order further provides that Mirant Potomac River and its customers should agree to mutually satisfactory terms for any costs incurred by it under this order or just and reasonable terms shall be established by a supplemental order. Certain parties filed for rehearing of the DOE order, and on February 17, 2006, the DOE issued an order granting rehearing solely for purposes of considering further the rehearing requests. Mirant Potomac River submitted an operating plan in accordance with the order. On January 4, 2006, the DOE issued an interim response to Mirant Potomac River’s operating plan

authorizing operation of the units of the Potomac River generating facility on a reduced basis, but making it possible to bring the entire plant into service within approximately 28 hours when necessary for reliability purposes. The DOE’s order expires July 1, 2007, but Mirant Potomac River expects it will be able to continue to operate these units after that expiration.

On June 1, 2006, Mirant Potomac River and the EPA executed an ACO by Consent to resolve the EPA’s allegations that Mirant Potomac River violated the Clean Air Act by not immediately shutting down all units at the Potomac River facility upon receipt of the Virginia DEQ’s August 19, 2005, letter and to assure an acceptable level of reliability to the District of Columbia. The ACO (i) specifies certain operating scenarios and SO2 emissions limits for the Potomac River facility, which scenarios and limits take into account whether one or both of the 230kV transmission lines serving Washington, D.C. are out of service; (ii) requires the operation of trona injection units to reduce SO2 emissions; and (iii) requires Mirant Potomac River to undertake a model evaluation study to predict ambient air quality impacts from the facility’s operations. In accordance with the specified operating scenarios, the ACO permits the facility to operate using a daily predictive modeling protocol. This protocol allows Mirant Potomac River to schedule the facility’s level of operations based on whether computer modeling predicts a NAAQS exceedance, based on weather and certain operating parameters. On June 2, 2006, the DOE issued a letter modifying its January 6, 2006, order to direct Mirant Potomac River to comply with the ACO in order to ensure adequate electric reliability to the District of Columbia. Mirant Potomac River is operating the Potomac River facility in accordance with the ACO and has been able to operate all five units of the facility most of the time under the ACO. This ACO expires in June 2007.

City of Alexandria Nuisance Suit. On October 7, 2005, the City of Alexandria filed a suit against Mirant Potomac River and the Company in the Circuit Court for the City of Alexandria. The suit asserted nuisance claims, alleging that the Potomac River plant’s emissions of coal dust, flyash, NOx, SO2, particulate matter, hydrogen chloride, hydrogen fluoride, mercury and oil pose a health risk to the surrounding community and harm property owned by the City. The City sought injunctive relief, damages and attorneys’ fees. On February 17, 2006, the City amended its complaint to add additional allegations in support of its nuisance claims relating to noise and lighting, interruption of traffic flow by trains delivering coal to the Potomac River plant, particulate matter from the transport and storage of coal and flyash, and potential coal leachate into the soil and groundwater from the coal pile. On December 13, 2006, the City withdrew the suit.

notice on the grounds that the notice and any claim for civil penalties or other monetary relief for alleged violations occurring before January 3, 2006, violated the discharge of claims and causes of action granted Mirant Chalk Point under the Plan. On August 14, 2006, the Bankruptcy Court entered an order agreed to by the parties enjoining the four organizations from seeking monetary damages for any alleged violations occurring on or before January 3, 2006. As part of that order, the organizations agreed not to file a complaint initiating litigation concerning the alleged violations until August 30, 2006.

On August 30, 2006, the four environmental organizations filed suit in the United States District Court for the District of Maryland against Mirant, the Company, and Mirant Chalk Point asserting that emissions from Chalk Point units 3 and 4 had violated opacity limits set under the Clean Air Act and state law on numerous occasions since January 4, 2006. The plaintiffs sought an injunction prohibiting further violations by Chalk Point units 3 and 4 of the Clean Air Act, civil penalties of up to $32,500 for each violation of the Clean Air Act, additional civil penalties for mitigation projects, and attorneys’ fees. On September 22, 2006, the Mirant defendants filed a motion to dismiss, arguing that under the Clean Air Act the MDE’s prosecution of the same alleged violations in the Maryland state court proceeding and their resolution through the Consent Decree barred the plaintiffs’ suit. On January 3, 2007, the district court granted the motion and dismissed the complaint, and that order has become final.

City of Alexandria Zoning Action

On January 18, 2005, Mirant Potomac River and the Company filed a complaint against the City of Alexandria and the City Council in the Circuit Court for the City of Alexandria. The complaint sought to overturn the actions taken by the City Council on December 18, 2004, changing the zoning status of Mirant Potomac River’s generating plant and approving revocation of the 1989 SUPs, on the grounds that those actions violated federal, state and city laws. The complaint asserted, among other things, that the actions taken by the City Council constituted unlawful spot zoning, were arbitrary and capricious, constituted an unlawful attempt by the City Council to regulate emissions from the plant, and violated Mirant Potomac River’s due process rights. Mirant Potomac River and the Company requested the court to enjoin the City of Alexandria and the City Council from taking any enforcement action against Mirant Potomac River or from requiring it to obtain a special use permit for the continued operation of its generating plant. On January 18, 2006, the court issued an oral ruling following a trial that the City of Alexandria acted unreasonably and arbitrarily in changing the zoning status of Mirant Potomac River’s generating plant and in revoking the 1989 SUPs. On February 24, 2006, the court entered judgment in favor of Mirant Potomac River and Mirant Mid-Atlantic declaring the change in the zoning status of Mirant Potomac River’s generating plant adopted December 18, 2004, to be invalid and vacating the City Council’s revocation of the 1989 SUPs. The City of Alexandria filed a petition with the Virginia Supreme Court seeking to appeal this judgment, and on September 11, 2006, the Virginia Supreme Court agreed to hear the appeal.

Pepco Assertion of Breach of Local Area Support Agreement

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.

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 44 through 74 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 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)
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)
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*	Settlement Agreement and Release dated as of May 30, 2006 by and among the Mirant Settling Parties and the Pepco Settling Parties (Designated on Form 8-K filed May 30, 2006 as Exhibit 10.1)
10	.2(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	.2(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	.2(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	.3(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	.3(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	.4(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)
10	.4(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	.5(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	.5(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	.6(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	.6(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	.7(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	.7(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	.8(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	.8(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	.9(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	.9(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	.10*	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	.11*	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	.12*	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	.13(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)
10	.13(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	.14(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	.14(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	.15(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	.15(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	.16(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	.16(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	.17(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	.17(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)
10	.18*	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 filed March 31, 2006 as Exhibit 10.17)
10	.19*	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 filed March 31, 2006 as Exhibit 10.18)
10	.20*	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 filed March 31, 2006 as Exhibit 10.19)
10	.21*	Administrative Services Agreement dated as of January 3, 2006 between Mirant Mid-Atlantic, LLC and Mirant Services, LLC (Designated on Form 10-K filed March 31, 2006 as Exhibit 10.20)
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.

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)

Name	Age		Position
Edward R. Muller		55	Board Manager as of January 3, 2006. Director, Chairman, President and Chief Executive Officer since September 2005 of Mirant. Mr. Muller is also a Board Manager of Mirant Americas Generation. President and Chief Executive Officer of Edison Mission Energy, a California-based independent power producer from 1993-2000. He is also a director of Global Santa Fe Corp.
James V. Iaco		62	Board Manager as of January 3, 2006. Executive Vice President and Chief Financial Officer of Mirant since November 2005. Mr. Iaco is also a Board Manager of Mirant Americas Generation. Prior to joining Mirant, was a private investor with numerous businesses and real estate ventures from 2000-2005. He served as Senior Vice President and President, Americas’ Division of Edison Mission Energy (1998-2000) and Senior Vice President and Chief Financial Officer, Edison Mission Energy (1994-1998).
Robert M. Edgell		60	Chairman of the Board of Mirant Americas Generations, Mirant North America and Mirant Mid-Atlantic as of January 9, 2006. Mr. Edgell is Executive Vice President and U.S. Region Head of Mirant since 2006. He was employed as Executive Vice President and General Manager of the Asia-Pacific Region for Edison Mission Energy from 1996-2000.

Name	Age		Position
Robert E. Driscoll		57	Chief Executive Officer of Mirant Americas Generation and Mirant Mid-Atlantic as of January 9, 2006. Mr. Driscoll is Senior Vice President and Head of Asset Management, U.S. Region of Mirant. 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			46			Senior Vice President, Chief Financial Officer and Treasurer of Mirant Mid-Atlantic and Mirant Americas Generation since November 2002. Mr. Holden has also been Senior Vice President and Treasurer of Mirant since April 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			55			Senior Vice President, Controller and Principal Accounting Officer of Mirant, Mirant Americas Generation and Mirant Mid-Atlantic. 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).

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

		Page
	Glossary of Certain Defined Terms		i-iv
	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		20
Item 4.	Submission of Matters to a Vote of Security Holders		28
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		29
Item 6.	Selected Financial Data		29
Item 7.	Management’s Discussion and Analysis of Results of Operations and Financial Condition		29
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		42
Item 8.	Financial Statements and Supplementary Data		44
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		75
Item 9A.	Controls and Procedures		75
Item 9B.	Other Information		75
	PART III
Item 10.	Directors and Executive Officers of the Registrant		76
Item 11.	Executive Compensation		78
Item 12.	Security Ownership of Certain Beneficial Owners and Management		78
Item 13.	Certain Relationships and Related Transactions		78
Item 14.	Principal Accountant Fees and Services		78
	PART IV
Item 15.	Exhibits and Financial Statements		79

	Member’s Interest				Preferred Stock in Affiliate				Investment by Mirant
	(in millions)
Balance, December 31, 2003		$	—			$	—			$	2,850
Net income		—				—				106
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	)		$	—

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

Name of Company				Jurisdiction of Organization
Mirant Mid-Atlantic, LLC				Delaware
Mirant Chalk Point, LLC				Delaware
Mirant Potomac River, LLC				Delaware
Mirant MD Ash Management, LLC				Delaware
Mirant Piney Point, LLC				Delaware

By:	/s/ J. WILLIAM HOLDEN, III
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

Name:		/s/ J. WILLIAM HOLDEN, III
		Senior Vice President and Chief Financial Officer