PART I

Item 1. Business

Overview

Mirant Americas Generation is a national independent power provider and an indirect wholly-owned subsidiary of Mirant. We generate revenue primarily through the production of electricity. 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 Mirant’s emergence from bankruptcy protection on January 3, 2006. Old Mirant was then renamed and transferred to a trust, which 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 our indirect wholly-owned subsidiary, Mirant Mid-Atlantic, and its interest in Mirant Zeeland and in Mirant Americas Energy Marketing, Mirant Americas Development, Inc., Mirant Americas Production Company, Mirant Americas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas Retail Energy Marketing, LP, and Mirant Americas Gas Marketing I-XV, LLCs (collectively, the “Trading Debtors”) to Mirant North America. All of the contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.” On January 31, 2006, the trading and marketing business of the Trading Debtors was transferred to Mirant Energy Trading, a wholly-owned subsidiary of Mirant North America. After these transfers took place, the Trading Debtors were transferred to a trust created under the Plan that is not affiliated with us.

The accompanying consolidated financial statements include the accounts of Mirant Americas Generation. The accompanying 2005 and 2004 combined financial statements present the results of operations and cash flows of the Company based on the assets, liabilities and operations of the predecessor Mirant Contributed Subsidiaries. The effects of the Plan are reflected as of December 31, 2005.

We produce and sell substantially all of the output from our generating facilities in the forward and spot markets and the remainder under contracts with third parties. We use derivative financial instruments, such as commodity forwards, futures, options and swaps to manage our exposure to fluctuations in electric energy and fuel prices. We are a Delaware limited liability company that owns or leases 12,099 MW of electric generation capacity. We operate 72 generating units at 20 plants serving customers located near major metropolitan load centers in Maryland, California, New York, Michigan, Texas, Massachusetts and Virginia.

In the third quarter of 2006, Mirant commenced auction processes to sell certain of its natural gas-fired plants, including our Zeeland (903 MW) and Bosque (546 MW) plants. On January 15, 2007, we entered into a definitive purchase and sale agreement with a subsidiary of LS Power Equity Partners I, L.P., LS Power Equity Partners II, L.P. and certain other affiliated funds, (collectively, “LS Power”), for the sale of our Zeeland and Bosque natural gas-fired plants. The net proceeds from the sales are expected to be approximately $500 million, after transaction costs. The transaction is expected to close in the second quarter of 2007 after the satisfaction of certain customary conditions.

After giving effect to the aforementioned sales, our continuing operations of 10,650 MW will consist of the ownership, long-term lease and operation of power generation facilities located in the Mid-Atlantic and Northeast regions of the United States and in California, and energy trading and marketing operations in Atlanta, Georgia.

We have a number of service agreements for labor and administrative services with Mirant Services. In addition, Mirant Energy Trading, and previously Mirant Americas Energy Marketing, provides services

to other Mirant affiliates related to the sale of electric power and the procurement of fuel and emissions allowances. These agreements are discussed further in Note 9 of our consolidated and combined financial statements.

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, 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.

Business Segments

Previously, we managed our business as one operating segment. In 2006, Mirant commenced auction processes to dispose of certain natural gas-fired plants, including our Zeeland and Bosque plants. The planned sales have resulted in the reclassification of the revenues and expenses of these assets to discontinued operations and the reclassification of the related assets and liabilities to held for sale for all periods presented. In the fourth quarter of 2006, we re-evaluated the business segments of our continuing operations. As a result, we now have four operating segments: Mid-Atlantic, Northeast, California and Other Operations. Other Operations includes proprietary trading and fuel oil management activities. For periods prior to 2006, Other Operations includes gains and losses related to a contractual arrangement entered into with Pepco with respect to certain PPAs, including Pepco’s long-term PPAs with Panda and Ohio Edison (the “Back-to-Back Agreement”). For selected financial information about our business segments see Note 16 to our consolidated and combined financial statements contained elsewhere in this report. See “Item 2. Properties” for a complete list of our assets.

The table below summarizes selected financial information for our business segments, after giving effect to the pending sales, for the year ended December 31, 2006 (dollars in millions):

	Revenues				%		Gross Margin		%		Operating Income				%
Business Segment:
Mid-Atlantic		$	1,901		58	%	$	1,318	67	%		$	918		78	%
Northeast		827			25	%	358		18	%		128			11	%
California		171			5	%	115		6	%		39			3	%
Other Operations		3,262			100	%	131		7	%		98			8	%
Eliminations		(2,888		)	(88	)%	38		2	%		(6		)	—
Total Continuing Operations		$	3,273		100	%	$	1,960	100	%		$	1,177		100	%

Overview

Our core business is the production and sale of electrical energy, electrical capacity (the ability to produce electricity on demand) and ancillary services (services that are ancillary to transmission services). Our customers are ISOs, utilities, municipal systems, aggregators, electric cooperative utilities, producers, generators, marketers and large industrial customers.

Ownership and Operation of Electricity Generation Assets

As of December 31, 2006, our continuing operations consist of owned or leased generation facilities with 10,650 MW of generating capacity. Our generating portfolio is diversified across fuel types, power markets and dispatch types and serves customers located near many major metropolitan load centers. Our total generation capacity includes approximately 32% baseload units, 48% intermediate units and 20% peaking units.

Commercial Operations

Our commercial operations consist primarily of procuring fuel, dispatching electricity, hedging the production and sale of electricity by our generating facilities, fuel oil management and providing logistical support for the operation of our facilities (for example, by procuring transportation for coal). We often sell the electricity we produce into the wholesale market at prices in effect at the time we produce it (“spot price”). Those prices are volatile, however, and in order to reduce the risk of that volatility and achieve

more predictable financial results, it is our strategy to enter into hedges—forward sales of electricity into the wholesale market and purchases of fuel and emissions allowances to allow us to produce and sell the electricity—for different periods of time. We procure these hedges in OTC transactions or exchanges where electricity, fuel and emissions allowances are broadly traded, or through specific transactions with buyers and sellers, using futures, forwards, swaps and options. We also sell capacity and ancillary services where there are markets for such products and when it is economic to do so. In addition to selling the electricity we produce and buying the fuel and emissions allowances we need to produce electricity (“asset management”), we buy and sell some electricity that we do not produce and some fuel and emissions allowances that we do not need to produce electricity (“proprietary trading”). Proprietary trading is a small part of our commercial operations, which we do in order to gain information about the markets to support our asset management and to take advantage of selected opportunities that we may identify from time to time. All of our commercial activities are governed by a comprehensive Risk Management Policy, which requires that our hedging activities with respect to our assets be risk-reducing and sets limits on the size of trading positions and VaR in our proprietary trading activities.

We use dispatch models to make daily decisions regarding the quantity and price of the power our facilities will generate and sell into the markets. We bid the energy from our generation facilities into the day-ahead energy market and sell ancillary services through the ISO markets. We work with the ISOs and RTOs in real time to ensure that our generation facilities are dispatched economically to meet the reliability needs of the market.

We economically hedge a substantial portion of our Mid-Atlantic coal-fired baseload generation and certain of our Northeast coal, gas and oil-fired generation through OTC transactions. However, we generally do not hedge most of our intermediate and peaking units. In 2006 and through February 26, 2007, our Mirant Mid-Atlantic subsidiary entered into financial swap transactions resulting in Mirant Mid-Atlantic being economically hedged for approximately 92%, 93%, 97% and 38% of its 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 of Mirant Mid-Atlantic 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 84%, 48%, 36% and 14% for 2007, 2008, 2009 and 2010, respectively. The corresponding fuel hedges are approximately 82%, 27%, 15% and 0% for 2007, 2008, 2009 and 2010, respectively.

While OTC transactions make up a substantial portion of our economic hedge portfolio, Mirant Energy Trading also sells non-standard, structured products to customers. In addition to energy, these products typically include capacity, ancillary services and other energy products. We view these transactions as a method of mitigating the risk of certain portions of our business that are not easy to economically hedge in the OTC market. Typically, we are able to sell these products at a higher premium than standard products. Additionally, we have facilities operating under long-term contracted capacity and RMR contracts. At December 31, 2006, our contracted capacity pursuant to these agreements was 2,347 MW with terms expiring through October 2011.

We enter into contracts of varying terms to secure appropriate quantities of fuel that meet the varying specifications of our generating facilities. For our coal-fired generation facilities, we purchase coal from a variety of suppliers under contracts with terms of varying lengths, some of which extend to 2009. For our oil-fired units, fuel typically is purchased under short-term contracts linked to a transparent oil index price. For our gas-fired units, fuel typically is purchased under short-term contracts with a variety of suppliers on a day-ahead or monthly basis.

Our coal supply primarily comes from the Central Appalachian and Northern Appalachian coal regions. All of our coal is delivered by rail, although we are in the process of permitting a barge unloading facility at our Morgantown station that will enable us to receive coal by an alternative transportation

source beginning in 2008. We monitor coal supply and delivery logistics carefully, and, despite occasional interruptions of scheduled deliveries, to date we have managed to avoid any significant impact to our operations. We maintain an inventory of coal at our coal-fired facilities for this purpose. Interruptions of scheduled deliveries can occur because of supply disruptions due to strikes or other reasons or as a result of rail system disruptions due to weather or other reasons.

Mid-Atlantic Region

We own or lease four generation facilities in the Mid-Atlantic region with a total generation capacity of 5,256 MW: Chalk Point, Morgantown, Dickerson and Potomac River. Our Mid-Atlantic region had a combined 2006 capacity factor (average percentage of full capacity used over a year) of 36%. Our Mid-Atlantic 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 Mid-Atlantic 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 the Mid-Atlantic assets.

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.

Northeast Region

We own generating facilities in the Northeast region consisting of 3,047 MW of capacity. Our Northeast region had a combined 2006 capacity factor of 17%. The Northeast region is comprised of our assets located in New York and New England. The subsidiaries that own our New York facilities remain in bankruptcy. For further information, see “Item 3. Legal Proceedings.” Generation is sold from our Northeast facilities through a combination of bilateral contracts, spot market transactions and structured transactions.

New York. Our New York generating facilities were acquired from Orange and Rockland and Consolidated Edison Company of New York, Inc. in June 1999. The New York generating facilities consist of the Bowline and Lovett facilities and various smaller generating facilities comprising a total of 1,656 MW of capacity. The Bowline facility is a 1,125 MW dual-fueled (natural gas and oil) facility comprised of two intermediate/peaking units. The Lovett facility consists of two baseload units capable of burning coal and gas comprising a total of 348 MW and a peaking unit capable of burning gas or oil comprising 63 MW. The smaller New York generating facilities have a total capacity of 120 MW and consist of the Hillburn and Shoemaker facilities, which each contain a single peaking unit capable of running on natural gas or jet fuel, and the Mongaup 1-4, Swinging Bridge 1-2 and Rio 1-2 facilities, which each contain a hydroelectric intermediate unit. We also had an operational interest in the Grahamsville facility, pursuant to a sublease between Orange and Rockland and Mirant NY-Gen. On October 31, 2006, we transferred the Grahamsville facility to Orange and Rockland for transfer to the City of New York. The capacity, energy and ancillary services from our New York generating units are sold into the bilateral markets and into the markets administered by the NYISO through Mirant Energy Trading. For a discussion of NYISO, see “Regulatory Environment” below.

Our current plan is to retire units 3 and 5 at the Lovett facility by April 30, 2007, and the remaining unit by April 30, 2008, as required under the terms of a consent decree entered into on June 11, 2003, to resolve issues related to NSR regulations promulgated under the Clean Air Act (the “2003 Consent Decree”) if certain environmental controls are not added to the two units of the Lovett facility that burn coal. We are also considering scenarios that allow continued operations past April 2007 and April 2008 as we continue to work with the State of New York and other parties to achieve a solution related to environmental controls and to allow Lovett to continue to contribute to the reliability of the electric system of the State of New York. In order for the facility to remain viable on a long-term basis, we need to accomplish two primary tasks. First, we need to reach agreement with the State of New York on amendments to the 2003 Consent Decree that would address the installation of environmental equipment. Second, because current market conditions do not allow Mirant Lovett to recover the necessary returns to fund the installation of environmental controls specified under the 2003 Consent Decree, we are seeking an agreement with a third party assuring us of enough revenue to justify the required capital expenditures. Our view is that the Lovett facility is necessary to the provision of reliable electricity to the Lower Hudson Valley and other areas within the New York Control Area.

In the fourth quarter of 2006, the Bankruptcy Court approved a settlement of disputed property taxes among Mirant Bowline, Mirant Lovett, Hudson Valley Gas and various New York tax jurisdictions. The settlement resolves pending disputes regarding refunds sought by us for property taxes paid for 1995 through 2003 and unpaid taxes assessed for 2003 through 2006. Under the settlement, in February 2007 we received refunds totaling approximately $163 million for 1995 through 2002, and paid unpaid taxes of approximately $115 million for 2003 through 2006, resulting in receipt of a net cash amount of $48 million. As a result of the refund and the reduction in unpaid taxes under the settlement, we recognized a gain of approximately $244 million in the fourth quarter of 2006. Of the $244 million gain recognized, $163 million is included in reorganization items, net, and $94 million is a reduction in operations and maintenance expense in the consolidated statement of operations. These amounts are partially offset by $13 million in interest expense.

In May 2005, a sinkhole was discovered in the dam of our Swinging Bridge facility. In response, Mirant NY-Gen filled this sinkhole, inspected for damage the dam’s slopes and the enclosed pipe that delivers water from the reservoir to the generator, drew down the lake level and cleaned the diversion tunnel. Mirant NY-Gen’s analysis indicates that the most probable cause of the sinkhole was erosion of soil comprising the dam from water flow through a hole in the pipe that delivers water from the reservoir to the generator. The dam is stabilized, and Mirant NY-Gen is performing additional remediation repairs. By letter dated June 14, 2006, the FERC authorized Mirant NY-Gen to proceed with its remediation plan for the sinkhole. The FERC has also concurred with the results of Mirant NY-Gen’s flood study for its Swinging Bridge, Rio and Mongaup generation facilities, which study concluded that no additional remediation is required. On June 29, 2006, the Bankruptcy Court authorized Mirant NY-Gen to proceed with implementation of the remediation plan. The current estimated cost to remediate the dam at Swinging Bridge is approximately $29 million, of which approximately $22 million had been incurred through December 31, 2006. Mirant NY-Gen currently expects to recover insurance proceeds for a portion of these repair costs. The Bankruptcy Court has approved a debtor-in-possession loan to Mirant NY-Gen from Mirant Americas under which Mirant Americas, subject to certain conditions, would lend up to $16.5 million to Mirant NY-Gen to provide funding for the repairs on the Swinging Bridge dam.

On January 26, 2007, Mirant New York, Mirant Bowline, and Hudson Valley Gas (collectively the “Emerging New York Entities”) filed a Supplemental Joint Chapter 11 Plan of Reorganization of the Emerging New York Entities (the “Supplemental Plan”) with the Bankruptcy Court. For more detail concerning the Supplemental Plan, see “Item 3. Legal Proceedings, Chapter 11 Proceedings.”

On January 31, 2007, Mirant New York entered into an agreement to sell Mirant NY-Gen, which owns the Hillburn and Shoemaker gas turbine facilities and the Swinging Bridge, Rio and Mongaup

hydroelectric generating facilities to Alliance Energy, LLC (the “Alliance Sale”). The sales price of approximately $5 million is subject to adjustments for working capital and certain dam remediation efforts that are ongoing at the Swinging Bridge facility. The Bankruptcy Court approved the Alliance Sale on March 8, 2007. The transaction is expected to close in the second quarter of 2007. On February 15, 2007, Mirant NY-Gen filed its proposed Chapter 11 Plan of Reorganization (the “Mirant NY-Gen Plan”). For more detail concerning the Mirant NY-Gen Plan, see “Item 3. Legal Proceedings, Chapter 11 Proceedings.”

New England. Our New England generating facilities, with a total capacity of 1,391 MW, were acquired from subsidiaries of Commonwealth Energy System and Eastern Utilities Associates in December 1998. The New England generating facilities consist of the Canal station, the Kendall station, the Martha’s Vineyard diesels and an interest in the Wyman unit 4 facility. The Canal and Kendall facilities, located in close proximity to Boston, consist of 1,112 MW and 256 MW of generating capacity, respectively, and are designed to operate during periods of intermediate and peak demand. The Kendall facility is a combined cycle facility which produces both steam and electricity for sale. Both the Canal and Kendall facilities possess the ability to burn both natural gas and fuel oil. The Martha’s Vineyard diesels, with 14 MW of capacity, supply electricity on the island of Martha’s Vineyard during periods of high demand or in the event of a transmission interruption. The Wyman unit 4 interest is an approximate 1.4% ownership interest (equivalent to 9 MW) in the 614 MW Wyman unit 4 located on Cousin’s Island, Yarmouth, Maine. Wyman unit 4 is primarily owned and operated by the Florida Power and Light Group.

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

We had determined that market fundamentals in NEPOOL did not permit us to operate the Kendall facility on an economical basis as a merchant facility. We therefore had planned to shut down, at least temporarily, the Kendall facility from January 2005 through December 2007, with the possibility of restarting operations as early as January 2008. However, the ISO-NE determined that part of the capacity of the Kendall facility was needed for reliability and proposed an RMR agreement with a term lasting until the earlier of (1) the date a locational installed capacity cost recovery mechanism applicable to the Kendall facility is in place or (2) 120-days after we are provided written notice. We entered into and received FERC approval for an agreement with NSTAR and ISO-NE, which included the RMR agreement. On December 28, 2006, ISO-NE provided notice that the RMR agreement shall terminate effective May 1, 2007. A locational installed capacity market has been implemented in New England and, as a result and coupled with additional steam sales, there are no plans to shut down the Kendall facility in 2007.

California

Our California facilities, with a total capacity of 2,347 MW, are primarily gas-fired generating facilities and consist of the Pittsburg, Contra Costa and Potrero facilities, which have generation capacity of 1,311 MW, 674 MW and 362 MW, respectively. Our California facilities had a 2006 capacity factor of 6%.

The Pittsburg and Contra Costa facilities are natural gas facilities and both generate electricity by using gas-fired steam boilers. They are located in Contra Costa County, approximately ten miles apart along the Sacramento/San Joaquin River. The Potrero facility, located in the City of San Francisco, has one natural gas-fired intermediate steam boiler from which it generates electricity and three oil-fired peaking distillate fueled combustion turbines.

Through the end of 2006, the majority of our California assets were subject to RMR arrangements with the CAISO. These agreements are described further under “Regulatory Environment” below. Our California subsidiaries had the largest portfolio of units that operated under RMR arrangements in California, reflecting that the location of these units is key to electric system reliability. Pittsburg unit 7 and Contra Costa unit 6 were not subject to an RMR arrangement, and thus functioned solely as merchant

facilities in the CAISO. In 2006, we either sold the output of Pittsburg unit 7 and Contra Costa unit 6 into the market through bilateral transactions with utilities and other merchant generators, or dispatched the units in the CAISO clearing markets.

On July 28, 2006, we signed two tolling agreements with PG&E to provide electricity from our natural gas-fired units at Pittsburg and Contra Costa, including Pittsburg unit 7 and Contra Costa unit 6. The agreements are for 100% of the capacity from these assets, approximately 2,000 MW. The contracts have varying tenors ranging from one to four years, and include capacity of 1,985 MW for 2007, 2008 and 2009, 1,303 MW for 2010 and 674 MW for 2011. We will receive monthly capacity payments with bonuses and/or penalties based on guaranteed heat rate and availability tolerances. As a result of these contracts, the Pittsburg and Contra Costa units are no longer subject to the RMR agreements. Potrero units 3-6 continue to be subject to the RMR arrangements as described.

On January 14, 2005, we and certain of our subsidiaries entered into a Settlement and Release of Claims Agreement (the “California Settlement”) with PG&E, SCE, San Diego Gas and Electric Company, the CPUC, the Cal DWR, the EOB and the Attorney General of the State of California and with the Office of Market Oversight and Investigations of the FERC. Pursuant to the settlement agreement that became effective in April 2005, the partially constructed Contra Costa unit 8 project, which is a planned 530 MW combined cycle generating facility, and related equipment (collectively, the “CC8 Assets”) were transferred to PG&E on November 29, 2006. Mirant Delta received $70 million that under the terms of the settlement had been held in an escrow account to be paid to PG&E if the Contra Costa 8 project was not transferred to it by June 30, 2008. We recognized a gain of $27 million in the fourth quarter of 2006 as a result of these transfers.

Discontinued Operations

The Zeeland facility, located in Zeeland, Michigan, is comprised of simple cycle units totaling 327 MW of capacity and a 576 MW combined cycle facility (903 MW of total capacity). The Zeeland facility is interconnected with the International Transmission Company, which is a member of the MISO and operates under the East Central Area Reliability Coordination Agreement.

The Bosque facility, located in Laguna Park, Texas, consists of a gas-fired combustion turbine with a corresponding steam turbine with a capacity of 239 MW that is available to serve baseload and intermediate demand. Additionally, Bosque units 1 and 2 are gas-fired peaking facilities with a total capacity of 307 MW. The Bosque facility operates in the ERCOT market. For a discussion of ERCOT, see “Regulatory Environment” below.

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. Any of our subsidiaries that owns a generating facility selling at wholesale or that markets electricity at wholesale outside of ERCOT is a “public utility” subject to the FERC’s jurisdiction under the Federal Power Act. These subsidiaries must comply with certain FERC reporting requirements and FERC-approved market rules and are subject to FERC oversight of mergers and acquisitions, the disposition of FERC-jurisdictional facilities and the issuance of securities. In addition, under the Natural Gas Act, the FERC has limited jurisdiction over certain resales of natural gas, but does not regulate the prices received by our subsidiary that markets natural gas.

The FERC has authorized 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 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 our subsidiaries that constitute public utilities is sold pursuant to this

authorization, although certain of our facilities sell their output under cost-based RMR agreements, as explained below. The FERC may revoke or limit our market-based rate authority if it determines that we possess undue market power in a regional market. The FERC requires that 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 any of our subsidiaries violates the market behavior rules or codes of conduct, the FERC may require a disgorgement of profits or revoke its market-based rate authority or blanket certificate authority. If the FERC were to revoke market-based rate authority, our affected subsidiary would have to file a cost-based rate schedule for all or some of its sales of electricity at wholesale. If the FERC revoked the blanket certificate authority of any of our subsidiaries, certain sales of natural gas would be prohibited.

Our facilities operate in ISO/RTO markets. In areas where ISOs or RTOs control the regional transmission systems, market participants have expanded access to transmission service. ISOs operate real-time and day-ahead energy and ancillary services markets, typically governed by FERC-approved tariffs and market rules. Some RTOs and ISOs also operate capacity markets. Changes to the applicable tariffs and market rules may be requested by market participants, state regulatory agencies and the system operator, and such proposed changes, if approved by the FERC, could have a significant impact on our operations and business plan. While participation by transmission-owning public utilities in ISOs and RTOs has been and is expected to continue to be voluntary, the majority of such public utilities in New England, New York, the Mid-Atlantic and California have joined the respective ISO/RTO.

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.

Mid-Atlantic Region. Our Mid-Atlantic facilities 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 located in the Mid-Atlantic region 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.

Northeast Region. Our New York plants participate in a market controlled by the NYISO, which replaced the New York Power Pool. The NYISO provides statewide transmission service under a single tariff and interfaces with neighboring market control areas. To account for transmission congestion and losses, the NYISO calculates energy prices using a locational marginal pricing model that is similar to that used in PJM and ISO-NE. The NYISO also administers a spot market for energy, as well as markets for installed capacity and services that are ancillary to transmission service, such as operating reserves and regulation service (which balances resources with load). The NYISO’s locational capacity market rules use a demand curve mechanism to determine for every month the required amount of installed capacity as well as installed capacity prices to be paid for three locational zones: New York City, Long Island and Rest of State. Our facilities operate outside of New York City and Long Island. On April 21, 2005, the FERC issued an order accepting the NYISO’s demand curves for capability years 2005/2006, 2006/2007 and 2007/2008 with minor modifications to the NYISO’s proposal. The new demand curves may result in increased prices within the NYISO for capacity.

Our New England plants participate in a market administered by ISO-NE. Mirant Energy Trading is a member of NEPOOL, which is a voluntary association of electric utilities and other market participants in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont, and which functions as an advisory organization to ISO-NE. The FERC approved ISO-NE as the RTO for the New England region effective on February 1, 2005, making ISO-NE responsible for market rule filings at the FERC, in addition to its responsibilities for the operation of transmission systems and administration and settlement of the wholesale electric energy, capacity and ancillary services markets. ISO-NE utilizes a locational marginal pricing model similar to that used in PJM and NYISO. In early 2004, ISO-NE filed with the FERC to adopt a LICAP similar to NYISO’s capacity market. After extensive litigation before the FERC on the LICAP proposal, on March 6, 2006, a comprehensive settlement proposal was filed with the FERC between ISO-NE and multiple market participants that would replace the LICAP proposal with a forward capacity market (“FCM”) under which annual capacity auctions would be conducted for supply three years in advance of delivery. In addition, the settlement provided for a four-year transition period under which capacity suppliers would receive a set price for their capacity commencing on December 1, 2006, and continuing with price escalators through May 31, 2010. On June 16, 2006, the FERC issued a decision accepting the proposed FCM settlement without modification. The FCM will result in increased opportunities for our New England generators to receive more revenues for their capacity commencing in December 2006. The FERC’s orders regarding the LICAP and FCM are pending review with the U.S.

Court of Appeals. On February 15, 2007, ISO-NE filed the market rules with the FERC to implement FCM. The market rules were supported by a majority of NEPOOL members. NEPOOL did not join in the filing but will be filing separate comments. Existing resources will need to be qualified, and the amount of MW they have to participate in the first auction certified, by April 2007. In June 2007, another round of information will be due from new generators, on a more detailed and binding nature than the show of interest forms. In October 2007 all resources that want to participate in the first auction will be fully qualified by ISO-NE. The first auction will take place starting February 4, 2008, for the delivery period June 1, 2010 - May 31, 2011.

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

Our subsidiaries owning facilities subject to RMR arrangements are parties to a PPA with PG&E that allows PG&E to dispatch and purchase the power output of all of our CAISO designated RMR units from 2006 through 2012. The PPA currently applies only to Potrero units 3-6, our CAISO designated RMR generating units for 2007. Under the PPA, through 2008 PG&E is paying us charges equivalent to the rates we charged during 2004 when the units were designated RMR Contract Condition 2 reduced by $1.4 million for each year. For 2009 through 2012, the charges for the units that are then subject to the PPA will be determined annually by the FERC.

The CAISO has proposed changes to its market design to more closely mirror the eastern ISO markets, including establishing a wholesale capacity market. The market redesign has been delayed several times, with full implementation now expected in 2008. Any proposal for a capacity market in California is subject to filing with and approval by the FERC, and at this time, the CAISO has not proposed a capacity market mechanism in its market redesign. The CPUC has taken a role in developing recommended options with respect to a wholesale capacity market in conjunction with the CAISO. We cannot at this time predict the outcome of the CPUC proceeding or the timing or structure of a wholesale capacity market in California.

The FERC approved a $400 per MWh cap, effective on January 1, 2006, on prices for energy in the CAISO market, which was an increase from the previous $250 per MWh cap, but still far short of the $1,000 per MWh energy cap utilized in the other FERC approved RTO markets. In addition, owners of non-hydroelectric generation in California, including certain of our facilities, must offer to keep their generation on-line and stand ready to offer power into the CAISO’s spot markets if the output is not under contract or scheduled for delivery within the hour, unless granted a waiver by the CAISO. The practical effect of this rule is to obtain operating reserves without paying for them, and to release excess energy into the market, thereby depressing prices. On August 26, 2005, the Independent Energy Producers, a trade association, filed a complaint with the FERC, requesting that the FERC require the CAISO to implement a reliability capacity services tariff (“RCST”) that would pay generators for the capacity obtained pursuant to the must-offer requirement. Prior to the FERC’s ruling on the merits of the complaint, the CAISO and multiple market participants filed a settlement that would implement a form of the RCST. On February 13, 2007, the FERC approved the RCST settlement with minor modifications with an effective date of June 1, 2006. The RCST settlement may result in increased capacity revenue opportunities for generators and possibly could increase revenues for certain units at our Pittsburg and Contra Costa plants for the June 1 - December 31, 2006, period, depending upon how the CAISO implements the terms of the settlement. However, after December 31, 2006, our Pittsburg and Contra Costa plants are under contract for varying periods from now until 2011, and we will not realize any opportunities from RCST until those contracts expire.

The CPUC has issued a series of orders purporting to require exempt wholesale generators and other power plant owners to comply with detailed operation, maintenance and recordkeeping standards for electricity generating facilities. In its orders, the CPUC has stated its intent to implement and enforce these detailed standards to maintain and protect the public health and safety of California residents and businesses, to ensure that electric generating facilities are effectively and appropriately maintained and efficiently operated, and to ensure electrical service reliability and adequacy. The CPUC has adopted detailed reporting requirements for the standards, and conducts frequent on-site spot inspections and more comprehensive facility audits to evaluate compliance. Some standards are intended to ensure that units are maintained in a state of readiness so as to be available to operate if requested by a control area operator, while others provide procedures for changing a unit’s long-term status. The CPUC’s efforts to implement and enforce the operation, maintenance and recordkeeping standards could interfere with our future ability to make economic business decisions regarding our units, including decisions regarding unit retirements, and could have a material adverse impact on our business activities in California.

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 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 Mid-Atlantic 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. Several of our facilities are located in or near metropolitan areas, such as New York City, Boston, San Francisco and Washington D.C., which are classified by the EPA as not achieving certain NAAQS. As a result of the

NAAQS classification of these areas, our operations are subject to more stringent air pollution requirements, 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 subsidiaries’ acquisition or lease of the plants. If a violation is determined to have occurred at any of the plants, 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. Our subsidiaries owning or leasing the Chalk Point, Dickerson and Morgantown plants in Maryland will be installing a variety of emissions control equipment on those plants to comply with the Maryland Healthy Air Act, but that equipment will 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 our subsidiaries acquired or leased the plants or, if occurring prior to the acquisition or lease, is determined to constitute a continuing

violation, 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 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.

State air regulations. Various states where we do business also have other air quality laws and regulations with increasingly stringent limitations and requirements that will become applicable in future years to our facilities and operations. We expect to incur additional compliance costs as a result of these additional state requirements, which could include significant expenditures on emissions controls or have other impacts on operations. Specific state items include:

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.

Massachusetts Emissions Standards for Power Plants. The Commonwealth of Massachusetts has finalized regulations to further reduce NOx emissions from certain generation facilities. The Massachusetts regulations relate to NOx emissions during ozone season and become effective in 2009. Our operations will not be materially affected by the newly established limits.

New York. In 2000, the State of New York issued an NOV to the previous owner of our Lovett facility alleging NSR violations associated with the operation of that facility prior to its acquisition by us. On June 11, 2003, Mirant New York, Mirant Lovett and the State of New York entered into the 2003 Consent Decree. The 2003 Consent Decree was approved by the Bankruptcy Court on October 15, 2003. Under the 2003 Consent Decree, Mirant Lovett has three options: (1) install emissions controls on Lovett’s two coal-fired units; (2) shut down one unit and convert one unit to natural gas; or (3) shut down both coal burning units in 2007 and 2008. If Mirant Lovett elects to install emissions controls on its two coal-fired units by 2007 through 2008, it must install: (a) emissions controls consisting of SCR technology to reduce NOx emissions; (b) alkaline in-duct injection technology to reduce SO2 emissions; and (c) a baghouse. Additionally, in 2003, the State of New York finalized air regulations that significantly reduced allowances for NOx and SO2 emissions from generation facilities through a state emissions cap-and-trade program, which will become effective during the 2006-2008 timeframe.

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, Massachusetts and New York will be affected, and we are evaluating our options to comply with the requirements of the rule.

In addition, separate from the RGGI, California and Massachusetts have also enacted limitations on CO2 emissions from power plants which affect our gas-fired plants in California and our Canal facility in Massachusetts. We expect that we will be able to comply with these restrictions either by reducing our emissions or purchasing emissions credits if permitted by the applicable law, but if we are unable to comply, we will be forced to curtail our operations at these facilities.

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.

In February 2006, Mirant Delta received correspondence from the U.S. Fish and Wildlife Service and the U.S. Army Corps of Engineers expressing the view that the federal Endangered Species Act coverage for our Contra Costa and Pittsburg facilities located along the Sacramento River and Suisun Bay is insufficient or inoperative. Endangered Species Act consultation has been formally reinitiated, and we are continuing to work with these agencies to resolve these issues. It is possible, however, that we will be unable to resolve these issues with the agencies and that more formal legal action may be instituted against us resulting in substantial fines or operational curtailment of these facilities.

On May 10, 2006, the San Francisco Regional Water Quality Control Board issued Mirant Potrero a National Pollution Discharge Elimination System permit pursuant to the Clean Water Act regulating the Potrero facility’s cooling water and process water discharges to the San Francisco Bay. Communities for a

Better Environment, an environmental advocacy organization, contested various elements of the permit in a petition filed with the California State Water Resources Control Board on June 8, 2006, seeking relief that could include a plant curtailment, and/or costly technological upgrades. Mirant Potrero filed a timely response to this petition as the permit holder on November 27, 2006, in support of the Regional Board’s permit decision. A decision from the State Board is expected by July 2007.

On September 26, 2006, the Massachusetts Department of Environmental Protection and the EPA jointly issued to Mirant Kendall a Surface Water Discharge Permit (“SWDP”) and a National Pollutant Discharge Elimination System (“NPDES”) permit for the Kendall generating facility. The new permit imposes in-stream temperature limits, an extensive temperature, water quality and biological monitoring program, and a requirement to develop and install a barrier net system to reduce fish impingement and entrainment. The provisions regulating the thermal discharge could cause substantial curtailments of the operations of the Kendall facility. Mirant Kendall has appealed significant portions of the SWDP and NPDES permit, along with a related state Water Quality Certificate. The portions of the permits that Mirant Kendall has appealed are stayed pending appeal. We are unable to predict the outcome of this proceeding.

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. Areas of soil and groundwater contamination are known to exist at our Pittsburg, Contra Costa and Potrero facilities. Prior to our acquisition of those facilities from PG&E in 1998, PG&E conducted soil and groundwater investigations at those facilities which revealed significant contamination. The consultants conducting the investigation estimated the aggregate cleanup costs at those facilities could be as much as $60 million. Pursuant to the terms of the Purchase and Sale Agreement with PG&E, PG&E has responsibility for the containment or capping of all soil and groundwater contamination at the Potrero generating facility and the disposition of up to 60,000 cubic yards of contaminated soil at the Potrero generating facility and the remediation of any groundwater or solid contamination identified by PG&E at the Pittsburg and Contra Costa generating facilities. Pursuant to our requests, PG&E has disposed of 807 cubic yards of contaminated soil at the Potrero generating facility. We are not aware of soil or groundwater conditions for which we expect our remediation costs to be material that are not covered by third-party agreements.

Employees

Under our services agreement with Mirant Services, Mirant Services provides the personnel who operate our facilities. At December 31, 2006, approximately 1,290 Mirant Services employees worked at our facilities, of whom approximately 1,180 were employed by Mirant Services at our power plants. The following details the employees subject to collective bargaining agreements:

Union

Location

Number of
Employees
Covered

Contract
Expiration
Date

Continuing Operations:

IBEW Local 1900

Maryland and Virginia

482

6/1/2010

IBEW Local 503

New York

136

6/1/2008

IBEW Local 1245

California

123

10/31/2008

UWUA Local 369

Cambridge, Massachusetts

2/28/2009

UWUA Local 480

Sandwich, Massachusetts

6/1/2011

Total

826

Discontinued Operations

United Steel Workers Local 12502(1)

Indiana and Michigan

1/1/2007

Total

853

(1) One year contract extension through 1/1/2008.

To mitigate and reduce the risk of disruption during labor negotiations, we engage in contingency planning for continuation of our generation and/or distribution activities to the extent possible during an adverse collective action by the union with whom Mirant Services is negotiating.

Item 1A. Risk Factors

The following are factors that could affect our future performance:

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

We sell capacity, energy and ancillary services from many of our generating facilities into competitive power markets on a short-term fixed price basis or through power sales agreements. We are not guaranteed recovery of our costs or any return on our capital investments through mandated rates. The market for wholesale electric energy and energy services reflects various market conditions beyond our control, including the balance of supply and demand, the marginal and long run costs incurred by our competitors and the impact of market regulation. Lack of diversification in revenue may also result in concentrated exposure to markets, especially PJM. The price for which we can sell our output may fluctuate on a day-to-day basis. The markets in which we compete remain subject to one or more forms of regulation that limit our ability to raise prices during periods of shortage to the degree that would occur in a fully deregulated market, limiting our ability to recover costs and an adequate return on our investment.

Our revenues and results of operations are influenced by factors that are beyond our control, including:

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

· actions by regulators, ISOs, RTOs 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, ISOs and RTOs, including any price limitations and other mechanisms to address some of the price volatility or illiquidity in these markets or the physical stability of the system;

· 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.

Mirant Energy Trading engages in asset management activities related to sales of electricity and purchases of fuel. The income and losses from these activities are recorded as generation revenues and fuel costs. Mirant Energy Trading may use forward contracts and derivative financial instruments 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.

Some of our generation facilities depend on only one or a few customers or suppliers. These parties, as well as other parties with whom we have contracts, may fail to perform their obligations, or may terminate their existing agreements, which may result in a default on project debt or a loss in revenues and may require us to institute legal proceedings to enforce the relevant agreements.

Several of our power production facilities depend on a single customer or a few customers to purchase most or all of the facility’s output or on a single supplier or a few suppliers to provide fuel, water and other services required for the operation of the facility. The sale and procurement agreements for these facilities may also provide support for any project debt used to finance the facilities. The failure of any supplier or customer to fulfill its contractual obligations to the facility could have a material adverse effect on such facility’s financial results. The financial performance of these facilities is dependent on the continued performance by customers and suppliers of their obligations under their long-term agreements.

Revenue received by our subsidiaries may be reduced upon the expiration or termination of existing power sales agreements. Some of the electricity we generate from our existing portfolio is sold under long-term power sales agreements that expire at various times. When the terms of each of these power sales agreements expire, it is possible that the price paid to us for the generation of electricity may be reduced significantly, which would substantially reduce our revenue.

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 debt or our other obligations.

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

We engage in asset management activities to 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. We also use derivative contracts with respect to our limited proprietary trading and fuel oil management activities, through which we attempt to achieve incremental returns by transacting where we have specific market expertise. Derivatives from our asset management and proprietary trading activities are recorded on our balance sheet at fair value pursuant to SFAS 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 and proprietary trading activities, see Note 6 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. Some of our facilities have areas with known soil and/or groundwater contamination. 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 Mid-Atlantic coal facilities may not meet their anticipated schedule, which would restrict these units from running at their maximum economic levels. In the event that the operating constraints were sufficiently severe, Mirant Mid-Atlantic may not have sufficient cash flow to permit it to make distributions or, if more severe, to meet its obligations.

Under the Maryland Healthy Air Act, we are required to reduce annual emissions below certain levels by January 2010. The levels established do not allow for the use of 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 level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations.

As of December 31, 2006, our total indebtedness for continuing operations was approximately $3.3 billion. In addition, the present value of lease payments under the Mirant Mid-Atlantic leveraged leases is approximately $1.1 billion (assuming a 10% discount rate) and the termination value of the Mirant Mid-Atlantic leveraged leases is $1.4 billion. Our substantial degree of leverage could have important consequences, including the following: (1) it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; (2) a substantial portion of our cash flows from operations must be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities; (3) the debt service requirements of our indebtedness could make it more difficult for us to satisfy our financial obligations; (4) certain of our borrowings, including borrowings under our senior secured credit facilities, are at variable rates of interest, exposing us to the risk of increased interest rates; (5) it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared with our competitors that have less debt; and (6) we may be more vulnerable in a downturn in general economic conditions or in our business and we may be unable to carry out capital expenditures that are important to our long-term growth or necessary to comply with environmental regulations.

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

We and our subsidiary, Mirant North America are holding companies and, as a result, we are dependent upon dividends, distributions and other payments from our subsidiaries to generate the funds necessary to meet our obligations. The ability of our subsidiaries to pay dividends and distributions is restricted under the terms of their debt or other agreements. In particular, a significant portion of cash from our operations is generated by the power generation facilities of Mirant Mid-Atlantic. Under the Mirant Mid-Atlantic leveraged leases, Mirant Mid-Atlantic is subject to a covenant that restricts its right to

make distributions to us. Mirant Mid-Atlantic’s ability to satisfy the criteria set by that covenant in the future could be impaired by factors which negatively affect the performance of its power generation facilities, including interruptions in operation or curtailment of operations to comply with environmental restrictions.

Our obligations and the obligations of Mirant North America, including our respective indebtedness, are effectively subordinated to the obligations or indebtedness of their respective subsidiaries, except to the extent that such obligations or indebtedness are assumed or guaranteed by a subsidiary.

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

Our ability to pay principal and interest on our debt depends on our future operating performance. If our cash flows and capital resources are insufficient to allow us to make scheduled payments on our debt, we may have to reduce or delay capital expenditures, sell assets, seek additional capital, restructure or refinance. There can be no assurance that the terms of our debt will allow these alternative measures, that the financial markets will be available to us on acceptable terms or that such measures would satisfy our scheduled debt service obligations.

We seek to manage the risks associated with the volatility in the price at which we sell power produced by our generation facilities and in the prices of fuel, emissions allowances and other inputs required to produce such power by entering into hedging transactions. These asset management activities may require us to post collateral either in the form of cash or letters of credit. As of December 31, 2006, we had approximately $38 million of posted cash collateral and $204 million of letters of credit outstanding primarily to support our asset management activities and debt service reserve requirements. While we seek to structure transactions in a way that reduces our potential liquidity needs for collateral, we may be unable to execute our hedging strategy successfully if we are unable to post the amount of collateral required to enter into and support hedging contracts.

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

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

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

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. The majority of our generation is sold at market prices under market-based rate authority granted by the FERC. If certain conditions are not met, the FERC has the authority to withhold or rescind market-based rate authority and require sales to be made based on cost-of-service rates. A loss of our market-based rate authority could have a materially negative impact on our 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, most of our assets are subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, ISOs and RTOs may impose bidding and scheduling rules, both to curb the potential exercise of market power and to ensure market functions. Such actions may materially affect our ability to sell and the price we receive for our energy and capacity.

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 service our indebtedness, 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.

The subsidiaries that own our generation facilities in New York, including our Lovett and Bowline facilities, have not emerged from Chapter 11.

On January 26, 2007, the Emerging New York Entities filed the Supplemental Plan with the Bankruptcy Court. For more information on the Supplemental Plan, see “Item 3. Legal Proceedings, Chapter 11 Proceedings.” The hearing before the Bankruptcy Court to consider the confirmation of the Supplemental Plan is scheduled for March 21, 2007. Until our subsidiaries related to our New York business operations emerge from bankruptcy, we will not have access to the cash from operations generated from these subsidiaries. In 2006, our New York operations generated $5 million of cash from operating activities.

March 8, 2007. The transaction is expected to close in the second quarter of 2007. On February 15, 2007, Mirant NY-Gen filed the Mirant NY-Gen Plan. For more detail concerning the Mirant NY-Gen Plan, see “Item 3. Legal Proceedings, Chapter 11 Proceedings.”

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:

Operating Plants:

				Mirant’s %				Net Equity
				Leasehold/				Interest/		2006
				Ownership		Total		Lease in		Capacity
Power Generation Business	Location	Plant Type	Primary Fuel	Interest(1)		MW(2)		Total MW(2)		Factor(3)
Continuing Operations
Mid-Atlantic Region:
Chalk Point	Maryland	Intermediate/Baseload/Peaking	Natural Gas/Coal/Oil		100		2,429		2,429		22	%
Dickerson	Maryland	Baseload/Peaking	Natural Gas/Coal/Oil		100		853		853		42	%
Morgantown	Maryland	Baseload/Peaking	Coal/Oil		100		1,492		1,492		58	%
Potomac River	Virginia	Intermediate/Baseload	Coal		100		482		482		26	%
Total Mid-Atlantic							5,256		5,256		36	%
Northeast Region:
Canal	Massachusetts	Intermediate	Natural Gas/Oil		100		1,112		1,112		17	%
Kendall	Massachusetts	Baseload	Natural Gas/Oil/Jet fuel		100		256		256		52	%
Martha’s Vineyard	Massachusetts	Peaking	Diesel		100		14		14		1	%
Wyman	Maine	Peaking	Fuel Oil		1.4		614		9		—
Total New England							1,996		1,391		23	%
Bowline	New York	Intermediate/Peaking	Natural Gas/Oil		100		1,125		1,125		2	%
Hillburn	New York	Baseload/Peaking	Natural Gas/Jet Fuel		100		51		51		—
Lovett	New York	Baseload/Peaking	Natural Gas/Coal/Oil		100		411		411		44	%
Mongaup	New York	Intermediate/Peaking	Hydro		100		4		4		23	%
Rio	New York	Intermediate/Peaking	Hydro		100		9		9		34	%
Shoemaker	New York	Peaking	Natural Gas/Jet Fuel		100		44		44		1	%
Swinging Bridge	New York	Intermediate/Peaking	Hydro		100		12		12		8	%
Total New York							1,656		1,656		13	%
Total Northeast							3,652		3,047		17	%
California:
Contra Costa	California	Intermediate	Natural Gas		100		674		674		2	%
Pittsburg	California	Intermediate	Natural Gas		100		1,311		1,311		4	%
Potrero	California	Intermediate/Peaking	Natural Gas/Oil		100		362		362		17	%
Total California							2,347		2,347		6	%
Total Continuing Operations							11,255		10,650		24	%
Discontinued Operations
Zeeland	Michigan	Intermediate/Peaking	Natural Gas		100		903		903		6	%
Bosque	Texas	Baseload/Peaking	Natural Gas		100		546		546		28	%
Total Discontinued Operations							1,449		1,449		14	%
Total Mirant Americas Generation							12,704		12,099

(1) Amounts reflect our percentage economic interest in the total MW.

(2) MW amounts reflect net dependable capacity.

(3) Capacity factor is the average percentage of full capacity used over a year.

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

Item 3. Legal Proceedings

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 certain of 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 we would have to pay additional cash amounts as necessary under the terms of the Plan to satisfy such pre-petition claims.

Our subsidiaries related to our New York business operations, Mirant New York, Mirant Bowline, Mirant Lovett, Hudson Valley Gas and Mirant NY-Gen, remain in bankruptcy. Our Lovett and Bowline generation facilities in New York were subject to disputes with local tax authorities regarding property tax assessments that were not resolved until December 2006, as described below in New York Tax Proceedings. Resolution of those tax disputes should allow Mirant New York, Mirant Bowline, and Hudson Valley Gas to emerge from bankruptcy in 2007. On January 26, 2007, Mirant New York, Mirant Bowline, and Hudson Valley Gas (collectively the “Emerging New York Entities”) filed a Supplemental Joint Chapter 11 Plan of Reorganization of the Emerging New York Entities (the “Supplemental Plan”) with the Bankruptcy Court. The Supplemental Plan has two main components. First, the Supplemental Plan incorporates a settlement with the various New York tax jurisdictions that resolved the tax disputes related to the Lovett and Bowline facilities. Second, the Supplemental Plan provides unsecured creditors of the Emerging New York Entities with the same treatment afforded holders of unsecured claims against us and our subsidiaries under the Plan. Such unsecured creditors of the Emerging New York Entities will receive their pro rata share of the pool of assets created under the Plan for the benefit of our unsecured creditors and those of our subsidiaries. On January 26, 2007, the Emerging New York Entities also filed a motion with the Bankruptcy Court to establish procedures to facilitate the consideration and confirmation of the Supplemental Plan. That motion requests, among other things, that the Bankruptcy Court find that the Supplemental Plan does not alter in any respect from the Plan the treatment of the holders of unsecured claims against the Emerging New York Entities, and that all votes previously cast by such holders in respect of the Plan (which votes accepted the Plan for the Emerging New York Entities by the requisite number and amount required by the Bankruptcy Code) should be deemed votes cast in respect of the Supplemental Plan. The hearing before the Bankruptcy Court to consider the confirmation of the Supplemental Plan is scheduled for March 21, 2007.

On October 19, 2006, Mirant Lovett notified the New York Public Service Commission, the NYISO, Orange and Rockland and certain other affected transmission and distribution companies in New York of its intent to discontinue operation of units 3 and 5 of the Lovett facility in April 2007. The discontinuance of operations at unit 5 is in accordance with the requirements of a June 11, 2003, Consent Decree (the “2003 Consent Decree”) among Mirant Lovett, the State of New York and the NYSDEC that requires Mirant Lovett to install certain environmental controls on unit 5 of the Lovett facility or shut down that unit by April 30, 2007. The 2003 Consent Decree imposes similar requirements with respect to unit 4 that have to be met by April 30, 2008. Operations at unit 3 are being discontinued because it is uneconomic to continue to run unit 3 if operations at unit 5 are discontinued. Mirant Lovett is in discussions with the NYSDEC and the New York State Office of the Attorney General regarding environmental controls. If Mirant Lovett is able to agree with the New York Attorney General’s office and the NYSDEC on alternative control technologies that would allow unit 5 to remain in operation past April 30, 2007, then Mirant Lovett may rescind the notice of its intent to discontinue operations at units 3 and 5. Until a resolution is reached on environmental controls that would permit economically feasible operation, Mirant Lovett will likely remain in Chapter 11. Mirant NY-Gen, which owns hydroelectric facilities at Swinging Bridge, Rio and Mongaup, and small combustion turbine facilities at Hillburn and Shoemaker, is insolvent. Its expenses are being funded under a debtor-in-possession facility provided by Mirant Americas with the approval of, and under the supervision of, the Bankruptcy Court. Mirant NY-Gen is proceeding with the implementation of a remediation plan for the sinkhole discovered in May 2005 in the dam at the Swinging Bridge facility. The status of the remediation effort is discussed in “Other Contingencies” in Note 17 to the consolidated and combined financial statements.

On January 31, 2007, Mirant New York entered into the Alliance Sale pursuant to which it will sell Mirant NY-Gen, which owns the Hillburn and Shoemaker gas turbine facilities and the Swinging Bridge, Rio and Mongaup hydroelectric generating facilities, to Alliance Energy, LLC. The sales price of approximately $5 million is subject to adjustments for working capital and certain dam remediation efforts that are ongoing at the Swinging Bridge facility. The Bankruptcy Court approved the Alliance Sale on March 8, 2007. The transaction is expected to close in the second quarter of 2007 in conjunction with a plan of reorganization becoming effective for Mirant NY-Gen. On February 15, 2007, Mirant NY-Gen filed the proposed Mirant NY-Gen Plan. It subsequently filed a related disclosure statement. Upon approval of the disclosure statement by the Bankruptcy Court, Mirant NY-Gen will solicit votes of its creditors and proceed to a confirmation hearing seeking approval of the Mirant NY-Gen Plan. The Bankruptcy Court will consider approval of the disclosure statement on March 21, 2007. No date has been set for the confirmation of the Mirant NY-Gen Plan. The Mirant NY-Gen Plan is proposed in connection with the Alliance Sale. Under the terms of the Mirant NY-Gen Plan, on the date that the Mirant NY-Gen Plan is confirmed, the Bankruptcy Court will estimate the amount of cash required for Mirant NY-Gen to pay in full all the claims outstanding against Mirant NY-Gen other than claims arising from the debtor-in-possession loan provided by Mirant Americas to Mirant NY-Gen and intercompany claims. Proceeds from the Alliance Sale in an amount equal to the Bankruptcy Court’s estimate of the claims will be reserved to pay such claims. The balance will be paid to Mirant Americas in partial satisfaction of the $16.5 million debtor-in-possession loan, and all intercompany claims held by Mirant NY-Gen will be assigned to Mirant Americas. Upon closing of the Alliance Sale, Mirant Americas will release all of its claims and liens against Mirant NY-Gen.

Until our subsidiaries related to our New York business operations emerge from bankruptcy, we will not have access to the cash from operations generated from these subsidiaries. In 2006, our New York operations generated $5 million of cash from operating activities.

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 and various of our subsidiaries causes 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 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 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 certain of 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 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 in “Pepco Assertion of Breach of Local Area Support Agreement” in Note 17 to the consolidated and combined financial statements.

U.S. Government Inquiries

Department of Justice Inquiries. In November 2002, Mirant received a subpoena from the DOJ, acting through the United States Attorney’s office for the Northern District of California, requesting information about its activities and those of its subsidiaries for the period since January 1, 1998. The subpoena requested information related to the California energy markets and other topics, including the reporting of inaccurate information to trade publications that publish natural gas or electricity spot price data. The subpoena was issued as part of a grand jury investigation. The DOJ’s investigation is based upon the same circumstances that were the subject of an investigation by the CFTC that was settled in December 2004, as described in Mirant’s Annual Report on Form 10-K for the year ended December 31, 2004, in Legal Proceedings—Other Governmental Proceedings—CFTC Inquiry. On June 19, 2006, two former employees of Mirant pled guilty to charges of conspiracy to manipulate the price of natural gas in interstate commerce during the period from July 1, 2000, until November 1, 2000, while they were west region traders for Mirant Americas Energy Marketing. Mirant is discussing the disposition of this matter with the DOJ. If Mirant is unable to reach a consensual resolution with the DOJ, it is possible that the DOJ could seek indictments against one or more Mirant entities for alleged violations of the Commodity

Exchange Act. A consensual resolution of this matter could involve a deferred prosecution agreement and payment of a fine or penalty. Our current assessment is that any such fine or penalty would be paid by Mirant, not us or our subsidiaries.

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 our 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 our subsidiaries’ acquisition or lease of the plants. If a violation is determined to have occurred at any of the plants, 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. Our subsidiaries owning or leasing the Chalk Point, Dickerson and Morgantown plants in Maryland will be installing a variety of emissions control equipment on those plants to comply with the Maryland Healthy Air Act, but that equipment will 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 our subsidiaries acquired or leased the plants or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, 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 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, Mirant Potomac River, Mirant Mid-Atlantic, 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 Mirant Mid-Atlantic to (1) install pollution control equipment at the Potomac River plant in Virginia and at the Morgantown plant in Maryland leased by Mirant Mid-Atlantic, (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 Mirant Mid-Atlantic’s Morgantown units 1 and 2 in 2007 and 2008, the Original Consent Decree would not have obligated our subsidiaries 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, Mirant Mid-Atlantic 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 Mirant Mid-Atlantic leases the coal units at the Dickerson and Morgantown plants. The Amended Consent Decree provides that if Mirant Mid-Atlantic 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, Mirant Mid-Atlantic, 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 Mirant Mid-Atlantic, 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, Mirant Mid-Atlantic and the MDE entered into an agreement to allow Mirant Mid-Atlantic to implement the consent decree with respect to the Morgantown plant, if the consent decree receives the necessary approvals. Under the agreement, Mirant Mid-Atlantic agreed to certain ammonia and particulate matter emissions limits and to submit testing results to the MDE.

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.

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.

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 Mirant Mid-Atlantic 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 Mirant Mid-Atlantic 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, Mirant, Mirant Mid-Atlantic, 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.

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.

Riverkeeper Suit Against Mirant Lovett. On March 11, 2005, Riverkeeper, Inc. filed suit against Mirant Lovett in the United States District Court for the Southern District of New York under the Clean Water Act. The suit alleges that Mirant Lovett failed to implement a marine life exclusion system at its Lovett generating plant and to perform monitoring for the exclusion of certain aquatic organisms from the plant’s cooling water intake structures in violation of Mirant Lovett’s water discharge permit issued by the State of New York. The plaintiff requests the court to enjoin Mirant Lovett from continuing to operate the Lovett generating plant in a manner that allegedly violates the Clean Water Act, to impose civil penalties of $32,500 per day of violation, and to award the plaintiff attorneys’ fees. On April 20, 2005, the district court approved a stipulation agreed to by the plaintiff and Mirant Lovett that stays the suit until 60 days after entry of an order by the Bankruptcy Court confirming a plan of reorganization for Mirant Lovett becomes final and non-appealable.

Mirant Canal NOV. On December 5, 2006, Mirant Canal received a notice of noncompliance from the Massachusetts DEP indicating that during August 2006, personnel from the Massachusetts DEP determined that the low NOx calibration gas cylinder for the continuous emission monitoring system (“CEMS”) for unit 1 of the Canal generating facility had an expiration date of December 23, 2005, which resulted in the CEMS being considered to be “out-of-control” after that date. The notice required Mirant Canal to review and update the facility CEMS operating and maintenance plan and CEMS quality control plan and to review and revise as necessary certain previously submitted reports. Further action may be taken by the Massachusetts DEP following its review of the information submitted by Mirant Canal in response to the notice.

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, Mirant Potomac River and Mirant Mid-Atlantic 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 Mirant Mid-Atlantic 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.

New York Tax Proceedings

Mirant New York, Mirant Bowline, Mirant Lovett, and Hudson Valley Gas (collectively with Mirant New York, Mirant Bowline, and Mirant Lovett, the “New York Companies”) were the petitioners in various proceedings (“Tax Certiorari Proceedings”) initially brought in the New York state courts challenging the assessed values determined by local taxing authorities for the Bowline and Lovett generating facilities and a natural gas pipeline (the “HVG Property”) owned by Hudson Valley Gas. Mirant Bowline had challenged the assessed value of the Bowline generating facility and the resulting local tax assessments for tax years 1995 through 2006. Mirant Bowline succeeded to rights held by Orange & Rockland for the tax years prior to its acquisition of the Bowline Plant in 1999 under its agreement with Orange & Rockland for the purchase of that plant. Mirant Lovett had challenged the assessed value of the

Lovett facility for each of the years 2000 through 2006. Hudson Valley Gas had challenged the assessed value of the HVG Property for each of the years 2004 through 2006.

As of December 31, 2006, Mirant Bowline and Mirant Lovett had not paid property taxes on the Bowline and Lovett generating facilities that fell due in the period from September 30, 2003, through September 30, 2006, in order to preserve their respective rights to offset the overpayments of taxes made in earlier years against the sums payable on account of current taxes. Hudson Valley Gas had not paid property taxes that fell due in the period from September 30, 2004, through September 30, 2006. The failure to pay these taxes when due potentially subjected Mirant Bowline, Mirant Lovett, and Hudson Valley Gas to additional penalties and interest.

On August 11, 2006, and August 28, 2006, the New York state court issued decisions addressing Mirant Bowline’s challenges to the assessed values of the Bowline facility for the years 1995 to 2003 and Mirant Lovett’s challenges to the assessed values of the Lovett facility for the years 2000 to 2003. Except for 1996, where it found that Mirant Bowline had failed to perfect its challenge to the assessed value of the Bowline facility, the New York state court concluded that the value of the Bowline facility and the Lovett facility in each year was substantially less than the assessed value set by the taxing authorities. Mirant Bowline and Mirant Lovett appealed the decisions of the New York state court, and the relevant taxing authorities cross-appealed.

On December 13, 2006, Mirant and the New York Companies entered into a settlement agreement (the “Settlement Agreement”) with the Town of Haverstraw (“Haverstraw”), the Town of Stony Point (“Stony Point”), the Haverstraw-Stony Point Central School District (the “School District”), the County of Rockland (the “County”), the Village of Haverstraw (“Haverstraw Village”), and the Village of West Haverstraw (“West Haverstraw Village” and collectively with Haverstraw, Stony Point, the School District, the County, and Haverstraw Village, the “Tax Jurisdictions”). The Settlement Agreement was approved by the Bankruptcy Court on December 14, 2006, and resolved all pending disputes regarding real property taxes between the New York Companies and the Tax Jurisdictions. Under the agreement, the New York Companies accepted the determinations of assessed value for the Bowline Facility for 1995 through 2003 and the Lovett Facility for 2000 through 2003 made by the New York state court in its rulings in the Tax Certiorari Proceedings issued in August 2006. The New York Companies and the Tax Jurisdictions agreed to adopt the New York state court’s assessed values for the Bowline Facility and the Lovett Facility for 2003 as the assessed values for each facility for 2004 through 2006. The parties agreed that the assessed values for the HVG Property for 2004 through 2006 should be the values determined previously by Haverstraw. The Tax Jurisdictions agreed to cancel penalties on the unpaid taxes owed by the New York Companies and to collect interest on those taxes at a rate of 8% per year for Mirant Bowline and Mirant Lovett and 12% per year for Hudson Valley Gas. Overall, the New York Companies under the settlement received total refunds of $163 million from the Tax Jurisdictions and paid unpaid taxes to the Tax Jurisdictions of $115 million, resulting in the New York Companies receiving a net cash payment in the amount of $48 million. The refunds and unpaid taxes were paid in early February 2007, and the New York Companies and the Tax Jurisdictions are in the process of dismissing all pending litigation related to the refunds and the unpaid taxes.

The $163 million of total refunds received by the New York Companies was recognized as a gain in the financial statements in the fourth quarter of 2006. In addition, the New York Companies had previously accrued a liability based upon the unpaid taxes as billed by the Tax Jurisdictions. Due to the reductions of the unpaid taxes that occurred pursuant to the terms of the Settlement Agreement, the New York Companies also recognized in the fourth quarter of 2006 a reduction of operating expenses of approximately $23 million related to 2006 and a gain of approximately $71 million related to prior periods.

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

None.

PART II

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

We are an indirect wholly-owned subsidiary of Mirant. Our membership interests are not publicly traded and all of our membership interests are held by our parent, Mirant Americas. We did not make any cash distributions from the Petition Date through December 31, 2005. We made $236 million of cash distributions in 2006. We have no equity compensation plans under which we issue our membership interests.

Item 6. Selected Financial Data

The following discussion should be read in conjunction with our consolidated and combined financial statements and the notes thereto, which are included elsewhere in this Form 10-K. The following table presents our selected financial information, which is derived from our consolidated and combined financial statements. Prior years have been revised to reflect the impact of our planned dispositions of the Zeeland and Bosque natural gas-fired intermediate and peaking plants. See Note 3 to our consolidated and combined financial statements for further discussion of our discontinued operations.

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 debt that was subject to compromise subsequent to the Petition Date. Our Statement of Operations Data for the year ended December 31, 2005, reflects the effects of accounting for the Plan confirmed on December 9, 2005.

	Years Ended December 31,
	2006		2005			2004			2003			2002
	(in millions)
Statements of Operations Data:
Operating revenues	$	3,273	$	2,967		$	3,465		$	3,965		$	3,407
Income (loss) from continuing operations	1,190		(760		)	123			(3,203		)	160
Income (loss) from discontinued operations	10		(3		)	(17		)	4			67
Net income (loss)	1,200		(779		)	106			(3,209		)	227
Balance Sheet Data:
Total assets	5,837		7,020			6,157			6,296			11,752
Total long-term debt, excluding discontinued operations	3,272		2,582			38			43			3,570
Liabilities subject to compromise, excluding discontinued operations	34		34			5,364			5,345			—
Equity (deficit)	$	1,644	$	703		$	(326	)	$	(439	)	$	2,338

At December 31, 2004 and 2003, certain long-term debt amounts were included in liabilities subject to compromise.

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. Our continuing operations consist of power generation facilities and our energy trading and marketing operations. Our continuing business consists of 10,650 MW located in markets that are characterized by low and declining reserve margins.

During the third quarter of 2006, Mirant commenced auction processes to sell certain of its natural gas-fired plants, including our Zeeland (903 MW) and Bosque (546 MW) plants. On January 15, 2007, we entered into a definitive purchase and sale agreement with a subsidiary of LS Power Equity Partners I, L.P., LS Power Equity Partners II, L.P. and certain other affiliated funds, (collectively, “LS Power”), for the sale of our Zeeland and Bosque natural gas-fired plants. The net proceeds from the sales are expected to be approximately $500 million, after transaction costs. The transaction is expected to close in the second quarter of 2007 after the satisfaction of certain customary conditions.

The primary factors affecting the earnings and cash flows of our continuing 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, 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 the incentives offered will result in the construction of new generation.

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 Mid-Atlantic baseload coal-fired generation and our New England intermediate oil-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, our Mirant Mid-Atlantic subsidiary entered into financial swap transactions resulting in Mirant Mid-Atlantic being economically hedged for approximately 92%, 93%, 97% and 38% of its 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 of Mirant Mid-Atlantic 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 84%, 48%, 36% and 14% for 2007, 2008, 2009 and 2010, respectively. The corresponding fuel hedges are approximately 82%, 27%, 15% and 0% for 2007, 2008, 2009 and 2010, respectively.

New York Property Tax Settlement. On December 13, 2006, we entered into a settlement agreement with certain tax jurisdictions related to property tax assessments at the Bowline and Lovett generating facilities that resolves all pending disputes regarding refunds sought by us for property taxes paid for 1995 through 2003 and unpaid taxes assessed for 2003 through 2006. Under the settlement, we were awarded refunds totaling approximately $163 million for 1995 through 2003, against which were offset unpaid taxes of approximately $115 million for 2003 through 2006, resulting in a net cash payment in the amount of $48 million. The refunds were received and the unpaid taxes were paid in early February 2007. As a result of the refunds and the reduction in unpaid taxes under the settlement, we recognized a gain of approximately $244 million in the fourth quarter of 2006. Of the $244 million gain recognized, $163 million is included in reorganization items, net, and $94 million is a reduction in operations and maintenance expense in our consolidated statements of operations. These amounts are partially offset by $13 million in interest expense.

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.

A portion of our capital resources, in the form of cash and letters of credit, is needed to satisfy counterparty collateral requirements. These counterparty collateral requirements reflect our non-investment grade credit ratings, volatile energy prices, generally higher margin levels in the industry and other factors. Whenever feasible, we seek to structure transactions in a way that reduces our potential liquidity needs for collateral.

Use of Proceeds from Planned Dispositions. The sale of the Zeeland and Bosque plants is subject to the terms of our and Mirant North America’s indebtedness, including provisions with respect to the mandatory prepayment and/or reinvestment of the sale proceeds and the requirement to secure a credit rating affirmation. We have received the required credit rating affirmations.

Consolidated Financial Performance

We reported net income of $1.2 billion for the year ended December 31, 2006, a net loss of $779 million for the year ended December 31, 2005, and net income of $106 million for the year ended December 31, 2004. The change in net income is detailed as follows (dollars in millions):

	Years Ended December 31,
							Increase/										Increase/
	2006			2005			(Decrease)				2005			2004			(Decrease)
Gross margin
Affiliate	$	(63	)	$	(28	)		$	(35	)	$	(28	)	$	311			$	(339	)
Nonaffiliate	2,023			863				1,160			863			770				93
Total gross margin	1,960			835				1,125			835			1,081				(246		)
Operating expenses:
Operations and maintenance
Affiliate	274			287				(13		)	287			318				(31		)
Nonaffiliate	277			375				(98		)	375			341				34
Depreciation and amortization	122			115				7			115			112				3
Impairment loss	119			—				119			—			2				(2		)
Loss (gain) on sales of assets, net	(9		)	(1		)		(8		)	(1		)	62				(63		)
Total operating expenses	783			776				7			776			835				(59		)
Operating income	1,177			59				1,118			59			246				(187		)
Other expense (income), net
Affiliate	(1		)	23				(24		)	23			8				15
Nonaffiliate	220			750				(530		)	750			(8		)		758
Gain on sales of investments	(74		)	(44		)		(30		)	(44		)	—				(44		)
Reorganization items, net	(163		)	85				(248		)	85			138				(53		)
Provision (benefit) for income taxes	5			5				—			5			(15		)		20
Income (loss) from continuing operations	1,190			(760		)		1,950			(760		)	123				(883		)
Income (loss) from discontinued operations	10			(3		)		13			(3		)	(17		)		14
Cumulative effect of changes in accounting principles	—			(16		)		16			(16		)	—				(16		)
Net income (loss)	$	1,200		$	(779	)		$	1,979		$	(779	)	$	106			$	(885	)

Bankruptcy Considerations

While in bankruptcy, our financial results were volatile as asset impairments, asset dispositions, 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.

At December 31, 2006 and 2005, amounts related to allowed claims, estimated unresolved claims and professional fees associated with the bankruptcy to be settled in cash were $5 million and $1.831 billion, respectively, and these amounts were recorded in claims payable and estimated claims accrual on the accompanying consolidated balance sheets. These amounts do not include unresolved claims that are expected to be settled in common stock or the stock portion of claims that are expected to be settled with cash and stock. During the year ended December 31, 2006, we paid approximately $1.755 billion in cash related to bankruptcy claims. Of this amount, $990 million represents the principal amount of debt claims and is reflected in cash flows from financing activities from continuing operations. The remaining $765 million is reflected in cash flows from operating activities and represents other bankruptcy claims and related interest.

Results of Operations

The following discussion of our performance is organized by reportable operating segment, which is consistent with the way we manage our business. Previously, we managed our business as one operating segment. In 2006, Mirant commenced auction processes to dispose of certain natural gas-fired plants, including our Zeeland and Bosque plants. The planned sales have resulted in the reclassification of the revenues and expenses of these assets to discontinued operations and the reclassification of the related assets and liabilities to assets and liabilities held for sale, for all periods presented. In the fourth quarter of 2006, we re-evaluated the business segments of our continuing operations. As a result, we now have four operating segments: Mid-Atlantic, Northeast, California and Other Operations. For selected financial information about our business segments, see Note 16 to our consolidated and combined financial statements contained elsewhere in this report.

In the tables below, the Mid-Atlantic region includes our Chalk Point, Morgantown, Dickerson and Potomac River facilities. The Northeast region includes our Bowline, Canal, Lovett, Kendall, Hillburn, Shoemaker, Martha’s Vineyard, Swinging Bridge, Rio, Mongaup and Wyman facilities. The California region includes our Pittsburg, Contra Costa and Potrero facilities. Other Operations includes proprietary trading and fuel oil management activities. For periods prior to 2006, Other Operations includes gains and losses related to the contractual arrangement with Pepco with respect to certain PPAs, including Pepco’s long-term PPAs with Panda and Ohio Edison (the “Back-to-Back Agreement”) and TPAs with Pepco.

Operating Statistics

The following table summarizes capacity factor (average percentage of full capacity used over a year) by region for the years ended December 31, 2006, 2005 and 2004:

	Years Ended December 31,
																Increase/
	2006			2005			Decrease			2005			2004			(Decrease)
Mid-Atlantic		36	%		39	%		(3	)%		39	%		40	%		(1	)%
Northeast		17	%		34	%		(17	)%		34	%		33	%		1	%
California		6	%		7	%		(1	)%		7	%		17	%		(10	)%
Total		24	%		31	%		(7	)%		31	%		33	%		(2	)%

The following table summarizes power generation volumes by region for the years ended December 31, 2006, 2005 and 2004 (in gigawatt hours):

	Years Ended December 31,
								Increase/
	2006	2005	Decrease			2005	2004	(Decrease)
Mid-Atlantic	16,607	18,200		(1,593	)	18,200	18,712		(512	)
Northeast	4,693	9,184		(4,491	)	9,184	8,832		352
California	1,136	1,414		(278	)	1,414	3,460		(2,046	)
Total	22,436	28,798		(6,362	)	28,798	31,004		(2,206	)

2006 versus 2005

Gross Margin

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

	Years Ended December 31,
	2006								2005
	Realized			Unrealized			Total		Realized				Unrealized				Total
Mid-Atlantic		$	834		$	484	$	1,318		$	552			$	(97	)	$	455
Northeast		297			61		358			216				(11		)	205
California		112			3		115			113				—			113
Other Operations		70			61		131			(39		)		85			46
Eliminations		38			—		38			16				—			16
Total		$	1,351		$	609	$	1,960		$	858			$	(23	)	$	835

Mid-Atlantic

Our Mid-Atlantic segment, which accounts for approximately half our generating capacity, includes four generation facilities with a total generation capacity of 5,256 MW. The following table summarizes the operations of our Mid-Atlantic segment for the years ended December 31, 2006 and 2005 (in millions):

	Years Ended December 31,						Increase/
	2006			2005			(Decrease)
Realized Gross Margin	$	834		$	552			$	282
Unrealized Gross Margin	484			(97		)		581
Total Gross Margin	1,318			455				863
Operating expenses:
Operations and maintenance	333			341				(8		)
Depreciation and amortization	74			64				10
Gain on sales of assets, net	(7		)	—				(7		)
Total operating expenses	400			405				(5		)
Operating income	918			50				868
Total other expense (income), net	(4		)	18				(22		)
Income from continuing operations before reorganization items and income taxes	$	922		$	32			$	890

Gross Margin

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

	Years Ended December 31,					Increase/
	2006		2005			(Decrease)
Energy	$	558	$	867			$	(309	)
Contracted and capacity	39		64				(25		)
Incremental realized value of hedges	237		(379		)		616
Unrealized gains (losses)	484		(97		)		581
Total	$	1,318	$	455			$	863

Energy represents gross margin from the generation of electricity, emissions allowances sales and purchases, fuel sales, fuel purchases and handling, steam sales and our proprietary trading activities.

Contracted and capacity represents revenue received through RMR contracts and other installed capacity arrangements, revenues from ancillary services and revenue from the Back-to-Back Agreement, as applicable.

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.

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

· an increase of $581 million related to unrealized 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.

Northeast

Our Northeast segment is comprised of our assets located in New York and New England with a total generation capacity of 3,047 MW. The following table summarizes the operations of our Northeast segment for the years ended December 31, 2006 and 2005 (in millions):

	Years Ended December 31,						Increase/
	2006			2005			(Decrease)
Realized Gross Margin	$	297		$	216			$	81
Unrealized Gross Margin	61			(11		)		72
Total Gross Margin	358			205				153
Operating expenses:
Operations and maintenance	133			225				(92		)
Depreciation and amortization	25			33				(8		)
Impairment losses	118			—				118
Gain on sales of assets, net	(46		)	(10		)		(36		)
Total operating expenses	230			248				(18		)
Operating income (loss)	128			(43		)		171
Total other expense, net	9			6				3
Income (loss) from continuing operations before reorganization items and income taxes	$	119		$	(49	)		$	168

Gross Margin

Gross margin increased by $153 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):

	Years Ended December 31,					Increase/
	2006		2005			(Decrease)
Energy	$	125	$	235			$	(110	)
Contracted and capacity	47		36				11
Incremental realized value of hedges	125		(55		)		180
Unrealized gains (losses)	61		(11		)		72
Total	$	358	$	205			$	153

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

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

· an increase of $180 million in incremental realized value of hedges of our generation output. In 2006, the incremental realized value of our hedges contributed $125 million to our gross margin as our power contracts settled at prices higher than market prices for the year, partially offset by hedged fuel costs that were higher than the market. In 2005, our opportunity cost of hedging was

$55 million primarily due to the impact of rising energy prices in the latter part of 2005 that resulted in the settlement of power contracts at prices lower than market prices for that year, partially offset by the favorable impact of hedged fuel costs that were generally lower than the market as fuel prices increased in 2005; and

· a decrease of $110 million in energy primarily related to lower generation volumes. Our decrease in generation volumes was driven by significantly lower volumes generated by our oil-fired units. A decrease in power prices combined with average oil prices that were higher than in 2005 resulted in our oil-fired units not being able to dispatch economically for most of the period.

Operating Expenses

The decrease of $18 million in operating expenses is primarily due to a decrease of $92 million in operations and maintenance, of which $94 million relates to the New York property tax settlement. Of this amount, $71 million relates to periods prior to 2006. The remaining decrease in property tax expense represents the difference in the 2006 expense under the settlement compared to the 2005 expense that was accrued based on the property tax assessments. Gains on sales of assets increased $36 million due to an increase of $37 million in gains on sales of emissions allowances to affiliates that are eliminated in the consolidated and combined statement of operations. Impairment losses in 2006 represent the impairment of the Bowline unit 3 suspended construction project.

California

Our California segment consists of the Pittsburg, Contra Costa and Potrero facilities with a total generation capacity of 2,347 MW. The following table summarizes the operations of our California segment for the years ended December 31, 2006 and 2005 (in millions):

	Years Ended December 31,					Increase/
	2006			2005		(Decrease)
Realized Gross Margin	$	112		$	113		$	(1	)
Unrealized Gross Margin	3			—			3
Total Gross Margin	115			113			2
Operating expenses:
Operations and maintenance	63			69			(6		)
Depreciation and amortization	13			5			8
Total operating expenses	76			74			2
Operating income	39			39			—
Total other expense (income), net	(34		)	1			(35		)
Income from continuing operations before reorganization items and income taxes	$	73		$	38		$	35

Gross Margin

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

	Years Ended December 31,						Increase/
	2006			2005			(Decrease)
Energy	$	14		$	—			$	14
Contracted and capacity	101			114				(13		)
Incremental realized value of hedges	(3		)	(1		)		(2		)
Unrealized gains	3			—				3
Total	$	115		$	113			$	2

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

Other Expense (Income), net

The decrease of $35 million in other expense (income), net is primarily due to a gain of $26 million in 2006 related to the transfer of Contra Costa unit 8 to PG&E and an increase of $6 million in interest income. See “California Settlement” in Note 17 to our consolidated and combined financial statements for further discussion.

Other Operations

Other Operations includes proprietary trading and fuel oil management activities. For periods prior to 2006, Other Operations includes gains and losses related to our Back-to-Back Agreement and TPAs with Pepco. See “Pepco Litigation” in Note 17 to our consolidated and combined financial statements for further discussion of the Back-to-Back Agreement.

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

	Years Ended December 31,						Increase/
	2006			2005			(Decrease)
Realized Gross Margin	$	70		$	(39	)		$	109
Unrealized Gross Margin	61			85				(24		)
Total Gross Margin	131			46				85
Operating expenses:
Operations and maintenance	22			27				(5		)
Depreciation and amortization	10			13				(3		)
Impairment losses	1			—				1
Loss on sales of assets, net	—			1				(1		)
Total operating expenses	33			41				(8		)
Operating income	98			5				93
Total other expense, net	174			730				(556		)
Loss from continuing operations before reorganization items and income taxes	$	(76	)	$	(725	)		$	649

Gross Margin

Gross margin increased by $85 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):

	Years Ended December 31,					Increase/
	2006		2005			(Decrease)
Energy	$	70	$	39			$	31
Contracted and capacity	—		(78		)		78
Unrealized gains	61		85				(24		)
Total	$	131	$	46			$	85

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

· an increase of $31 million in energy primarily related to our proprietary trading and fuel oil management activities net of lower of cost or market adjustments on our oil inventory during the third and fourth quarters of 2006;

· an increase of $78 million in contracted and capacity due to a decrease in realized losses on the Back-to-Back Agreement and the related hedges of this contract primarily due to the expiration of one of the PPAs under that agreement. In 2006, the Back-to-Back agreement was transferred to Mirant Power Purchase; and

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

Operating Expenses

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

Other Expense, net

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

· interest expense, net decreased by $527 million. In 2005, we recognized $746 million of interest on liabilities subject to compromise for the period from the 2003 petition date through December 2005; and

· our gain on sales of investments increased $30 million. In 2006, we recognized a gain of $54 million related to sales of our investment in ICE and a gain of $19 million on the sale of our two New York Mercantile Exchange seats and shares. In 2005, we recognized a gain of $44 million related to the sale of a portion of our investment in ICE.

Other Significant Consolidated Statements of Operations Comparison

Reorganization Items, net

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

	Years Ended December, 31,						Increase/
	2006			2005			(Decrease)
Gain on the implementation of the Plan	$	—		$	(30	)		$	30
Gain on the New York property tax settlement	(163		)	—				(163		)
Estimated claims and losses on rejected and amended contracts	—			54				(54		)
Professional fees and administrative expense	2			82				(80		)
Interest income, net	(2		)	(21		)		19
Total	$	(163	)	$	85			$	(248	)

Reorganization items, net decreased by $248 million for the year ended December 31, 2006, compared to 2005, primarily related to the settlement of the New York State property tax disputes. Under the terms of the settlement, in February 2007 we received refunds totaling approximately $163 million for 1995 through 2003 and paid unpaid taxes of approximately $115 million for 2003 through 2006. For the year ended December 31, 2005, reorganization items, net represents amounts that were recorded in the financial statements as a result of the bankruptcy proceedings.

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

Discontinued Operations

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

For the year ended December 31, 2006, we reported net income from discontinued operations of $10 million, which includes an impairment loss of $8 million to write-down the Zeeland and Bosque plants to fair value. For the year ended December 31, 2005, we reported a net loss from discontinued operations of $3 million. See Note 3 to our consolidated and combined financial statements for additional information related to planned dispositions and discontinued operations.

2005 versus 2004

The following table details gross margin by realized and unrealized margin for the years ended December 31, 2005 and 2004 (in millions):

	Years Ended December 31,
	2005										2004
	Realized				Unrealized				Total		Realized				Unrealized				Total
Mid-Atlantic		$	552			$	(97	)	$	455		$	576			$	(75	)	$	501
Northeast		216				(11		)	205			197				31			228
California		113				—			113			143				3			146
Other Operations		(39		)		85			46			(14		)		213			199
Eliminations		16				—			16			7				—			7
Total		$	858			$	(23	)	$	835		$	909			$	172		$	1,081

Mid-Atlantic

The following table summarizes the operations of our Mid-Atlantic segment for the years ended December 31, 2005 and 2004 (in millions):

	Years Ended December 31,						Increase/
	2005			2004			(Decrease)
Realized Gross Margin	$	552		$	576			$	(24	)
Unrealized Gross Margin	(97		)	(75		)		(22		)
Total Gross Margin	455			501				(46		)
Operating expenses:
Operations and maintenance	341			336				5
Depreciation and amortization	64			62				2
Total operating expenses	405			398				7
Operating income	50			103				(53		)
Total other expense, net	18			3				15
Income from continuing operations before reorganization items and income taxes	$	32		$	100			$	(68	)

Gross Margin

Gross margin decreased by $46 million for the year ended December 31, 2005, compared to the same period for 2004 and is detailed as follows (in millions):

	Years Ended December 31,						Increase/
	2005			2004			(Decrease)
Energy	$	867		$	481			$	386
Contracted and capacity	64			62				2
Incremental realized value of hedges	(379		)	33				(412		)
Unrealized losses	(97		)	(75		)		(22		)
Total	$	455		$	501			$	(46	)

The decrease in 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.

Northeast

The following table summarizes the operations of our Northeast segment for the years ended December 31, 2005 and 2004 (in millions):

	Years Ended December 31,						Increase/
	2005			2004			(Decrease)
Realized Gross Margin	$	216		$	197			$	19
Unrealized Gross Margin	(11		)	31				(42		)
Total Gross Margin	205			228				(23		)
Operating expenses:
Operations and maintenance	225			200				25
Depreciation and amortization	33			31				2
Loss (gain) on sales of assets, net	(10		)	43				(53		)
Total operating expenses	248			274				(26		)
Operating loss	(43		)	(46		)		3
Total other expense (income), net	6			(3		)		9
Loss from continuing operations before reorganization items and income taxes	$	(49	)	$	(43	)		$	(6	)

Gross Margin

Gross margin decreased by $23 million for the year ended December 31, 2005, compared to the same period for 2004 and is detailed as follows (in millions):

	Years Ended December 31,					Increase/
	2005			2004		(Decrease)
Energy	$	235		$	142		$	93
Contracted and capacity	36			36			—
Incremental realized value of hedges	(55		)	19			(74		)
Unrealized gains (losses)	(11		)	31			(42		)
Total	$	205		$	228		$	(23	)

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

· a decrease of $74 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 $42 million related to unrealized gains and losses on hedging activities. In 2005, unrealized losses of $11 million are primarily due to the settlement of power and fuel contracts during the year for which net unrealized gains had been recorded in prior periods. In 2004, the settlement of hedges for which unrealized losses had been recognized in prior periods resulted in a gain of $17 million. In addition, the impact of rising fuel prices on forward fuel contracts, less the impact of rising power prices on forward power contracts, resulted in a gain of $14 million; and

· an increase of $93 million in energy primarily related to higher market prices for power, partially offset by higher fuel costs during the year ended 2005 compared to the same period in 2004.

Operating Expenses

The decrease of $26 million in operating expenses is primarily due to an increase of $53 million in gain on sales of assets. In 2004, we recognized a loss of $65 million on the sale of three natural gas combustion turbines partially offset by an increase of $25 million in operations and maintenance expense, which included increased maintenance costs of $8 million on the dam at Swinging Bridge and $5 million related to environmental remediation costs at the Lovett and Hillburn facilities.

California

The following table summarizes the operations of our California segment for the years ended December 31, 2005 and 2004 (in millions):

	Years Ended December 31,				Increase/
	2005		2004		(Decrease)
Realized Gross Margin	$	113	$	143		$	(30	)
Unrealized Gross Margin	—		3			(3		)
Total Gross Margin	113		146			(33		)
Operating expenses:
Operations and maintenance	69		80			(11		)
Depreciation and amortization	5		4			1
Total operating expenses	74		84			(10		)
Operating income	39		62			(23		)
Total other expense, net	1		1			—
Income from continuing operations before reorganization items and income taxes	$	38	$	61		$	(23	)

Gross Margin

Gross margin decreased by $33 million for the year ended December 31, 2005, compared to the same period for 2004 and is detailed as follows (in millions):

	Years Ended December 31,
	2005			2004		Decrease
Energy	$	—		$	5		$	(5	)
Contracted and capacity	114			127			(13		)
Incremental realized value of hedges	(1		)	11			(12		)
Unrealized gains	—			3			(3		)
Total	$	113		$	146		$	(33	)

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

· a decrease in contracted and capacity of $13 million related to the expiration of an RMR contract for one of our California generating facilities in 2004, partially offset by income from tolling agreements on those California assets not covered by RMR agreements; and

· a decrease of $12 million in the incremental realized value of hedges is due to favorable price spreads on both power and fuel contracts.

Other Operations

The following table summarizes the operations of our Other Operations segment for the years ended December 31, 2005 and 2004 (in millions):

	Years Ended December 31,						Increase/
	2005			2004			(Decrease)
Realized Gross Margin	$	(39	)	$	(14	)		$	(25	)
Unrealized Gross Margin	85			213				(128		)
Total Gross Margin	46			199				(153		)
Operating expenses:
Operations and maintenance	27			44				(17		)
Depreciation and amortization	13			15				(2		)
Impairment losses	—			2				(2		)
Loss on sales of assets-nonaffiliate	1			1				—
Total operating expenses	41			62				(21		)
Operating income	5			137				(132		)
Total other expense, net	730			6				724
Income (loss) from continuing operations before reorganization items and income taxes	$	(725	)	$	131			$	(856	)

Gross Margin

Gross margin decreased by $153 million for the year ended December 31, 2005, compared to the same period for 2004 and is detailed as follows (in millions):

	Year Ended December 31,						Increase/
	2005			2004			(Decrease)
Energy	$	39		$	(28	)		$	67
Contracted and capacity	(78		)	14				(92		)
Unrealized gains	85			213				(128		)
Total	$	46		$	199			$	(153	)

The decrease in gross margin is primarily due to:

· an increase of $67 million in energy primarily related to an increase in realized margin from our proprietary trading activities;

· a decrease of $92 million in contracted and capacity, which includes a decrease of $335 million in amortization on two TPAs into which we entered in connection with the acquisition of the Mid-Atlantic facilities from Pepco. Under the TPAs, we agreed to supply Pepco its full load requirement in the District of Columbia and in Maryland. The Maryland TPA expired in 2004 and the District of Columbia TPA expired in early 2005. The decrease related to the TPAs was partially offset by an increase of $243 million in realized losses on the Back-to-Back Agreement. In 2006, the Back-to-Back Agreement was transferred to Mirant Power Purchase; and

· a decrease of $128 million related to unrealized gains in our proprietary trading. For the year ended December 31, 2005, we had unrealized losses of $12 million related to our proprietary trading activities and $97 million in unrealized gains from the Back-to-Back Agreement. For the same period in 2004, we had unrealized gains of $45 million related to our proprietary trading activities and $168 million in unrealized gains on the Back-to-Back Agreement.

Operating Expenses

The decrease in operating expenses of $21 million is primarily due to a decrease in operations and maintenance of $17 million resulting from a reduction in allocated corporate costs of $10 million in 2005.

Other Expense, net

The increase in other expense, net of $724 million is primarily due to the recognition in 2005 of $746 million of interest on liabilities that were subject to compromise for the period from the Petition Date through December 31, 2005, and an increase in the gain on sales of investment of $44 million related to the sale of a portion of our investment in ICE in 2005.

Other Significant Consolidated Statements of Operations Comparison

Reorganization Items, net

Reorganization items, net decreased by $53 million for the year ended December 31, 2005, compared to the same period in 2004. Reorganization items represent expense, income or gain and loss amounts that were recorded in the financial statements as a result of the bankruptcy proceedings. For the years ended December 31, 2005 and 2004, this amount included:

	Years Ended December, 31,						Increase/
	2005			2004			(Decrease)
Gain on the implementation of the Plan	$	(30	)	$	—			$	(30	)
Estimated claims and losses on rejected and amended contracts	54			101				(47		)
Professional fees and administrative expense	82			47				35
Interest income, net	(21		)	(10		)		(11		)
Total	$	85		$	138			$	(53	)

Estimated claims and losses on rejected and amended contracts relate primarily to rejected energy contracts, such as tolling agreements, gas transportation and electric transmission contracts and includes a $32 million gain related to the California Settlement.

Discontinued Operations

For the years ended December 31, 2005 and 2004, we reported a net loss from discontinued operations of $3 million and $17 million, respectively, which includes the reclassification of the results of operations related to the planned disposition of our Zeeland and Bosque plants.

Liquidity and Capital Resources

Overview

Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, capital expenditures, collateral requirements, fuel procurement and power sale contract obligations, legal settlements and working capital needs. Net cash flow provided by operating activities totaled $362 million for the year ended December 31, 2006. Net cash flow used in operating activities totaled $192 million and $151 million for the years ended December 31, 2005 and 2004, respectively.

Senior Notes and Senior Secured Credit Facilities

On December 23, 2005, in connection with our emergence from bankruptcy, our subsidiary Mirant North America issued $850 million of 7.375% senior unsecured notes due 2013 (the “Old Notes”). The

Old Notes were issued in a private placement and were not registered with the SEC. The funds from this issuance initially were placed in escrow and were released from escrow on January 3, 2006. On August 4, 2006, Mirant North America completed an exchange offer for the Old Notes, whereby $849.965 million of senior notes registered under the Securities Act (the “New Notes”) were exchanged for an equal amount of the Old Notes. The terms of the New Notes are identical in all material respects to the Old Notes, except that the New Notes are registered under the Securities Act and generally are not subject to transfer restrictions or registration rights. On January 3, 2006, Mirant North America also entered into an $800 million senior secured revolving credit facility and a $700 million senior secured term loan. At the closing, $200 million drawn under the senior secured term loan was deposited into a cash collateral account to support the issuance of up to $200 million of letters of credit.

Sources of Funds and Capital Structure

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 our subsidiaries; (ii) borrowings under Mirant North America’s $800 million six year senior secured revolving credit facility; and (iii) $200 million of letters of credit capacity under Mirant North America’s $700 million term loan; and (iv) preferred shares in Mirant Americas.

Proceeds from the sales of the Zeeland and Bosque plants, expected to be approximately $500 million, will be reinvested in our subsidiary Mirant North America and/or used to retire debt at Mirant North America.

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).

We and our subsidiary Mirant North America are holding companies and, as a result, we are dependent upon dividends, distributions and other payments from our subsidiaries to generate the funds necessary to meet our obligations. The ability of certain of our subsidiaries to pay dividends and distributions is restricted under the terms of their debt or other agreements. We have no operations and no subsidiaries with operations other than Mirant North America and its subsidiaries, including Mirant Mid-Atlantic. The Mirant North America notes and senior secured credit facilities restrict its ability to make distributions. In particular, a significant portion of cash from operations is generated by the power generation facilities of Mirant Mid-Atlantic. Under the Mirant Mid-Atlantic leveraged leases, Mirant Mid-Atlantic is subject to a covenant that restricts its right to make distributions to us and Mirant North America. Mirant Mid-Atlantic’s ability to satisfy the criteria set by that covenant in the future could be impaired by factors which negatively affect the performance of its power generation facilities, including interruptions in operation or curtailment of operations to comply with environmental restrictions.

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 three activities: (i) our asset management and proprietary trading activities; (ii) capital expenditures required to keep our power generation facilities in operation; and (iii) debt service.

Collateral Requirements. Our asset management and, to a lesser extent, proprietary trading activities, represent a significant need for liquidity and capital resources. These liquidity requirements are primarily driven by margin and collateral posting requirements with counterparties and levels of inventory. As of December 31, 2006, we had approximately $38 million of posted cash collateral and $204 million of letters of credit outstanding primarily to support our asset management activities and debt service reserve requirements. Our liquidity requirements are highly dependent on the level of our hedging activity, forward prices for energy, emissions credits and fuel, commodity market volatility and credit terms with third parties.

Capital Expenditures. Capital expenditures for our continuing operations were $127 million, $96 million and $86 million for the years ended December 31, 2006, 2005 and 2004, respectively. Our capital expenditures for 2007 are expected to be approximately $826 million for our continuing business, with approximately $573 million of that amount 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.’’

Debt Service. At December 31, 2006, our continuing operations had approximately $3.3 billion of long-term debt with expected annual interest expense of approximately $255 million. Under the terms of its senior secured term facility, Mirant North America is required to use 50% of its free cash flow for each fiscal year (less amounts paid to us for the purpose of paying interest on our senior notes) to pay down its senior secured term loan, in addition to its scheduled amortization of $7 million per year. The percentage of free cash flow that Mirant North America is required to use to pay down its senior secured term loan may be reduced to 25% upon the achievement by it of a net debt to EBITDA ratio of less than 2:1. At December 31, 2006, the current estimate of the mandatory principal prepayment of the term loan in March 2007 is approximately $131 million.

Mirant Mid-Atlantic Operating Leases. Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively. Mirant Mid-Atlantic has an option to extend the leases. Any extensions of the respective leases would be limited to 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. We are accounting for these leases as operating leases. While there is variability in the scheduled payment amounts over the lease term, we recognize 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. Rent expenses under the Mirant Mid-Atlantic leases were $96 million, $99 million and $103 million for the years ended December 31, 2006, 2005 and 2004, respectively. In addition, Mirant Mid-Atlantic is required to post rent reserves in an aggregate amount equal to the greater of the next six months’ rent, fifty percent of the next twelve months’ rent or $75 million.

Use of Proceeds from Planned Dispositions

Proceeds from the sales of the Zeeland and Bosque plants, expected to be approximately $500 million, will be reinvested in Mirant North America, a subsidiary of Mirant Americas Generation, and/or used to retire debt at Mirant North America.

Debtor-in-Possession Financing for New York Subsidiaries

Mirant North America and Mirant Americas Energy Marketing, (the “Primary DIP Lenders”) entered into the Primary New York DIP Agreement to make secured debtor-in-possession financing in an amount of (i) $20 million, plus (ii) an amount equal to the amount of credit support provided on behalf of

the Mirant New York, Mirant Bowline, Mirant Lovett, and Hudson Valley Gas Corporation (collectively, the ‘‘New York DIP Borrowers’’), to the extent such amounts are collateralized with cash or cash equivalents by the New York DIP Borrowers. The facility is available on a joint and several basis to the New York DIP Borrowers. On January 31, 2006, all the assets of Mirant Americas Energy Marketing were transferred to Mirant Energy Trading, with Mirant Energy Trading to succeed to all rights and assume all obligations of Mirant Americas Energy Marketing under the Primary New York DIP Agreement. The financing under the Primary New York DIP Agreement can be utilized through borrowings by the New York DIP Borrowers, the issuance of letters of credit for the account of any of the New York DIP Borrowers or in support of commercial transactions entered into by Mirant Energy Trading for the benefit of the New York DIP Borrowers, the posting of cash in respect of obligations incurred for the benefit of any of the New York DIP Borrowers, including the making of prepayments for fuel and other commodities for the benefit of any of the New York DIP Borrowers. Under the Primary New York DIP Agreement, the amount which represents the excess on the effective date of the Plan of (x) credit support posted for the benefit of the New York DIP Borrowers by the lenders in respect of transactions entered into on their behalf over (y) the amount of cash collateral posted by the New York DIP Borrowers to the lenders is deemed to be a loan made to the New York DIP Borrowers on such date. The New York DIP Borrowers have posted $5 million cash collateral with Mirant Energy Trading in accordance with the December 31, 2006, collateral allocation performed in good faith by Mirant Energy Trading. To the extent that the required level of credit support provided to the New York DIP Borrowers is reduced, the amount of such reduction is required to be returned to the New York DIP Borrowers. The financing under the Primary New York DIP Agreement has a stated maturity of 180 days, subject to renewal or extension, and is available until the earlier of (x) the expiration of such period or (y) with respect to each of the New York DIP Borrowers, the effective date of a confirmed Plan for such New York DIP Borrower in its Chapter 11 case. The loan has twice been extended such that the stated maturity date is now June 26, 2007. Subject to the authorization of the Bankruptcy Court, the obligations of the New York DIP Borrowers under the Primary New York DIP Agreement, pursuant to Section 364(c) of the Bankruptcy Code, (i) constitute a claim having priority over any or all administrative expenses of the kind specified in sections 503(b) or 507(b) of Bankruptcy Code, (ii) are secured by a lien on property of the estates of the New York DIP Borrowers that is not otherwise subject to a lien and (iii) are secured by a junior lien on property of the estates of the New York DIP Borrowers that is subject to a lien. The financing bears interest at a rate of LIBOR plus 2.25%. The Primary New York DIP Agreement contains certain events of default, and the ability of the New York DIP Borrowers to borrow thereunder is subject to certain conditions precedent. In addition, the Primary New York DIP Agreement contains covenants that, among other things, restrict the ability of the New York DIP Borrowers to engage in mergers, acquisitions and asset sales, to make investments and to incur indebtedness.

Contemporaneous with their entry into the Primary New York DIP Agreement, the New York DIP Borrowers also entered into the Secondary New York DIP Agreement. The Secondary New York DIP Agreement permits Mirant to make secured debtor-in-possession financing in the maximum amount of $50 million to the New York DIP Borrowers, and the borrowings are available solely for cash collateral postings by any one or more of the New York DIP Borrowers. The terms of the Secondary New York DIP Agreement are substantially similar to the terms of the Primary New York DIP Agreement. However, (i) the rights of the Primary DIP Lenders to payment out of cash collateral posted by the New York DIP Borrowers pursuant to the Primary New York DIP Agreement as may be repaid shall at all times rank senior to the rights of Mirant under the Secondary New York DIP Agreement and (ii) certain claims and liens granted under the Primary New York DIP Agreement in respect of cash collateral posted by the New York DIP Borrowers shall at all times be senior to similar claims and liens granted under the Secondary New York DIP Agreement. The loan has twice been extended such that the stated maturity date is now June 26, 2007.

The Bankruptcy Court has approved a debtor-in-possession loan to Mirant NY-Gen from Mirant Americas under which Mirant Americas, subject to certain conditions, would lend up to $16.5 million to Mirant NY-Gen to provide funding for the repairs on the Swinging Bridge dam. The loan has been extended such that the stated maturity date is now June 26, 2007.

Cash Flows

2006 versus 2005

Continuing Operations

Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Cash provided by operating activities from continuing operations increased $538 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 $493 million for the year ended December 31, 2006, compared to the same period in 2005. See “Results of Operations” for additional discussion of our improved performance in 2006 compared to the same period in 2005;

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

· an increase in bankruptcy related claims and expenses of $662 million. In 2006 we paid bankruptcy claims and professional fees of $1.773 billion, of which $765 million is reflected in cash from operations. Our remaining claims payable and estimated claims accrual is $5 million at December 31, 2006. We paid $103 million in the year ended December 31, 2005 related to professional fees and other expenses associated with the bankruptcy proceedings.

Investing Activities. Net cash used in investing activities from continuing operations was $30 million for the year ended December 31, 2006, compared to $34 million in 2005. This difference was primarily due to the following:

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

· an increase in the proceeds from the sales of assets and investments of $45 million. In 2006, we received $97 million in proceeds from the sales of assets and investments, which included $12 million from the sale of the Mirant Service Center, $20 million from the sale of our investment in the New York Mercantile Exchange and $58 million from the sale of a portion of our investment in ICE. In 2005, proceeds from the sales of assets and investments were $52 million and included $48 million from the sale of a portion of our investment in ICE and $4 million in additional proceeds from the 2004 sale of the Bowline gas turbines; and

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

Financing Activities. Net cash provided by financing activities from continuing operations was $5 million for the year ended December 31, 2006, compared to $18 million for the same period in 2005. This difference was primarily due to the following:

· an increase in proceeds from the issuance of long-term debt of approximately $2 billion. Proceeds from the issuance of long-term debt in 2006 included $850 million from the Mirant North America debt offering that was released from escrow on January 3, 2006, $700 million from the Mirant North America senior secured loan and $465 million drawn on the Mirant North America senior secured revolving credit facility. In 2006 we also incurred $51 million in debt issuance costs.

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

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

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

Discontinued Operations

Cash provided by operating activities from discontinued operations increased $16 million for the year ended December 31, 2006, compared to the same period in 2005, primarily due to an increase of $14 million in realized gross margin.

2005 versus 2004

Continuing Operations

Operating Activities. Cash used in operating activities from continuing operations increased $39 million for the year ended December 31, 2005, compared to the same period in 2004, primarily due to the following:

· a decrease in cash used due to a $284 million increase in gross margin, excluding unrealized gains and losses and TPA amortization. See “Results of Operations” for additional discussion;

· an increase in cash used of $231 million due to a $182 million increase in the collateral required to support commercial operations and $49 million of collateral posted related to the Mirant Mid-Atlantic leases; and

· an increase in cash used of $32 million for 2005 payments under the settlement agreement related to the Mirant Mid-Atlantic leases.

Investing Activities. Net cash used in investing activities from continuing operations was $34 million for the year ended December 31, 2005, compared to $282 million cash provided in 2004. This difference is primarily due to the following:

· capital expenditures were $96 million in 2005 compared to $86 million for the same period in 2004;

· in 2005, proceeds from the sales of assets and investments was $52 million and included $48 million from the sale of a portion of our investment in ICE and $4 million related to the sale of the Bowline turbines. In 2004, proceeds from the sales of assets and investments was $42 million related to the sale of the Bowline turbines; and

· in 2005, we received repayments on notes receivable from affiliates of $10 million compared to $325 million in 2004.

Financing Activities. Net cash provided by financing activities from continuing operations increased $13 million for the year ended December 31, 2005, compared to the same period in 2004. Proceeds from the issuance of long-term debt—affiliate was $21 million in 2005. We received $7 million from Mirant Americas under the make-whole contract in 2004.

Discontinued Operations

Cash provided by operating activities from discontinued operations decreased $2 million for the year ended December 31, 2005, compared to the same period in 2004 primarily due to an increase in operating expenses of $7 million, partially offset by an increase in gross margin of $4 million.

Total Cash, Cash Equivalents and Credit Facility Availability

At December 31, 2006, we have total cash, cash equivalents, and credit facility availability of approximately $1.4 billion. The table below sets forth total cash, cash equivalents and availability of credit facilities of Mirant Americas Generation and our subsidiaries at December 31, 2006 and 2005 (in millions):

	At December 31, 2006			At December 31, 2005
Cash and Cash Equivalents:
Mirant Americas Generation		$	—		$	129
Mirant North America		678			19
Mirant Mid-Atlantic		75			276
Total cash and cash equivalents		753			424
Less: Cash restricted due to bankruptcy of New York entities and reserved for working capital and other purposes		102			1
Total available cash and cash equivalents		651			423
Available under credit facilities		796			—
Available under the DIP Facility		—			249
Total cash, cash equivalents and credit facilities availability		$	1,447		$	672

Mirant North America’s ability to pay dividends is restricted under the terms of its debt agreements. At December 31, 2006, Mirant North America had distributed to us all available cash that was permitted to be distributed under the terms of its debt agreements. After taking into account the financial results of Mirant North America for the twelve months ended December 31, 2006, we expect Mirant North America will be able to distribute approximately $131 million in March 2007.

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

· expected collateral posted in support of our business;

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

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

· seasonal and intra-month working capital requirements; and

· other unforeseen events.

Our capital expenditures for 2007 and 2008 are expected to be approximately $826 million and $802 million, respectively. This forecast does not assume any construction of new generating units during the

forecast period. Instead, the current capital expenditure program, which is expected to be funded by operating cash flow, focuses on efficiency, safety, reliability, compliance with existing environmental laws and contract obligations. 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.

Cash Collateral and Letters of Credit

In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, we are often required to provide trade credit support to our counterparties or make deposits with brokers. In addition, we are often required to provide cash collateral or letters of credit for access to the transmission grid, to participate in power pools, to fund debt service reserves and for other operating activities. Trade credit support includes cash collateral, letters of credit and financial guarantees. In the event that we default, the counterparty can draw on a letter of credit or apply cash collateral held to satisfy the existing amounts outstanding under an open contract. At December 31, 2006, our outstanding issued letters of credit totaled $204 million.

The following table summarizes cash collateral posted with counterparties and brokers and letters of credit issued as of December 31, 2006 and 2005 (in millions):

	At December 31, 2006			At December 31, 2005
Continuing operations:
Cash collateral posted—energy trading and marketing		$	27		$	619
Cash collateral posted—debt service and rent reserves		—			56
Cash collateral posted—other operating activities		11			10
Letters of credit—energy trading and marketing		100			51
Letters of credit—debt service and rent reserves		84			—
Letters of credit—other operating activities		15			—
		237			736
Discontinued operations:
Assets held for sale—letters of credit		5			5
Total		$	242		$	741

On July 13, 2006, Moody’s Investors Service reduced Mirant’s corporate credit rating to “B2” and our debt rating was also lowered. Standard and Poor’s also announced that they had placed Mirant’s corporate credit rating and our debt rating on credit watch.

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

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

	Total		2007		2008		2009		2010		2011		>5 years
Mirant Mid-Atlantic operating leases	$	2,246	$	112	$	121	$	142	$	140	$	134		$	1,597
Other operating leases	34		4		4		4		4		3			15
Long-term debt	5,725		396		260		260		260		1,063			3,486
Claims payable and estimated claims accrual	5		5		—		—		—		—			—
Purchase commitments:
Long-term service agreements	33		3		1		2		2		2			23
Fuel commitments	418		263		89		66		—		—			—
Other purchase commitments	172		172		—		—		—		—			—
Total excluding liabilities subject to compromise	8,633		955		475		474		406		1,202			5,121
Liabilities subject to compromise	34
Discontinued operations	187
Total debt obligations, off-balance sheet arrangements and contractual obligations	$	8,854

Operating leases are off-balance sheet arrangements and are discussed in Note 15 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 10 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.

Claims payable and estimated claims accrual primarily consists of allowed bankruptcy claims, estimated unresolved bankruptcy claims that are to be settled in cash and professional fees associated with the bankruptcy proceedings.

Long-term service agreements represent our total estimated commitments under our long-term service agreements associated with turbines installed or in storage and are discussed in Note 15 to our consolidated and combined financial statements contained elsewhere in this report.

Fuel commitments primarily relate to long-term coal agreements and other fuel purchase agreements. 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.

Liabilities subject to compromise on the consolidated balance sheets at December 31, 2006, relate only to our New York subsidiaries that remain in bankruptcy and are discussed in Note 12 to our consolidated and combined financial statements contained elsewhere in this report.

Discontinued operations include the debt and obligations of our Zeeland and Bosque natural gas-fired plants.

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 Trading and Marketing Activities

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

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

The fair value model has historically been used for derivative energy contracts that economically hedge our electricity generation assets or that are used in our proprietary trading activities. We use a variety of derivative contracts, such as futures, swaps and option contracts, in the management of our business. Such derivative contracts have varying terms and durations, or tenors, which range from a few days to a number of years, depending on the instrument.

Pursuant to SFAS 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. We currently defer inception gains and losses in accordance with EITF 02-3. Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of completing forecasted transactions to be critical accounting estimates. These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors. The fair value of derivative contracts is included in price risk management assets and

liabilities affiliate and nonaffiliate in our consolidated balance sheets. Transactions that do not qualify for accounting under SFAS 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 and liabilities affiliate and nonaffiliate in our consolidated balance sheets is also affected by our assumptions as to interest rate, counterparty credit risk and liquidity risk. The nominal value of the contracts is discounted using a forward interest rate curve based on LIBOR. In addition, the fair value of our derivative contracts is reduced to reflect the estimated risk of default of counterparties on their contractual obligations to us.

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 6 to our consolidated and combined financial statements for further information on financial instruments related to energy trading and marketing activities.

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

Long-Lived Assets

Estimated Useful Lives

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

Key Assumptions and Approach Used. Estimated useful lives are the mechanism by which we allocate the cost of long-lived assets over the asset’s service period. We perform depreciation studies periodically to update changes in estimated useful lives. The actual useful life of an asset could be affected by changes in estimated or actual commodity prices, environmental regulations, various legal factors, competitive forces and our liquidity and ability to sustain required maintenance expenditures and satisfy asset retirement obligations. We use composite depreciation for groups of similar assets and establish an average useful life for each group of related assets. In accordance with SFAS No. 144, we cease depreciation on long-lived assets classified as available for sale. See Note 7 to our consolidated and combined financial statements for additional information related to our property, plant and equipment.

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

Asset Retirement Obligations

Nature of Estimates Required. We account for asset retirement obligations under SFAS 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 have a noncurrent liability of $41 million recorded as of December 31, 2006. 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 definite-lived 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.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

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

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 regions in which we operate, facility outages, weather and general economic conditions. As a result of these influences, the cost of fuel and electricity prices do not always change in the same magnitude or direction, which results in conversion spreads for a particular generation facility widening or narrowing (or becoming negative) over time.

Through our asset management activities, we enter into a variety of exchange-traded and OTC energy and energy-related derivative contracts, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage our exposure to commodity price 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. Our proprietary trading activities also utilize similar contracts in markets where we have a physical presence to attempt to generate incremental gross margin.

Derivative energy contracts required to be reflected at fair value are presented as price risk management assets and liabilities-affiliate and price risk management assets and liabilities-nonaffiliate 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 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 eleven months. The net notional amount, or net short position, of the price risk management assets and liabilities-affiliate and price risk management assets and liabilities-nonaffiliate at December 31, 2006, was approximately 24 million equivalent MWh.

The following table provides a summary of the factors affecting the change in net fair value of the price risk management asset and (liability) accounts in 2006 (in millions):

	Proprietary Trading				Asset Management				Total
Net fair value of portfolio at December 31, 2005		$	40			$	(155	)	$	(115	)
Gains recognized in the period, net		29				411			440
Contracts settled during the period, net		(23		)		192			169
Net fair value of portfolio at December 31, 2006		$	46			$	448		$	494

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

	Net Price Risk Management
	Assets							Liabilities								Net Fair Value at
	Current				Noncurrent			Current				Noncurrent				December 31, 2006
Electricity		$	619			$	104		$	(260	)		$	(12	)		$	451
Natural Gas		21				1			(26		)		(2		)		(6		)
Oil		83				—			(10		)		(29		)		44
Coal		13				—			(3		)		—				10
Other, including credit reserve		(5		)		—			—				—				(5		)
Total		$	731			$	105		$	(299	)		$	(43	)		$	494

Value at Risk

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

We manage the price risk associated with asset management activities through a variety of methods. Our Risk Management Policy requires that asset management activities are restricted to only those activities that are risk-reducing 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. While the net result of these transactions is risk reducing, the timing of the roll-off could result in volatility in the gross margin results. To ensure that fuel oil management activities are risk-reducing in aggregate, a VaR limit of $5 million was established in the Risk Management Policy effective December 14, 2006.

The average VaR of our fuel oil management activities, using a five day holding period and a 95% confidence interval, was $2 million for the year ended December 31, 2006, and the VaR at December 31, 2006 was $2 million. If we assumed VaR levels using a one-day holding period for all positions in our fuel oil management portfolio, based on a 95% confidence interval, our average portfolio VaR for the year ended December 31, 2006 was $1 million and the VaR at December 31, 2006, was $1 million. This VaR control was initiated on December 14, 2006, and actual daily loss versus one-day VaR calculations are not available for the calendar year.

Our Risk Management Policy sets a VaR limit with respect to our proprietary trading activities of $7.5 million. See “Critical Accounting Policies and Estimates” for accounting treatment for asset management and proprietary trading activities.

The average VaR for our proprietary trading activities, using a five-day holding period and a 95% confidence level, was $3 million for the year ended December 31, 2006, and the VaR at December 31, 2006, was $4 million. If we assumed VaR levels using a one-day holding period for all positions in our proprietary trading portfolio, based on a 95% confidence level, our average portfolio VaR for the year ended December 31, 2006, was $1 million and the VaR at December 31, 2006, was $2 million. During the year ended December 31, 2006, the actual daily loss on a fair value basis exceeded the corresponding one-day VaR calculation 14 times, which is reasonable given our 95% confidence level.

Interest Rate Risk

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

Our total debt from continuing operations is subject to variable interest rates through either the Mirant North America Term Loan or Revolving credit facility. Assuming they are fully drawn, this debt totals approximately $1.5 billion. A 1% per annum increase in the average market rate would result in an increase in our annual interest expense of approximately $15 million for continuing operations.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty failed to perform under its contractual obligations. We have established controls and procedures in our Risk Management Policy to determine and monitor the creditworthiness of customers and counterparties. Our credit policies are established and monitored by the Risk Oversight Committee. The Risk Oversight Committee includes the Chief Financial Officer and management’s representatives from several functional areas. We 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.

Collection Risk

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

MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)

DECEMBER 31, 2006 CONSOLIDATED STATEMENT OF EQUITY AND COMPREHENSIVE INCOME (LOSS)
AND
DECEMBER 31, 2005 and 2004 COMBINED STATEMENTS OF EQUITY (DEFICIT) AND COMPREHENSIVE INCOME (LOSS)

(in millions)

													Accumulated
					Preferred								Other
	Member’s				Stock in				Investment				Comprehensive				Comprehensive
	Interest				Affiliate				by Mirant				Income				Income / (Loss)
Balance, December 31, 2003		$	—			$	—			$	(439	)		$	—
Net income		—				—				106				—
Capital contributions—payments received from Mirant Americas under make-whole agreement		—				—				7				—
Balance, at December 31, 2004		—				—				(326		)		—
Net loss		—				—				(779		)		—				$	(779	)
Contribution of net assets and liabilities from Mirant under the Plan		—				—				1,781				—				—
Other comprehensive income		—				—				—				27				27
Comprehensive loss																		(752		)
Change in member pursuant to the Plan		995				(319		)		(676		)		—
Balance, at December 31, 2005		995				(319		)		—				27
Net income		1,200				—				—				—				1,200
Amortization of discount on preferred stock in affiliate		20				(20		)		—				—				—
Distribution to member		(236		)		—				—				—				—
Capital contributions		4				—				—				—				—
Other comprehensive loss		—				—				—				(27		)		(27		)
Comprehensive income																		$	1,173
Balance, at December 31, 2006		$	1,983			$	(339	)		$	—			$	—

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

MIRANT AMERICAS GENERATION, 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

(in millions)

	Years Ended December 31,
	2006			2005			2004
Cash Flows from Operating Activities:
Net income (loss)	$	1,200		$	(779	)	$	106
Income (loss) from discontinued operations	10			(3		)	(17		)
Income (loss) from continuing operations	1,190			(776		)	123
Adjustments to reconcile net income (loss) from continuing operations to net cash provided by (used in) operating activities:
Equity income in affiliates, net of dividends	—			—			1
Depreciation and amortization	132			120			112
Amortization of transition power agreements and other obligations	—			(9		)	(344		)
Impairment charges	119			—			2
Non-cash post-petition interest expense	—			746			—
Loss (gain) on sales of assets and investments	(83		)	(43		)	65
Cumulative effect of changes in accounting principles	—			16			—
Non-cash charges for reorganization items	1			8			99
Effects of the Plan	—			(30		)	—
Price risk management activities, net	(609		)	23			(172		)
Non-cash gain on property tax settlement	(71		)	—			—
Deferred income tax	—			(11		)	1
Other, net	(23		)	2			(2		)
Changes in operating assets and liabilities:
Affiliate accounts receivable, net	9			(296		)	(17		)
Customer accounts receivable, net	115			(112		)	51
Prepaid rent	(9		)	(9		)	(23		)
Inventories	(11		)	(17		)	(63		)
Other assets	460			(376		)	(33		)
Accounts payable and accrued liabilities	(210		)	117			(105		)
Settlement of claims payable	(765		)	404			—
Payable to affiliate	(7		)	—			117
Property taxes accrued, affiliate	—			—			(14		)
Property taxes accrued, nonaffiliate	55			25			48
Other liabilities	37			10			(15		)
Total adjustments	(860		)	568			(292		)
Net cash provided by (used in) operating activities of continuing operations	330			(208		)	(169		)
Net cash provided by operating activities of discontinued operations	32			16			18
Net cash provided by (used in) operating activities	362			(192		)	(151		)
Cash Flows from Investing Activities:
Capital expenditures	(127		)	(96		)	(86		)
Repayments of notes receivable from affiliate	—			10			325
Repayments of notes receivable from nonaffiliate	—			—			1
Proceeds from the sales of assets and investments, net	97			52			42
Net cash provided by (used in) investing activities of continuing operations	(30		)	(34		)	282
Net cash used in investing activities of discontinued operations	(6		)	(4		)	(2		)
Net cash provided by (used in) investing activities	(36		)	(38		)	280
Cash Flows from Financing Activities:
Proceeds from issuance of debt-affiliate	—			21			—
Proceeds from issuance of long-term debt-nonaffiliate	2,015			—			—
Repayment of debt-affiliate	(9		)	—			—
Repayment of long-term debt-nonaffiliate	(474		)	(3		)	(2		)
Payments received under make-whole agreement	—			—			7
Settlement of member’s obligation under the Plan	(990		)	—			—
Debt issuance costs	(51		)	—			—
Payment to affiliate under the Plan	(250		)	—			—
Distribution to member	(236		)	—			—
Net cash provided by financing activities of continuing operations	5			18			5
Net cash used in financing activities of discontinued operations	(2		)	—			(1		)
Net cash provided by financing activities	3			18			4
Net Increase (Decrease) in Cash and Cash Equivalents	329			(212		)	133
Cash and Cash Equivalents, beginning of period	424			636			503
Cash and Cash Equivalents, end of period	$	753		$	424		$	636
Supplemental Cash Flow Disclosures:
Cash paid for interest, net of amounts capitalized	$	220		$	29		$	13
Cash paid for claims and professional fees from bankruptcy	$	1,773		$	103		$	60
Refunds received from income tax	$	—		$	—		$	(2	)
Financing Activity:
Capital contribution—non-cash	$	4		$	—		$	—

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

MIRANT AMERICAS GENERATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

1. Description of Business and Organization

Mirant Americas Generation is a national independent power producer and an indirect wholly-owned subsidiary of Mirant. Mirant Americas Generation generates revenues primarily through the production of electricity. 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 the Company’s indirect wholly-owned subsidiary, Mirant Mid-Atlantic, its interest in Zeeland, and its interest in the following: Mirant Americas Energy Marketing, Mirant Americas Development, Inc., Mirant Americas Production Company, Mirant Americas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas Retail Energy Marketing, LP, and Mirant Americas Gas Marketing, LLC (collectively, the “Trading Debtors”) to Mirant North America. All of the contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.” On January 31, 2006, the trading and marketing business of the Trading Debtors was transferred to Mirant Energy Trading, a wholly-owned subsidiary of Mirant North America. After these transfers took place, the Trading Debtors were transferred to a trust created under the Plan that is not affiliated with the Company.

The Company produces and sells substantially all of the output from its generating facilities in the forward and spot markets and the remainder under contracts with third parties. 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. The Company is a Delaware limited liability company. As of December 31, 2006, the Company owned or leased 12,099 MW of electric generating capacity.

In the third quarter of 2006, Mirant commenced auction processes to sell certain natural gas-fired plants, including the Company’s Zeeland (903 MW) and Bosque (546 MW) plants. On January 15, 2007, the Company entered into a definitive purchase and sale agreement with a subsidiary of LS Power Equity Partners I, L.P., LS Power Equity Partners II, L.P. and certain other affiliated funds, (collectively, “LS Power”), for the sale of the Company’s Zeeland and Bosque natural gas-fired plants. The net proceeds from the sales are expected to be approximately $500 million, after transaction costs. The transaction is expected to close in the second quarter of 2007 after the satisfaction of certain customary conditions. See Note 3 for additional information related to discontinued operations.

After giving effect to the aforementioned sales, Mirant Americas Generation’s continuing operations of 10,650 MW consist of the ownership, long-term lease and operation of power generation facilities

located in markets in the Mid-Atlantic and Northeast regions of the United States and in California, and energy trading and marketing operations in Atlanta, Georgia.

The Company has a number of service agreements for labor and administrative services with Mirant Services. In addition, Mirant Energy Trading, and previously Mirant Americas Energy Marketing, provides services to other Mirant affiliates related to the sale of electric power and the procurement of fuel and emissions allowances. These agreements are discussed further in Note 9.

2. Accounting and Reporting Policies

Basis of Presentation

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

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

In accordance with SFAS No. 144, the results of operations of the Company’s assets to be disposed of have been reclassified to discontinued operations and the associated assets and liabilities have been reclassified to assets and liabilities held for sale for all periods presented. In addition, the accompanying consolidated and combined statements of cash flows present the cash flows from discontinued operations in each of the three major categories (operating, investing and financing activities). The combined statements of cash flows for the years ended December 31, 2005 and 2004, were revised to conform to this presentation. See Note 3 for additional information regarding discontinued operations.

Certain prior period amounts have been reclassified to conform to the current year financial statement presentation.

Use of Estimates

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

· determining the fair value of certain derivative contracts;

· 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 Americas Generation recognizes affiliate and nonaffiliate revenue when electric power is delivered, capacity is made available or ancillary services are provided to an affiliate or to a customer pursuant to contractual commitments that specify volume, price and delivery requirements, and collection of such revenue is probable. Some sales of energy are based on economic dispatch, or “as-ordered” by an ISO based on member participation agreements, but without an underlying contractual commitment. ISO revenues and revenues 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. When a long-term electric power agreement conveys to the buyer of the electric power the right to use the generating capacity of Mirant Americas Generation’s plant, that agreement is evaluated to determine if it is a lease of the generating facility rather than a sale of electric power. Operating lease revenue for the Company’s generating units is normally recorded as capacity revenue and included in generation revenues in the consolidated and combined statements of operations.

Derivative Financial Instruments

Derivative financial instruments are recorded in the accompanying consolidated balance sheets at fair value as either price risk management assets or liabilities-affiliate or price risk management assets or liabilities-nonaffiliate, and changes in fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. 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 and liabilities-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. Mirant North America’s derivative financial instruments are categorized by the Company, based on the business objective the instrument is expected to achieve: asset management or proprietary trading. All derivative contracts are recorded at fair value, except for a limited number of transactions that qualify for the normal purchases or normal sales exclusion from SFAS 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. For asset management activities, 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. Changes in the fair value and settlements of contracts for proprietary trading activities are recorded as net operating revenue affiliate and nonaffiliate in the accompanying consolidated and combined statements of operations.

Concentration of Revenues

In 2006, 2005 and 2004, the Company earned a significant portion of its operating revenue and gross margin from the PJM energy market, where its Mirant Mid-Atlantic generation facilities are located. Mirant Mid-Atlantic’s revenues and gross margins as a percentage of the Company’s total revenues and gross margin from continuing operations are as follows:

	Years Ended December 31,
	2006			2005			2004
Revenues		58	%		40	%		29	%
Gross margins		67	%		54	%		46	%

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 64% of the employees of the Company’s continuing operations are subject to collective bargaining agreements.

Cash and Cash Equivalents

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

Restricted Cash

Restricted cash is included in current and noncurrent assets as funds on deposit in the accompanying consolidated balance sheets. As of December 31, 2006, current and noncurrent funds on deposit are $233 million and $6 million, respectively. As of December 31, 2005, current and noncurrent funds on deposit are $1.5 billion and $5 million, respectively. Restricted cash includes deposits with brokers and cash collateral posted with third parties to support the Company’s commodity positions as well as a $200 million deposit Mirant North America posted under its senior secured term loan to support the issuance of letters of credit. In addition, as of December 31, 2005, restricted cash included $853 million of escrowed proceeds from a bond offering in December 2005. These amounts were released from escrow on January 3, 2006.

Inventory

Inventory consists primarily of oil, coal, purchased emissions allowances and materials and supplies. Inventory, including commodity trading inventory, is generally stated at the lower of cost or market value. Fuel stock is removed from the inventory account as it is used in the production of electricity. Materials and supplies are removed from the inventory account when they are used for repairs, maintenance or capital projects.

Emissions Allowances

Purchased emissions allowances are recorded in inventory at the lower of cost or market value. Cost is computed on an average cost basis. Purchased emissions allowances for SO2 and NOx are removed from inventory and charged to cost of fuel, electricity and other products in the accompanying 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 14 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. In addition the Company acquired emissions allowances for future periods as part of the California Settlement. These allowances are included in other intangible assets and will be amortized over the periods in which they may be utilized.

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.

Capitalization of Interest Cost

The Company capitalizes interest on projects during the advanced stages of development and during the construction period. The Company determines which debt instruments represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest costs are included in the calculation of the weighted average interest rate used for determining the capitalization rate. Upon commencement of commercial operations of the plant or project, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. For the years ended December 31, 2006, 2005 and 2004, the Company incurred the following interest costs on debt to nonaffiliates (in millions):

	For the Years Ended December 31,
	2006			2005		2004
Total interest costs:	$	298		$	759		$	4
Interest capitalized and included in construction work in progress:	(9		)	—			—
Total interest expense—nonaffiliate:	$	289		$	759		$	4

In the third quarter of 2005, the Company determined that it was probable that contractual interest on liabilities subject to compromise from the Petition Date would be incurred for certain claims expected to be allowed under the Plan and, accordingly, recorded approximately $746 million of interest expense in 2005 on liabilities subject to compromise.

Environmental Remediation Costs

The Company accrues for costs associated with environmental remediation when such costs are probable and can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the 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.

Debt Issuance Costs

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

Income Taxes

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

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

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 reimbursing Mirant for their intercompany tax obligations attributable to their operations. Accordingly, the Company’s income tax receivables and payables with Mirant or Mirant Americas were resolved pursuant to a global settlement under the Plan whereby intercompany receivables and payables received no distribution, with the exception of income tax payables and receivables related to Mirant New York which continues to remain in bankruptcy at December 31, 2006.

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

On January 15, 2007, the Company entered into a definitive purchase and sale agreement with a subsidiary of LS Power Equity Partners I, L.P., LS Power Equity Partners II, L.P. and certain other affiliated funds, (collectively “LS Power”), for the sale of the Zeeland and Bosque natural gas-fired plants discussed above. The net proceeds to the Company are expected to be approximately $500 million, after transaction costs. The sale of the Zeeland and Bosque natural gas-fired plants is subject to the terms of the Mirant North America credit facilities and senior notes, including the provisions with respect to the use of the proceeds of such sales to repay amounts under the senior term loans and/or reinvest with the sale proceeds. The transaction is expected to close in the second quarter of 2007 after the satisfaction of certain customary conditions to closing. See Note 10 for additional information regarding restrictions on the proceeds from the sale of the gas assets.

The table below presents the components of the balance sheet accounts classified as assets and liabilities held for sale for the years ended December 31, 2006 and 2005 (in millions):

	At December 31,
	2006		2005
Current Assets	$	22	$	29
Property, Plant and Equipment	497		513
Noncurrent Assets	—		1
Total Assets	$	519	$	543
Current Liabilities	$	5	$	5
Noncurrent Liabilities	11		11
Total Liabilities	$	16	$	16

Assets held for sale at December 31, 2006, consisted of the planned dispositions discussed above. Assets held for sale at December 31, 2005, consisted of the planned dispositions discussed above plus $7 million related to the Mirant Service Center in Maryland. The sale of the Mirant Service Center closed in the second quarter of 2006, and the Company recognized a gain of approximately $6 million.

Liabilities held for sale included $11 million at December 31, 2006 and 2005, related to the Zeeland capital lease and are included in other current liabilities on the consolidated balance sheets.

During the fourth quarter of 2004, the Company entered into an agreement to dispose of three natural gas turbines related to a suspended construction project. The sale resulted in the Company receiving $42 million in the fourth quarter of 2004 and $4 million in the first quarter of 2005. As a result, the Company in the year ended December 31, 2004, recognized a loss related to these turbines of $65 million which is included in loss (gain) on sales of assets, net in the combined statements of operations.

Measurement of Assets Held for Sale

In accordance with SFAS No. 144, an asset classified as held for sale shall be measured at the lower of carrying value or fair value less costs to sell.

Pursuant to the definitive purchase and sale agreement entered into by Mirant with LS Power, the Zeeland and Bosque plants will be sold in a single transaction. The Company recorded an impairment loss of $71 million in the third quarter of 2006 to write down the Zeeland asset to its estimated fair value less cost to sell. As a result of updated fair values along with changes to the working capital calculation in the purchase and sale agreement, the Company recorded a reduction to the impairment loss of $63 million in the fourth quarter of 2006. The net 2006 impairment loss of $8 million was recorded in discontinued operations in the Company’s consolidated statement of operations for the year ended December 31, 2006 to decrease the carrying value of the assets to their fair value less costs to sell.

Discontinued Operations

The Company has reclassified amounts for prior periods in the financial statements to report separately, as discontinued operations, the revenues and expenses of components of the Company that have been disposed of or have met the required criteria for such classification at December 31, 2006.

A summary of the operating results for these discontinued operations for the years ended December 31, 2006, 2005 and 2004 are as follows (in millions):

	December 31,
	2006			2005				2004
Operating revenues		$	54		$	74		$	89
Operating expenses(1)		43			74			94
Operating income (loss)		11			—			(5		)
Other expense, net		1			3			12
Net income (loss)		$	10		$	(3	)	$	(17	)

(1) Includes a net impairment loss of $8 million in 2006.

Other Commitments

Mirant Americas Generations has commitments under fuel and transportation, long term service agreements and other purchase commitments with various terms and expiration dates that are related to its discontinued operations. The total of these commitments as of December 31, 2006, is approximately $187 million.

4. Impairments on Assets Held and Used

In accordance with SFAS No. 144, an asset classified as held and used shall be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An asset impairment charge must be recognized if the sum of the undiscounted expected future cash flows from a long-lived asset is less than the carrying value of that asset. The amount of any impairment charge is calculated as the excess of the carrying value of the asset over its fair value. Fair value is estimated based on the discounted future cash flows from that asset or determined by other valuation techniques.

Current Year Events

The Mirant Lovett and Mirant Bowline generation facilities in New York have been subject to disputes with local tax authorities regarding property tax assessments. In addition, Mirant New York and Mirant Lovett entered into the 2003 Consent Decree to resolve issues related to NSR requirements under the Clean Air Act related to the Lovett plant. Mirant Lovett is in discussions with the NYSDEC and the New York State Office of the Attorney General regarding environmental controls under the 2003 Consent Decree.

Under the 2003 Consent Decree, Mirant Lovett is required to make an election to install certain environmental controls on units 5 and 4 of the Lovett facility or shut down those units by April 30, 2007

and April 30, 2008, respectively. On September 19, 2006, Mirant Lovett sought Bankruptcy Court approval to discontinue operations at units 3 and 5 of the Lovett generation facility if an alternative environmental compliance mechanism that is agreeable to the State of New York is not approved by April 30, 2007. On October 18, 2006, the Bankruptcy Court approved the Company’s request. On October 19, 2006, Mirant Lovett submitted notices of its intent to discontinue operations at units 3 and 5 of the Lovett facility on April 30, 2007, to the New York Public Service Commission, NYISO, Orange and Rockland and several other affected transmission and distribution utilities in New York. Mirant Lovett reserved its rights to withdraw these notices if a viable alternative environmental compliance mechanism is found. See New York State Administrative Claim in Note 17—Litigation and Other Contingencies for additional information.

On December 14, 2006, the Bankruptcy Court approved a settlement of disputed property taxes among Mirant Bowline, Mirant Lovett, Hudson Valley Gas and various New York tax jurisdictions. The settlement resolves pending disputes regarding refunds sought by the Company’s New York subsidiaries for property taxes paid for 1995 through 2003 and unpaid taxes assessed for 2003 through 2006. Under the settlement, in February 2007, the Company received refunds totaling approximately $163 million for 1995 through 2002, and paid unpaid taxes of approximately $115 million for 2003 through 2006, resulting in receipt of a net cash amount of $48 million. As a result of the refunds and the reductions in unpaid taxes under the settlement, the Company recognized a gain of $244 million in the fourth quarter of 2006. Of this amount, $163 million was included in reorganization items, net in the consolidated statement of operations as it related to periods prior to the Petition Date.

Asset Grouping

For purposes of measuring an impairment loss, a long-lived asset or assets must be grouped at the lowest level of independent identifiable cash flows. All of the units at Mirant Lovett were viewed as one group. For Bowline, the Company determined that the suspended Bowline unit 3 construction project was independent of the operating Bowline units. In addition, the Company’s analysis and planning around the operating Bowline units 1 and 2 did not consider the suspended construction project for Bowline unit 3.

Assumptions and Results

In its impairment analysis of the Bowline and Lovett generation facilities in prior periods, the Company assumed that PILOT agreements covering 2006 and seven subsequent years would be successfully approved and implemented. The Company no longer expects such PILOT agreements to be implemented. The August 2006 decisions and the appeals that followed prompted management to test for recoverability of the asset under SFAS No. 144 because additional uncertainty existed related to achieving property taxation levels that would allow economically feasible operation of the Bowline and Lovett generation facilities. As a result of these developments, management re-reviewed the economic viability of these facilities in the third quarter of 2006.

Lovett. The Company’s assessment of Lovett under SFAS No. 144 in the third quarter of 2006 involved estimating property tax refunds and payments and assuming that property taxes would be negotiated to a reasonable level for future periods. Among the multiple scenarios considered were the shut down of units 3 and 5 by April 30, 2007, and unit 4 by April 30, 2008. The Company also considered scenarios that would allow operations past April 2008 because the Company continues to work with the State of New York and other parties to achieve a solution related to environmental controls and to allow Lovett to continue to contribute to the reliability of the electric system of the State of New York. The sum of the probability weighted undiscounted cash flows for the Lovett generation facility exceeded the Company’s carrying value at September 30, 2006. As the refunds and taxes owed agreed upon in the settlement agreement were not materially different from the estimates used in the impairment analysis, the Company determined that no further analysis was needed at December 31, 2006.

Bowline Units 1 and 2. The Company’s assessment of Bowline units 1 and 2 under SFAS No. 144 in the third quarter of 2006 involved estimating property tax refunds and payments and assuming that property taxes would be negotiated to levels for future periods that would allow Bowline units 1 and 2 to operate until the end of their remaining economic useful lives. The sum of the undiscounted cash flows exceeded the Company’s carrying value at September 30, 2006, for Bowline units 1 and 2. As the refunds and taxes owed agreed upon in the settlement agreement were not materially different from the estimates used in the impairment analysis, the company determined that no further analysis was needed at December 31, 2006.

Bowline Unit 3. The Company’s assessment of the Bowline unit 3 suspended construction project assumed that completion of this project was remote. A strategic review of the Company’s portfolio of assets in 2006 resulted in the conclusion that the Bowline 3 project as currently configured and permitted is not economically viable. As a result of this conclusion, the Company determined the estimated value of the equipment and project termination liabilities. At December 31, 2006, the carrying value of the development and construction costs for Bowline unit 3 exceeded the estimated undiscounted cash flows from the abandonment of the project by $120 million, which is reflected in impairment losses on the consolidated statement of operations for the year ended December 31, 2006. On January 15, 2007, the Company entered into a definitive purchase and sale agreement with LS Power, for the sale of certain natural gas-fired plants, which includes some of the equipment at Bowline unit 3. The transaction is expected to close in the second quarter of 2007. The sale of the equipment at Bowline unit 3 has been approved by the Bankruptcy Court.

5. Inventory

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

	At December 31,
	2006			2005
Fuel		$	196		$	202
Materials and supplies		63			58
Emissions allowances		29			15
Total inventory		$	288		$	275

6. Financial Instruments

Commodity Financial Instruments

The Company manages the risks around fuel supply and power to be generated from its physical asset positions. Mirant manages the price risk associated with asset management activities through a variety of methods. Mirant’s Risk Management Policy requires that asset management activities are restricted to only those activities that are risk-reducing in nature. In addition, the Company, through its proprietary trading and fuel oil management activities, attempts to achieve incremental returns by entering into energy contracts where it has specific market expertise or physical asset positions. Proprietary trading and fuel oil management activities increase risk and expose the Company to risk of loss if prices move differently than expected. As of December 31, 2006, Mirant’s Risk Management Policy sets VaR limits with respect to the Company’s proprietary trading and fuel oil management activities of $7.5 million and $5 million, respectively.

The Company enters into a variety of derivative financial and physical instruments to manage its exposure to the prices of the fuel it acquires for generating electricity, as well as the electricity that it sells. These include contractual agreements, such as forward purchase and sale agreements, futures, swaps and option contracts. Futures are traded on national exchanges and swaps are typically traded in OTC financial markets. Option contracts are traded on both a national exchange and in OTC financial markets. These

contractual agreements have varying terms, notional amounts and durations, or tenors, which range from a few days to a number of years, depending on the instrument. As part of its proprietary trading activities, the Company is exposed to certain market risks in an effort to generate gains from changes in market prices by entering into derivative instruments, including exchange-traded and OTC contracts, as well as other contractual arrangements.

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

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

	Net Price Risk Management															Net Fair Value
	Assets							Liabilities								at December 31,
	Current				Noncurrent			Current				Noncurrent				2006
Electricity		$	619			$	104		$	(260	)		$	(12	)		$	451
Natural gas		21				1			(26		)		(2		)		(6		)
Oil		83				—			(10		)		(29		)		44
Coal		13				—			(3		)		—				10
Other, including credit reserve		(5		)		—			—				—				(5		)
Total		$	731			$	105		$	(299	)		$	(43	)		$	494

The following table represents the net price risk management assets and liabilities by tenor at December 31, 2006 (in millions):

	All Agreements
2007		$	433
2008		13
2009		40
2010		9
Thereafter		(1		)
Net (liabilities) assets		$	494

The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at December 31, 2006, was approximately 11 months. The net notional amount of the price risk management assets and liabilities at December 31, 2006, was a net short position of approximately 24 million equivalent MWh.

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

	Net Price Risk Management															Net Fair Value
	Assets							Liabilities								at December 31,
	Current				Noncurrent			Current				Noncurrent				2005
Electricity		$	449			$	51		$	(677	)		$	(6	)		$	(183	)
Natural Gas		113				19			(112		)		(20		)		—
Oil		21				11			(5		)		—				27
Coal		31				24			(2		)		(1		)		52
Other, including credit reserves		(11		)		—			—				—				(11		)
Total		$	603			$	105		$	(796	)		$	(27	)		$	(115	)

7. Property, Plant and Equipment, net

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

	At December 31,						Depreciable
	2006			2005			Lives
Production	$	2,504		$	2,441			14 to 34
Oil pipeline	26			25				24
Construction work in progress	187			74				—
Other	88			87				2 to 12
Suspended construction projects	8			174				—
Less accumulated depreciation	(626		)	(506		)
Total property, plant and equipment, net	$	2,187		$	2,295

Property, plant and equipment, net of $497 million and $513 million have been reclassified to assets held for sale in the Company’s consolidated balance sheets at December 31, 2006 and 2005, respectively. See Note 3 for additional information on assets held for sale.

Suspended construction projects decreased in 2006 due to the transfer of Contra Costa unit 8 to PG&E pursuant to a Settlement and Release of Claims Agreement and the impairment loss of $120 million related to Bowline unit 3. See California Settlement in Note 17 for additional information regarding the transfer of the CC8 Assets. See Note 4 for further discussion related to impairments of long-lived assets.

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. Mirant Americas Generation does not depreciate its suspended construction project costs or property, plant and equipment that has been reclassified to assets held for sale. 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. An asset impairment charge must be recognized 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. The amount of any impairment charge is calculated as the excess of the carrying value of the asset over its fair value. Fair value is estimated based on the discounted future cash flows from that asset or determined by other valuation techniques. In the case of assets the

Company expects to sell, the impairment charge is based on the estimated sales value less costs to sell. For additional information on impairments see Note 4 and Note 3.

8. Intangible Assets, net

Following is a summary of intangible assets at December 31, 2006 and 2005 (in millions):

			At December 31, 2006							At December 31, 2005
	Weighted Average Amortization Lives		Gross Carrying Amount			Accumulated Amortization				Gross Carrying Amount			Accumulated Amortization
Trading rights		26 years		$	27		$	(3	)		$	27		$	(2	)
Development rights		38 years		62			(9		)		62			(7		)
Emissions allowances		32 years		151			(25		)		151			(21		)
Other intangibles		30 years		12			(3		)		13			(2		)
Total other intangible assets				$	252		$	(40	)		$	253		$	(32	)

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

Development rights represent the right to expand capacity at certain acquired generating facilities. The existing infrastructure, including storage facilities, transmission interconnections, and fuel delivery systems, and contractual rights acquired by 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, as well as the Company’s units in California. Allowances granted by the EPA for other owned assets are recorded within property, plant and equipment, net on the consolidated balance sheets.

Substantially all of Mirant Americas Generation’s other remaining intangible assets are subject to amortization and are being amortized on a straight-line basis over their estimated useful lives.

Amortization expense was approximately $8 million for the years ended December 31, 2006, 2005 and 2004. 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.

9. Related Party Arrangements and Transactions

Management, Personnel and Services Agreement with Mirant Services

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

	Years Ended December 31,
	2006		2005		2004
Cost of fuel, electricity and other products—affiliate	$	9	$	10	$	10
Operations and maintenance expense—affiliate	148		162		164
Total	$	157	$	172	$	174

Services and Risk Management Agreements with Affiliates

The Company, through Mirant Energy Trading and previously Mirant Americas Energy Marketing, provides energy marketing and fuel procurement services to the following affiliates: Mirant Las Vegas, Mirant Sugar Creek, Shady Hills, Mirant West Georgia and Mirant Wichita Falls. Amounts due from each affiliate under their respective service agreements are recorded as a net accounts payable-affiliate or accounts receivable—affiliate because of each subsidiary’s legal right to offset.

Substantially all energy marketing costs are allocated to Mirant’s operating subsidiaries. During the years ended December 31, 2006, 2005 and 2004, the total energy marketing costs were $45 million, $54 million and $83 million, respectively. For the years ended December 31, 2006, 2005 and 2004, the Company recorded a reduction to operations and maintenance of approximately $6 million, $8 million and $14 million, respectively, related to the allocation of costs to affiliates of the Company.

For the period from January 1, 2006 to January 31, 2006, Mirant Americas Energy Marketing continued to provide these services to the affiliates. Beginning February 1, 2006, Mirant Energy Trading began providing these services to the affiliates.

Mirant Wichita Falls was sold by Mirant in the second quarter of 2006. Mirant has signed an agreement to sell Mirant Las Vegas, Mirant Sugar Creek, Shady Hills and Mirant West Georgia. The sales are expected to be completed in the second quarter of 2007. Subsequent to the sale of these affiliates by Mirant, the Company will no longer recognize a reduction to operations and maintenance associated with providing services to these affiliates.

The Company’s gross margin for future periods is not expected to be materially impacted by the sale of these affiliates. However, because the Company will likely discontinue providing energy marketing and fuel procurement services to these entities, the Company would expect its operating revenues-affiliate and cost of fuel, electricity, and other products—affiliate to decrease or be eliminated subsequent to the sale of these affiliates. In addition, these decreases would result in corresponding decreases in cost of fuel, electricity, and other products—nonaffiliate and operating revenues-nonaffiliate, respectively, in the consolidated and combined statements of operations in future periods.

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 $132 million, $133 million and $168 million, respectively, in costs under these arrangements, which are included in operations and maintenance—affiliate in the accompanying consolidated and combined statements of operations.

Make-Whole Reimbursement Agreement

Under the asset purchase and sale agreement for the Pepco generating assets, Mirant assumed and recorded net obligations of approximately $2.4 billion, representing the estimated fair value (at the date of acquisition) of out-of-market energy delivery and PPAs, which consisted of five PPAs and two TPAs. The estimated fair value of the contracts was derived using forward prices obtained from brokers and other external sources in the marketplace, including brokers and trading platforms/exchanges such as New York Mercantile Exchange and estimated load information. Mirant Americas Energy Marketing assumed these obligations from Mirant pursuant to a liability assignment agreement.

Mirant Americas and Mirant Americas Energy Marketing entered into a Make-Whole Agreement, whereby Mirant Americas was obligated to reimburse Mirant Americas Energy Marketing for losses arising from the TPAs, PPAs, and related hedges of these agreements. In any month that Mirant Americas Energy Marketing realized net gains related to the TPAs, PPAs, and related hedges, it was required to pay

these amounts to Mirant Americas. Amounts received were recorded as capital contributions and amounts paid were recorded as capital distributions in the accompanying combined financial statements. In 2004, the Company received payments from Mirant Americas under the Make-Whole Agreement of $7 million. Under the Plan, claims arising out of the Make-Whole Agreement were resolved pursuant to a global settlement, whereby intercompany claims did not receive distributions.

Sales to Mirant Energy Marketing Canada

Historically, Mirant Americas Energy Marketing purchased natural gas from Mirant Energy Marketing Canada, a subsidiary of Mirant. These purchases were reflected in operating revenue—affiliate on the combined statements of operations. The natural gas was sold to third parties; therefore, the revenue was reflected in operating revenue—nonaffiliate in the combined statements of operations. In 2003, Mirant sold a substantial portion of the Canadian operation and decided to exit the remaining elements of its trading business in Canada. Gas purchases from Mirant Energy Marketing Canada for the years ended December 31, 2005 and 2004, were $3 million and $17 million, respectively.

Restructuring Charges

During the years ended December 31, 2006, 2005 and 2004, the Company recorded restructuring charges of $1 million, $3 million and $5 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 the Company’s locations were paid by Mirant Services and billed to the Company and are included in the amounts disclosed above for management, personnel and services.

Notes Payable to Affiliate

During the pendency of the Chapter 11 proceedings, Mirant and certain of its subsidiaries participated in an intercompany cash management program approved by the Bankruptcy Court, pursuant to which cash balances at Mirant and the participating subsidiaries were transferred to central concentration accounts and, if necessary, lent to Mirant or any participating subsidiary to fund working capital and other needs, subject to the intercompany borrowing limits approved by the Bankruptcy Court. At December 31, 2006 and 2005, the Company had current notes payable to affiliate of $13 million and $21 million, respectively. Interest expense-affliate was $23 million and $8 million for the years ended December 31, 2005 and 2004, respectively.

Payable to Mirant Americas Pursuant to the Plan

Pursuant to the Plan, Mirant North America, the Company’s wholly-owned subsidiary, was required to pay $250 million to Mirant Americas within five days of the effective date of the Plan in return for Mirant’s contribution of the Trading Debtors. This amount is included in payable to affiliate at December 31, 2005, in the consolidated balance sheet and was paid in January 2006.

Mirant Guarantees

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

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

In July 2006, Mirant North America posted a letter of credit in the amount of $14 million on behalf of Mirant Delta related to a tolling agreement. This letter of credit expires in July 2007.

Prior to 2005, Mirant entered into pre-petition letters of credit to support the Company’s asset management activities. In September 2005, several of these letters of credit were drawn in the amount of $39 million. In January 2006, the remaining pre-petition letter of credit of $7 million was drawn in full. In addition, Mirant entered into post-petition letters of credit to support its asset management activities. In January 2006, letters of credit from the Mirant North America senior secured credit facilities replaced the eleven post-petition letters of credit outstanding at December 31, 2005. See “Financial Condition-Cash Collateral and Letters of Credit” for details on letters of credit outstanding at December 31, 2006.

Series A Preferred Shares in Mirant Americas

Pursuant to the Plan, Mirant Americas was required to make capital contributions to Mirant Mid-Atlantic for the purpose of funding future environmental capital expenditures. These capital contributions were made in the form of mandatorily redeemable Series A Preferred Shares, and are reflected as preferred stock in affiliate in the accompanying consolidated balance sheets at December 31, 2006 and 2005.

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 Mirant Mid-Atlantic 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 Mirant Mid-Atlantic. Any amounts so deferred shall be added to the amount of Series A Preferred Shares to be redeemed on the next Scheduled Redemption Date.

Mirant Mid-Atlantic 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 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.

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Series B Preferred Shares in Mirant Americas

In December 2005, Mirant Americas issued the Series B Preferred Shares for the purpose of supporting the refinancing of $850 million of Mirant Americas Generation senior notes due in 2011. The Series B Preferred Shares have a mandatory redemption date of April 1, 2011, for the liquidation preference amount of $150 million. At any time after June 30, 2010, Mirant Americas Generation has the right to put the Series B Preferred Shares to Mirant at the liquidation preference amount.

The Series B Preferred Shares are recorded at a fair value of $118 million and $111 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 expected redemption date and the liquidation preference amount using a 6.21% discount rate.

Debtor in Possession Financing for New York Subsidiaries

Mirant North America and Mirant Americas Energy Marketing, (the “Primary DIP Lenders”) entered into an agreement (the “Primary New York DIP Agreement”) to make secured debtor-in-possession financing in an amount of (i) $20 million, plus (ii) an amount equal to the amount of credit support provided on behalf of Mirant New York, Mirant Bowline, Mirant Lovett, and Hudson Valley Gas Corporation (collectively, the “New York DIP Borrowers”), to the extent such amounts are collateralized with cash or cash equivalents by the New York DIP Borrowers. The facility is available on a joint and several basis to the New York DIP Borrowers. On January 31, 2006, all the assets of Mirant Americas Energy Marketing were transferred to Mirant Energy Trading, with Mirant Energy Trading to succeed to all rights and assume all obligations of Mirant Americas Energy Marketing under the Primary New York DIP Agreement. The financing under the Primary New York DIP Agreement can be utilized through borrowings by the New York DIP Borrowers, the issuance of letters of credit for the account of any of the New York DIP Borrowers or in support of commercial transactions entered into by Mirant Energy Trading for the benefit of the New York DIP Borrowers, the posting of cash in respect of obligations incurred for the benefit of any of the New York DIP Borrowers, including the making of prepayments for fuel and other commodities for the benefit of any of the New York DIP Borrowers. Under the Primary New York DIP Agreement, the amount which represents the excess on the effective date of the Plan of (x) credit support posted for the benefit of the New York DIP Borrowers by the lenders in respect of transactions entered into on their behalf over (y) the amount of cash collateral posted by the New York DIP Borrowers to the lenders is deemed to be a loan made to the New York DIP Borrowers on such date. The New York DIP Borrowers have posted $5 million cash collateral with Mirant Energy Trading in accordance with the December 31, 2006, collateral allocation performed in good faith by Mirant Energy Trading. To the extent that the required level of credit support provided to the New York DIP Borrowers is reduced, the amount of such reduction is required to be returned to the New York DIP Borrowers. The financing under the Primary New York DIP Agreement has a stated maturity of 180 days, subject to renewal or extension, and is available until the earlier of (x) the expiration of such period or (y) with respect to each of the New York DIP Borrowers, the effective date of a confirmed Plan for such New York DIP Borrower in its Chapter 11 case. The loan has twice been extended such that the stated maturity date is now June 26, 2007. Subject to the authorization of the Bankruptcy Court, the obligations of the New York DIP Borrowers under the Primary New York DIP Agreement, pursuant to Section 364(c) of the Bankruptcy Code, (i) constitute a claim having priority over any or all administrative expenses of the kind specified in sections 503(b) or 507(b) of Bankruptcy Code, (ii) are secured by a lien on property of the estates of the New York DIP Borrowers that is not otherwise subject to a lien and (iii) are secured by a junior lien on property of the estates of the New York DIP Borrowers that is subject to a lien. The financing bears interest at a rate of LIBOR plus 2.25%. The Primary New York DIP Agreement contains certain events of default, and the ability of the New York DIP Borrowers to borrow thereunder is subject to certain conditions precedent. In addition, the Primary New York DIP Agreement contains covenants

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that, among other things, restrict the ability of the New York DIP Borrowers to engage in mergers, acquisitions and asset sales, to make investments and to incur indebtedness.

Contemporaneous with their entry into the Primary New York DIP Agreement, the New York DIP Borrowers also entered into an agreement for secured financing with Mirant (the “Secondary New York DIP Agreement”). The Secondary New York DIP Agreement permits Mirant to make secured debtor-in-possession financing in the maximum amount of $50 million to the New York DIP Borrowers, and the borrowings are available solely for cash collateral postings by any one or more of the New York DIP Borrowers.

10. Long-Term Debt

Long-term debt at December 31, 2006 and 2005, was as follows (in millions):

	At December 31,							Secured/
	2006			2005			Interest Rate	Unsecured
Long-term Debt:
Mirant Americas Generation:
Senior notes:
Due 2011	$	850		$	850		8.30%	Unsecured
Due 2021	450			450			8.50%	Unsecured
Due 2031	400			400			9.125%	Unsecured
Unamortized debt discount	(4		)	(4		)
Mirant North America:
Term loan, due 2007 to 2013	692			—			LIBOR + 1.75%	Secured
Notes, due 2013.	850			850			7.375%	Unsecured
Other:
Mirant Chalk Point capital lease, due 2007 to 2015	34			36			8.19%	—
Total Mirant Americas Generation	3,272			2,582
Less: current portion of long-term debt	(141		)	(3		)
Total long-term debt, excluding current portion	$	3,131		$	2,579

Pursuant to the Plan, Mirant Americas Generation reinstated $1.7 billion of senior notes maturing in 2011, 2021 and 2031. The reinstated senior notes are senior unsecured obligations of Mirant Americas Generation and are not recourse to any subsidiary or affiliate of Mirant Americas Generation. During 2006, approximately $11 million for the Zeeland capital lease was reclassified to liabilities held for sale and included in other current liabilities on the Company’s consolidated balance sheets at December 31, 2006 and 2005. See Note 3 for additional information on liabilities held for sale.

Senior Secured Credit Facilities

Mirant North America, a wholly-owned subsidiary of the Company, entered into senior secured credit facilities in January 2006, which are comprised of an $800 million six-year senior secured revolving credit facility and a $700 million seven-year senior secured term loan. The full amount of the senior secured revolving credit facility is available for cash draws or for the issuance of letters of credit. On January 3,

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2006, Mirant North America drew $465 million under its senior secured revolving credit facility. All amounts were repaid during the first quarter of 2006. The senior secured term loan was fully drawn at closing and amortizes in quarterly installments aggregating 0.25% of the original principal of the term loan per quarter for the first 27 quarters, with the remainder payable on the final maturity date in January 2013. At the closing, $200 million drawn under the senior secured term loan was deposited into a cash collateral account to support the issuance of up to $200 million of letters of credit. As of December 31, 2006, there were approximately $199 million of letters of credit outstanding under the term loan and $6 million outstanding under the revolver. The senior secured credit facilities are obligations of Mirant North America and the respective guarantors and are not recourse to any other Mirant Americas Generation entities.

Mirant North America is required to prepay a portion of the outstanding principal balance of the senior secured term loan once a year, in addition to the regularly scheduled principal payments, based on an EBITDA calculation to determine excess free cash flows, as defined in the loan agreement. At December 31, 2006, the current estimate of the mandatory principal prepayment of the term loan in March 2007 is approximately $131 million. This amount has been reclassified from long-term debt to current portion of long-term debt at December 31, 2006.

The sale of the Zeeland and Bosque natural gas-fired plants is subject to the terms of the Mirant North America senior secured credit facilities, including the mandatory prepayment and/or reinvestment provisions and the requirement to secure credit rating affirmations. Mirant North America has received the required credit rating affirmations.

Senior Notes

In December 2005, Mirant North America issued the Old Notes in an aggregate principal amount of $850 million that bear interest at 7.375% and mature on December 31, 2013. The senior notes were issued in a private placement and were not registered with the SEC. Interest on the notes is payable on each June 30 and December 31, commencing June 30, 2006. The proceeds of the notes offering initially were placed in escrow pending the emergence of Mirant North America from bankruptcy. The proceeds were released from escrow in connection with Mirant North America’s emergence from bankruptcy and the closing of the senior secured credit facilities. The senior notes are obligations of Mirant North America and the respective guarantors and are not recourse to any other Mirant Americas Generation entities.

In connection with the issuance of the Old Notes, Mirant North America entered into a registration rights agreement under which it agreed to complete an exchange offer for the Old Notes. On June 29, 2006, Mirant North America completed its registration under the Securities Act of $850 million of the New Notes and initiated the Exchange Offer. The Exchange Offer was completed on August 4, 2006, with $849.965 million of the outstanding Old Notes being tendered for the New Notes. The terms of the New Notes are identical in all material respects to the terms of the Old Notes, except that the New Notes are registered under the Securities Act and generally are not subject to transfer restrictions or registration rights.

The notes are redeemable at the option of Mirant North America, in whole or in part, at any time prior to December 31, 2009, at a price equal to 100% of the principal amount, plus accrued and unpaid interest, plus a make-whole premium. At any time on or after December 31, 2009, Mirant North America may redeem the notes at specified redemption prices, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to December 31, 2008, Mirant North America may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings at a redemption price of 107.375% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. Under the terms of the notes, the occurrence of a change of control will be a triggering event requiring Mirant North America to offer to purchase all or a portion of

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the notes at a price equal to 101% of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase. In addition, certain asset dispositions or casualty events will be triggering events which may require Mirant North America to use the proceeds from those asset dispositions or casualty events to make an offer to purchase the notes at 100% of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase if such proceeds are not otherwise used, or committed to be used, within certain time periods, to repay senior secured indebtedness, to repay indebtedness under the senior secured credit facilities (with a corresponding reduction in commitments) or to invest in capital assets related to its business.

The sale of the Zeeland and Bosque natural gas-fired plants is subject to the terms of the Mirant North America senior notes, including the provisions with respect to a mandatory offer to purchase and/or reinvest with the sale proceeds.

At December 31, 2006, the annual scheduled maturities of debt during the next five years and thereafter were as follows (in millions):

2007	$	141
2008	10
2009	10
2010	10
2011	861
Thereafter	2,240
Total	$	3,272

Other than for 2007, the annual scheduled maturities above do not include estimates of Mirant North America’s required payments of its senior secured term loan based on its EBITDA.

Capital Leases

Long-term debt includes a capital lease by Mirant Chalk Point. At December 31, 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.

Sources of Funds and Capital Structure

The principal sources of liquidity for the Company’s future operations and capital expenditures are expected to be: (i) existing cash on hand and cash flows from the operations of the Company’s subsidiaries; (ii) borrowings under Mirant North America’s $800 million six-year senior secured revolving credit facility; (iii) $200 million of letters of credit capacity under Mirant North America’s $700 million term loan; and (iv) proceeds from the preferred shares issued by Mirant Americas to Mirant Mid-Atlantic and the Company to fund capital expenditures and support the refinancing of the Company’s senior notes due in 2011.

The Company and its subsidiary, including Mirant North America are holding companies and, as a result, they are dependent upon dividends, distributions and other payments from their respective subsidiaries to generate the funds necessary to meet their obligations. The ability of certain of the

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Company’s subsidiaries to pay dividends and distributions is restricted under the terms of their debt or other agreements. The Company has no operations and no subsidiaries with operations other than Mirant North America and its subsidiaries, including Mirant Mid-Atlantic.

In particular, a substantial portion of the cash from the Company’s operations is generated by Mirant Mid-Atlantic. The Mirant Mid-Atlantic leveraged leases contain a number of covenants, including limitations on dividends, distributions and other restricted payments. Under its leveraged leases, Mirant Mid-Atlantic is not permitted to make any dividends, distributions and other restricted payments unless (1) it satisfies the fixed charge coverage ratio on a historical basis for the last period of four fiscal quarters, (2) it is projected to satisfy the fixed charge coverage ratio for the next two periods of four fiscal quarters, and (3) no significant lease default or event of default has occurred and is continuing. In the event of a default under the leveraged leases or if the restricted payments test is not satisfied, the cash of Mirant Mid-Atlantic would not be able to be distributed. Based on the Company’s calculation of the fixed charge coverage ratios under the leveraged leases as of December 31, 2006, Mirant Mid-Atlantic meets the required 1.7 to 1.0 ratio for restricted payments, both on a historical and projected basis.

The Plan provided for the organization of Mirant North America as an intermediate holding company that is a subsidiary of Mirant Americas Generation and the parent of its indirect subsidiaries, including Mirant Mid-Atlantic. Pursuant to the confirmed Plan, Mirant North America incurred certain indebtedness and entered into a revolving credit facility for working capital and other purposes secured by the assets of Mirant North America and its subsidiaries (other than Mirant Mid-Atlantic and its subsidiaries). The revolving credit facility includes certain covenants typical in such credit facilities, including restrictions on dividends, distributions and other restricted payments. Further, the revolving credit facility includes financial covenants that will exclude from the calculation of compliance with such covenants the financial results of any subsidiary that is unable to make distributions or dividends at the time of such calculation. Thus, the ability of Mirant Mid-Atlantic to make distributions to Mirant North America under the leveraged lease transaction could have a material impact on the calculation of the financial covenants under the revolving credit facility and other debt of Mirant North America and on its ability to make distributions to the Company.

11. Other Comprehensive (Loss) Income

Other comprehensive (loss) income includes unrealized gains and losses on certain derivatives that qualified as cash flow hedges and unrealized gains on available-for-sale securities. Changes in accumulated other comprehensive (loss) income, net of tax are as follows (in millions):

Balance, December 31, 2004	$	—
Other comprehensive income for the period:
Unrealized gain on available-for-sale securities	27
Balance, December 31, 2005	27
Other comprehensive income for the period:
Unrealized gain on available-for-sale securities reclassification to earnings	(27		)
Balance, December 31, 2006	$	—

The $27 million in accumulated other comprehensive income at December 31, 2005, is associated with unrealized gains on available for sale securities. In 2006, the unrealized gains were reclassified to earnings when the securities were sold.

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12. 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.

At December 31, 2006 and 2005, amounts related to allowed claims, estimated unresolved claims and professional fees associated with the bankruptcy that are to be settled in cash were $5 million and $1,831 million, respectively, and these amounts were recorded in claims payable and estimated claims accrual on the accompanying consolidated balance sheets. These amounts do not include unresolved claims that will be settled in Mirant common stock. During the year ended December 31, 2006, the Company paid approximately $1.755 billion in cash related to bankruptcy claims. Of this amount approximately $990 million is reflected in cash flows from financing activities from continuing operations and represents the principal amount of debt claims. The remaining $765 million is reflected in cash flows from operating activities and represents other bankruptcy claims and interest.

Financial Statements of Subsidiaries in Bankruptcy

Mirant Americas Generation’s New York subsidiaries remain in bankruptcy and include the following entities: Mirant Lovett, Mirant Bowline, Mirant NY-Gen, Mirant New York and Hudson Valley Gas Corporation. Consolidated financial statements of Mirant America Generation’s New York subsidiaries are set forth below:

New York Subsidiaries

Condensed Consolidated Statements of Operations Data
(in millions)

	Years Ended December 31,
	2006			2005			2004
Operating revenues	$	336		$	433		$	244
Cost of fuel, electricity and other products	162			361			139
Operating expenses	193			178			214
Operating loss	(19		)	(106		)	(109		)
Other expense, net	16			2			1
Reorganization items, net(1)	(163		)	(2		)	15
Provision (benefit) for income taxes	2			1			(1		)
Cumulative effect of change in accounting principles	—			2			—
Net income (loss)	$	126		$	(109	)	$	(124	)

(1) In 2006, reorganization items, net is primarily related to the pre-petition gain on the New York Property Tax Settlement.

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New York Subsidiaries

Condensed Consolidated Balance Sheets Data
(in millions)

	At December 31,
	2006		2005
Assets—affiliate	$	106	$	149
Assets—nonaffiliate	224		35
Property, plant and equipment, net	366		502
Total assets	$	696	$	686
Liabilities not subject to compromise
Liabilities—affiliate	$	28	$	36
Liabilities—nonaffiliate	66		177
Liabilities subject to compromise—affiliate	62		62
Liabilities subject to compromise—nonaffiliate	18		18
Member’s equity	522		393
Total liabilities and member’s equity	$	696	$	686

New York Subsidiaries

Condensed Consolidated Statements of Cash Flows Data
(in millions)

	Years Ended December 31,
	2006			2005			2004
Net cash provided by (used in):
Operating activities		$	5	$	10		$	24
Investing activities		84		(16		)	(25		)
Financing activities		9		7			1
Net increase in cash and cash equivalents		98		1			—
Cash and cash equivalents, beginning of period		1		—			—
Cash and cash equivalents, end of period		$	99	$	1		$	—

Liabilities Subject to Compromise

The Company’s liabilities subject to compromise, which relate to its New York subsidiaries that remain in bankruptcy, are $34 million at December 31, 2006 and 2005.

The amounts subject to compromise at December 31, 2006 and 2005, consisted of the following items (in millions):

	At December 31, 2006			At December 31, 2005
Items, absent the bankruptcy filings, that would have been considered current:
Accounts payable and accrued liabilities—affiliate		$	16		$	16
Accounts payable and accrued liabilities—nonaffiliate		18			18
Total		$	34		$	34

Reorganization Items, net

Reorganization items, net represents expense, income and gain or loss amounts that were recorded in the financial statements as a result of the bankruptcy proceedings. In 2006, reorganization items, net relate

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to refunds received from various New York tax jurisdictions for the settlement of the property tax dispute related to the New York subsidiaries.

Reorganization items, net for the years ended December 31, 2006, 2005 and 2004, are comprised of the following (in millions):

	Years Ended December 31,
	2006			2005			2004
Gain on the implementation of the Plan	$	—		$	(30	)	$	—
Gain on New York property tax settlement	(163		)	—			—
Estimated claims and losses on rejected and amended contracts(1)	—			54			101
Professional fees and administrative expense	2			82			47
Interest income, net	(2		)	(21		)	(10		)
Total	$	(163	)	$	85		$	138

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

13. Income Taxes

Details of the income tax provision (benefit) are as follows (in millions):

	For the Years Ended December 31,
	2006			2005			2004
Current:
Federal		$	2	$	7		$	(10	)
State		3		9			(6		)
Deferred:
Federal		—		(12		)	2
State		—		1			(1		)
Provision (benefit) for income taxes		$	5	$	5		$	(15	)

A reconciliation of the Company’s expected federal statutory income tax provision (benefit) to the effective income tax provision (benefit) for continuing operations adjusted for reorganization items is as follows (in millions):

	2006			2005			2004
U.S. federal statutory income tax (benefit) provision	$	418		$	(264	)	$	38
State and local income taxes, net of federal income taxes	5			1			(1		)
LLC income not subject to federal taxation	(370		)	314			(50		)
Change in deferred tax asset valuation allowance	(50		)	(534		)	(4		)
Impact of the Plan	—			466			—
Other, net	2			22			2
Tax (benefit) provision	$	5		$	5		$	(15	)

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The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities are as follows at December 31, 2006 and 2005 (in millions):

	2006			2005
Deferred tax assets:
Property and intangible assets	$	108		$	99
Net operating loss carryforwards	66			79
Other, net	11			45
Deferred tax assets	185			223
Valuation allowance	(173		)	(223		)
Net deferred tax assets	12			—
Deferred tax liabilities:
Price risk management liabilities	(11		)	—
Other, net	(1		)	—
Total	(12		)	—
Net deferred tax liabilities	$	—		$	—

Several changes to the Company’s tax posture occurred as a result of the Plan, including the conversion of certain of the Company’s regarded corporate entities to limited liability companies coupled with the liquidation and/or merger of these regarded corporate entities into other disregarded corporate entities for income tax purposes, and certain partnerships owned by the regarded corporate entities were also liquidated and now form part of these disregarded entities for income tax purposes. The result of the plan effects eliminates the Company’s recording of tax expense and benefit beginning January 1, 2006, with respect to the liquidated regarded corporate entities. Furthermore, with respect to those liquidated regarded corporate entities, all previously existing deferred tax assets and liabilities were eliminated as of December 31, 2005.

Certain of the Company’s other subsidiaries continue to exist as regarded corporate entities for income tax purposes including Mirant New York, Hudson Valley Gas, Mirant Kendall, and Mirant Special Procurement Inc. For those regarded corporate entities, the Company allocates current and deferred income taxes to each regarded corporate entity as if such entity were a single taxpayer utilizing the asset and liability method to account for income taxes. To the extent the Company provides tax expense or benefit, any related tax payable or receivable to Mirant is reclassified to equity in the same period. As such, $2 million was reclassified as a capital contribution to member’s interest for the year ended December 31, 2006.

SFAS No. 109 requires that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including the Company’s past and anticipated future performance, the reversal of deferred tax liabilities, the implementation of tax planning strategies and management’s expectations of future reimbursements of NOL carryforwards from Mirant.

Objective positive evidence is necessary to support a conclusion that a valuation allowance is not needed for all or a portion of deferred tax assets when significant negative evidence exists. Cumulative losses in recent years are the most compelling form of negative evidence considered by management in this determination. Additionally, management considered the fact that Mirant has not reimbursed the Company for current period NOLs from the Petition Date to December 31, 2005, and the uncertainty regarding future reimbursements from Mirant. In 2006, 2005 and 2004, the Company recognized changes in its valuation allowance of $(50) million, $(534) million and $(4) million, respectively, related to its net deferred tax assets.

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At December 31, 2006, the Company had $149 million of NOL carryforwards for federal income tax purposes expiring from 2023 to 2026 and $289 million of NOL carryforwards for state income tax purposes expiring on various dates. These NOL carryforwards are available to offset future federal and state income taxes.

The Company, through its parent Mirant, negotiated a settlement agreement with the Internal Revenue Service (“IRS”) for certain tax liabilities arising from their audit of the Company’s federal income tax returns for tax years the Company was a subsidiary of the Southern Company. This agreement resulted in an assessment of $14 million including interest. The Company has provided adequate tax provisions in prior years for the recognition of this liability. As this liability represented an intercompany obligation to Mirant, the liability was resolved pursuant to the Plan with no distribution for such liability. Mirant has indemnified the Company with respect to this obligation.

Additionally, the Company has contingent liabilities related to tax uncertainties arising in the ordinary course of business. The Company periodically assesses its contingent liabilities in connection with these uncertainties based on the latest information available. For those uncertainties where it is probable that a loss has occurred and the loss or range of loss can be reasonably estimated, a liability is recognized in the financial statements. The recognition of contingent losses for tax uncertainties requires management to make significant assumptions about the expected outcomes of certain tax contingencies. On January 1, 2007, the Company will change its method of determining tax contingencies upon adoption of FIN 48. 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 Company anticipates that the adoption of FIN 48 will result in a decrease in accrued liabilities of approximately $50 million. The decreases in accrued liabilities will result in an increase in member’s interest of the same amount.

Pro Forma Income Tax Disclosures

The Company is not subject to income taxes except for those subsidiaries of the Company that are separate taxpayers. Mirant Americas and Mirant are otherwise 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 related to its operations. Pro forma income tax provision (benefit) attributable to income before tax would consist of the following (in millions):

	For the Years Ended December 31,
	2006			2005			2004
Current provision (benefit):
State		$	3		$	9		$	(8	)
Total income tax provision (benefit)		$	3		$	9		$	(8	)

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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 tax provision (benefit) (in millions):

	For the Years Ended December 31,
	2006			2005			2004
U.S. federal statutory income tax (benefit) provision	$	418		$	(264	)	$	38
State and local income taxes, net of federal income taxes	51			—			(1		)
Impact of discontinued operations	3			(1		)	(6		)
Change in deferred tax asset valuation allowance	(562		)	(10		)	(54		)
Professional fees during bankruptcy	28			—			—
Anticipated effect of 382(l)(5)	61			—			—
Impact of the Plan	—			223			—
Other, net	4			61			15
Tax provision (benefit)	$	3		$	9		$	(8	)

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the consolidated balance sheet 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 assets:
Revenue subject to refund	$	1		$	182
Net operating loss carryforwards	784			809
Property and intangible assets	101			189
Price risk management liabilities—affiliate	—			89
Other, net	65			108
Deferred tax assets	951			1,377
Valuation allowance	(788		)	(1,350		)
Net deferred tax assets	163			27
Deferred tax liabilities:
Price risk management liabilities—affiliate	(144		)	(10		)
Other, net	(19		)	(17		)
Total	(163		)	(27		)
Net deferred tax liabilities	$	—		$	—

The ultimate utilization of the Company’s remaining pro forma NOLs will depend on several factors, including its future financial performance and certain tax elections. Specifically, the Company’s utilization of pro forma NOLs will be impacted by whether Mirant elects NOL treatment under Internal Revenue Code Section (“§”) 382(l) (5) or § 382(l) (6). Under § 382(l)(5), the Company would have use of its pro forma NOLs as long as there is not a change of Mirant ownership (broadly defined as 50 percent change of five percent shareholders) within two years of emergence. The § 382(l)(5) election results in a reduction to the Company’s pro forma federal NOLs of approximately $175 million due to interest accrued on debt settled with Mirant stock for the three years prior to emergence. Under § 382(l) (6), the Company would be subject to an overall annual limitation on use of pro forma NOLs. Mirant will make the § 382(l) (5) or § 382(l) (6) election in its 2006 annual tax return filed in 2007. Given the likelihood that Mirant will elect § 382(l) (5), the Company has adjusted various pro forma deferred tax items including the pro forma NOL.

The Company anticipates that the adoption of FIN 48 would result in a pro forma increase in member’s interest of $50 million to $85 million.

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

14. 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		$	33		$	10
Revisions to cash flows for liabilities recognized upon adoption of SFAS No. 143		—			(5		)
Liabilities recognized upon adoption of FIN 47		—			27
Liabilities recorded in the period		5			—
Accretion expense		3			1
Ending balance, December 31		$	41		$	33

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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		$	35			$	33
Revisions to cash flows for liabilities recognized upon adoption of SFAS No. 143		(5		)		—
Accretion expense		3				2
Ending balance, December 31		$	33			$	35

15. Commitments and Contingencies

Mirant Americas Generation has made firm commitments to buy materials and services in connection with its ongoing operations and has made financial guarantees relative to some of its investments.

Cash Collateral and Letters of Credit

In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, the Company often is required to provide trade credit support to its counterparties or make deposits with brokers. In addition, the Company often is required to provide cash collateral or letters of credit for access to the transmission grid, to participate in power pools, to fund debt service reserves and for other operating activities. Trade credit support includes cash collateral, letters of credit and financial guarantees. In the event of default by the Company, the counterparty can draw on a letter of credit or apply cash collateral held to satisfy the existing amounts outstanding under an open contract. The Company’s outstanding issued letters of credit totaled $204 million as of December 31, 2006.

Following is a summary of cash collateral posted with counterparties and brokers and letters of credit issued as of December 31, 2006 and 2005 (in millions):

	At December 31,			At December 31,
Continuing Operations:	2006			2005
Cash collateral posted—energy trading and marketing		$	27		$	619
Cash collateral posted—debt service and rent reserves		—			56
Cash collateral posted—other operating activities		11			10
Letters of credit—energy trading and marketing		100			51
Letters of credit—debt service and rent reserves		84			—
Letters of credit—other operating activities		15			—
		237			736
Discontinued operations:
Assets held for sale—letters of credit		5			5
Total		$	242		$	741

On July 13, 2006, Moody’s Investors Service reduced Mirant’s corporate credit rating to “B2” and the debt ratings of the Company’s subsidiaries debt ratings were also lowered. Standard and Poor’s also announced that they had placed Mirant’s corporate credit rating and the debt ratings of the Company and its subsidiaries on credit watch.

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Commitments

In addition to debt and other obligations in the consolidated balance sheets, Mirant Americas Generation has the following annual commitments under various agreements at December 31, 2006, related to its continuing operations (in millions):

Fiscal Year Ending	2007		2008		2009		2010		2011		Thereafter			Total
Mirant Mid-Atlantic operating leases	$	112	$	121	$	142	$	140	$	134		$	1,597	$	2,246
Other operating leases	4		4		4		4		3			15		34
Fuel commitments	263		89		66		—		—			—		418
Long-term service agreements	3		1		2		2		2			23		33
Other purchase commitments	172		—		—		—		—			—		172
Total payments	$	554	$	215	$	214	$	146	$	139		$	1,635	$	2,903

Operating Leases

Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively. Mirant Mid-Atlantic has an option to extend the leases. Any extensions of the respective leases would be limited to 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. The Company is accounting for these leases as operating leases and recognizes rent expense on a straight-line basis. Rent 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 expense 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

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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 statements 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, $4 million and $5 million during 2006, 2005 and 2004, respectively.

Fuel Commitments

As of December 31, 2006, the total estimated commitments associated with long-term coal and other fuel commitments is $418 million. The fair value of certain contracts is included in price risk management assets or price risk management liabilities on the Company’s consolidated balance sheets.

Long-Term Service Agreements

As of December 31, 2006, the total estimated commitments under LTSAs associated with turbines installed or in storage were approximately $165 million. Of this total, $33 million relates to the Company’s continuing operations and $132 million relates to the Company’s Zeeland and Bosque natural gas-fired plants that are included in liabilities held for sale. These commitments are payable over the terms of the respective agreements, which range from ten to twenty years. These agreements have terms that allow for cancellation of the contracts by the Company upon the occurrence of several major events during the term of the contracts. Estimates for future commitments for the LTSAs are based on the stated payment terms in the contracts at the time of execution. These payments are subject to an annual inflationary adjustment.

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.

16. Segment Reporting

Previously, the Company managed its business as one operating segment. In 2006, Mirant commenced auction processes to sell certain intermediate and peaking natural gas-fired plants including the Company’s Zeeland and Bosque plants. The planned sales have resulted in the reclassification of the revenues and expenses of these assets to discontinued operations and the reclassification of the related assets and liabilities to assets and liabilities held for sale for all periods presented. In the fourth quarter of 2006, the Company re-evaluated the business segments of its continuing operations. As a result, the Company now has four operating segments: Mid-Atlantic, Northeast, California and Other Operations. Other Operations includes proprietary trading and fuel oil management. For periods prior to 2006, Other Operations also includes gains and losses related to the Company’s Back-to-Back Agreement and TPAs with Pepco.

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Business Segments

													Other
	Mid-Atlantic				Northeast				California				Operations				Eliminations				Total
	(in millions)
2006:
Operating revenues—affiliate		$	1,711			$	811			$	47			$	389			$	(2,888	)	$	70
Operating revenues—nonaffiliate		190				16				124				2,873				—			3,203
Total operating revenues		1,901				827				171				3,262				(2,888		)	3,273
Cost of fuel, electricity and other products—affiliate		465				317				56				2,221				(2,926		)	133
Cost of fuel, electricity and other products—nonaffiliate		118				152				—				910				—			1,180
Total cost of fuel, electricity and other products		583				469				56				3,131				(2,926		)	1,313
Gross margin		1,318				358				115				131				38			1,960
Operating Expenses:
Operations and maintenance—affiliate		135				78				39				22				—			274
Operations and maintenance—nonaffiliate		198				55				24				—				—			277
Depreciation and amortization		74				25				13				10				—			122
Impairment losses		—				118				—				1				—			119
Loss (gain) on sales of assets—affiliate		(2		)		(44		)		—				2				44			—
Loss (gain) on sales of assets—nonaffiliate		(5		)		(2		)		—				(2		)		—			(9		)
Total operating expenses		400				230				76				33				44			783
Operating Income		918				128				39				98				(6		)	1,177
Total other expense (income), net		(4		)		9				(34		)		174				—			145
Income (loss) from continuing operations before reorganization items and income taxes		922				119				73				(76		)		(6		)	1,032
Reorganization items, net		—				(163		)		—				—				—			(163		)
Provision for income taxes		—				2				—				3				—			5
Income from continuing operations		$	922			$	280			$	73			$	(79	)		$	(6	)	$	1,190
Total assets of continuing operations		$	3,404			$	1,198			$	443			$	2,021			$	(1,748	)	$	5,318
Gross property additions		$	112			$	12			$	1			$	2			$	—		$	127

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	Mid-Atlantic			Northeast				California				Other Operations				Eliminations				Total
	(in millions)
2005:
Operating revenues—affiliate		$	1,197		$	986			$	60			$	1,891			$	(3,975	)	$	159
Operating revenues—nonaffiliate		—			53				106				2,649				—			2,808
Total operating revenues		1,197			1,039				166				4,540				(3,975		)	2,967
Cost of fuel, electricity and other products—affiliate		610			778				55				2,735				(3,991		)	187
Cost of fuel, electricity and other products—nonaffiliate		132			56				(2		)		1,759				—			1,945
Total cost of fuel, electricity and other products		742			834				53				4,494				(3,991		)	2,132
Gross margin		455			205				113				46				16			835
Operating Expenses:
Operations and maintenance—affiliate		148			77				37				25				—			287
Operations and maintenance—nonaffiliate		193			148				32				2				—			375
Depreciation and amortization		64			33				5				13				—			115
Loss (gain) on sales of assets—nonaffiliate		—			(10		)		—				1				8			(1		)
Total operating expenses		405			248				74				41				8			776
Operating Income (loss)		50			(43		)		39				5				8			59
Total other expense (income), net		18			6				1				730				(26		)	729
Income (loss) from continuing operations before reorganization items and income taxes		32			(49		)		38				(725		)		34			(670		)
Reorganization items, net		22			7				(169		)		199				26			85
Provision (benefit) for income taxes		—			6				9				(10		)		—			5
Income (loss) from continuing operations		$	10		$	(62	)		$	198			$	(914	)		$	8		$	(760	)
Total assets of continuing operations		$	3,334		$	1,020			$	379			$	3,724			$	(1,980	)	$	6,477
Gross property additions		$	67		$	15			$	14			$	—			$	—		$	96

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	Mid-Atlantic				Northeast				California				Other Operations			Eliminations				Total
	(in millions)
2004:
Operating revenues—affiliate		$	1,021			$	708			$	232			$	1,822		$	(3,341	)	$	442
Operating revenues—nonaffiliate		1				96				144				2,782			—			3,023
Total operating revenues		1,022				804				376				4,604			(3,341		)	3,465
Cost of fuel, electricity and other products—affiliate		372				507				229				2,371			(3,348		)	131
Cost of fuel, electricity and other products—nonaffiliate		149				69				1				2,034			—			2,253
Total cost of fuel, electricity and other products		521				576				230				4,405			(3,348		)	2,384
Gross margin		501				228				146				199			7			1,081
Operating Expenses:
Operations and maintenance—affiliate		152				82				50				35			(1		)	318
Operations and maintenance—nonaffiliate		184				118				30				9			—			341
Depreciation and amortization		62				31				4				15			—			112
Impairment losses		—				—				—				2			—			2
Loss on sales of assets—nonaffiliate		—				43				—				1			18			62
Total operating expenses		398				274				84				62			17			835
Operating Income (loss)		103				(46		)		62				137			(10		)	246
Total other expense (income), net		3				(3		)		1				6			(7		)	—
Income (loss) from continuing operations before reorganization items and income taxes		100				(43		)		61				131			(3		)	246
Reorganization items, net		(6		)		20				18				98			8			138
Provision (benefit) for income taxes		—				(5		)		(15		)		5			—			(15		)
Income (loss) from continuing operations		$	106			$	(58	)		$	58			$	28		$	(11	)	$	123
Total assets of continuing operations		$	3,148			$	1,469			$	548			$	2,481		$	(2,044	)	$	5,602
Gross property additions		$	41			$	26			$	19			$	—		$	—		$	86

Geographic Areas

	Property, Plant and Equipment and Other Intangible Assets
	Mid-Atlantic			Northeast			California			Other			Eliminations				Total
	(in millions)
At December 31, 2006		$	2,450		$	571		$	163		$	14		$	(799	)	$	2,399
At December 31, 2005		$	2,368		$	707		$	222		$	18		$	(799	)	$	2,516

17. 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.

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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 subsidiaries of the Company, 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 the Company would have to pay additional cash amounts as necessary under the terms of the Plan to satisfy such pre-petition claims.

The Company’s subsidiaries related to its New York business operations, Mirant New York, Mirant Bowline, Mirant Lovett, Hudson Valley Gas Corporation and Mirant NY-Gen remain in bankruptcy. The Company’s Lovett and Bowline generation facilities in New York were subject to disputes with local tax authorities regarding property tax assessments that were not resolved until December 2006, as described below in New York Tax Proceedings. Resolution of those tax disputes should allow Mirant New York, Mirant Bowline, and Hudson Valley Gas to emerge from bankruptcy in 2007. On January 26, 2007, Mirant New York, Mirant Bowline, and Hudson Valley Gas (collectively, the “Emerging New York Entities”) filed a Supplemental Joint Chapter 11 Plan of Reorganization of the Emerging New York Entities (the “Supplemental Plan”) with the Bankruptcy Court. The Supplemental Plan has two main components. First, the Supplemental Plan incorporates a settlement with the various New York tax jurisdictions that resolved the tax disputes related to the Lovett and Bowline facilities. Second, the Supplemental Plan provides unsecured creditors of the Emerging New York Entities with the same treatment afforded holders of unsecured claims against the Company and its subsidiaries under the Plan. Such unsecured creditors of the Emerging New York Entities will receive their pro rata share of the pool of assets created under the Plan for the benefit of the unsecured creditors of the Company and its subsidiaries. On January 26, 2007, the Emerging New York Entities also filed a motion with the Bankruptcy Court to establish procedures to facilitate the consideration and confirmation of the Supplemental Plan. That motion requests, among other things, that the Bankruptcy Court find that the Supplemental Plan does not alter in any respect from the Plan the treatment of the holders of unsecured claims against the Emerging New York Entities, and that all votes previously cast by such holders in respect of the Plan (which votes accepted the Plan for the Emerging New York Entities by the requisite number and amount required by the Bankruptcy Code) should be deemed votes cast in respect of the Supplemental Plan. The hearing before the Bankruptcy Court to consider the confirmation of the Supplemental Plan is scheduled for March 21, 2007.

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On January 31, 2007, Mirant New York entered into the Alliance Sale pursuant to which it will sell Mirant NY-Gen, which owns the Hillburn and Shoemaker gas turbine facilities and the Swinging Bridge, Rio and Mongaup hydroelectric generating facilities, to Alliance Energy, LLC. The sales price of approximately $5 million is subject to adjustments for working capital and certain dam remediation efforts that are ongoing at the Swinging Bridge facility. The Bankruptcy Court approved the Alliance Sale on March 8, 2007. The transaction is expected to close in the second quarter of 2007 in conjunction with a plan of reorganization becoming effective for Mirant NY-Gen. On February 15, 2007, Mirant NY-Gen filed the proposed Mirant NY-Gen Plan. It subsequently filed a related disclosure statement. Upon approval of the disclosure statement by the Bankruptcy Court, Mirant NY-Gen will solicit votes of its creditors and proceed to a confirmation hearing seeking approval of the Mirant NY-Gen Plan. The Bankruptcy Court will consider approval of the disclosure statement on March 21, 2007. No date has been set for the confirmation of the Mirant NY-Gen Plan. The Mirant NY-Gen Plan is proposed in connection with the Alliance Sale. Under the terms of the Mirant NY-Gen Plan, on the date that the Mirant NY-Gen Plan is confirmed, the Bankruptcy Court will estimate the amount of cash required for Mirant NY-Gen to pay in full all the claims outstanding against Mirant NY-Gen other than claims arising from the debtor-in-possession loan provided by Mirant Americas to Mirant NY-Gen and intercompany claims. Proceeds from the Alliance Sale in an amount equal to the Bankruptcy Court’s estimate of the claims will be reserved to pay such claims. The balance will be paid to Mirant Americas in partial satisfaction of the $16.5 million debtor-in-possession loan and all intercompany claims held by Mirant NY-Gen will be assigned to Mirant Americas. Upon closing of the Alliance Sale, Mirant Americas will release all of its claims and liens against Mirant NY-Gen.

Until the Company’s subsidiaries related to its New York business operations emerge from bankruptcy, the Company will not have access to the cash from operations generated from these subsidiaries. In 2006, Mirant’s New York operations generated $5 million of cash from operating activities.

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

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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 and various of the Company’s subsidiaries causes the Company’s 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’s 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’s 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 subsidiaries of the Company), 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.

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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 subsidiaries of the Company, 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.

California and Western Power Markets

FERC Refund Proceedings. On July 25, 2001, the FERC issued an order requiring proceedings (the “FERC Refund Proceedings”) to determine the amount of any refunds and amounts owed for sales made by market participants, including Mirant Americas Energy Marketing, to the CAISO or the Cal PX from October 2, 2000, through June 20, 2001 (the “Refund Period”). Various parties have appealed these FERC orders to the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) seeking review of a number of issues, including changing the Refund Period to include periods prior to October 2, 2000, and expanding the sales of electricity subject to potential refund to include bilateral sales made to the DWR and other parties. On August 2, 2006, the Ninth Circuit issued an opinion addressing some of the issues raised by these appeals. The Ninth Circuit remanded to the FERC for further proceedings the FERC’s denial of relief for sales of electricity made in the CAISO and Cal PX markets prior to October 2, 2000, at rates found to be unjust and directed the FERC to address the parties’ request for a market-wide remedy

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for tariff violations that may have occurred prior to October 2, 2000. In addition, the Ninth Circuit found that the FERC had not adequately supported its decision to exclude from the FERC Refund Proceedings (i) sales made in the CAISO and Cal PX that had a term of greater than 24 hours, and (ii) energy exchange transactions, and remanded these issues to the FERC for further proceedings. The Ninth Circuit affirmed the FERC’s decision to exclude bilateral sales to the DWR from the FERC Refund Proceeding. If the FERC grants the parties’ requested relief with respect to the issues remanded by the Ninth Circuit, any expansion of the Refund Period to include periods prior to October 2, 2000, or of the types of sales of electricity potentially subject to refund could increase the refund exposure of Mirant Americas Energy Marketing in this proceeding.

In the July 25, 2001, order, the FERC also ordered that a preliminary evidentiary proceeding be held to develop a factual record on whether there had been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest from December 25, 2000, through June 20, 2001. In that proceeding, the California Attorney General, the CPUC and the EOB filed to recover certain refunds from parties, including Mirant Americas Energy Marketing, for bilateral sales of electricity to the DWR at the California/Oregon border, claiming that such sales took place in the Pacific Northwest. In an order issued June 25, 2003, the FERC ruled that no refunds were owed and terminated the proceeding. On November 10, 2003, the FERC denied requests for rehearing filed by various parties. Various parties appealed the FERC’s decision to the Ninth Circuit.

On September 9, 2004, the Ninth Circuit reversed the FERC’s dismissal of a complaint filed in 2002 by the California Attorney General that sought refunds for transactions conducted in markets administered by the CAISO and the Cal PX outside the Refund Period set by the FERC and for transactions between the DWR and various owners of generation and power marketers, including Mirant Americas Energy Marketing and subsidiaries of the Company. The Ninth Circuit remanded the proceeding to the FERC for it to determine what remedies, including potential refunds, are appropriate where entities, including Mirant Americas Energy Marketing, purportedly did not comply with certain filing requirements for transactions conducted under market-based rate tariffs. On July 31, 2006, the Ninth Circuit denied a petition for rehearing filed by Mirant Americas Energy Marketing and other parties. Various parties to the proceeding have filed a petition for writ of certiorari with the United States Supreme Court requesting it to review the Ninth Circuit’s September 9, 2004, decision.

On January 14, 2005, Mirant and certain of its subsidiaries, including the Company, entered into a Settlement and Release of Claims Agreement (the “California Settlement”) with PG&E, SCE, San Diego Gas and Electric Company, the CPUC, the DWR, the EOB and the Attorney General of the State of California (collectively, the “California Parties”) and with the Office of Market Oversight and Investigations of the FERC. The California Settlement settled a number of disputed lawsuits and regulatory proceedings that were pursued originally in state and federal courts and before the FERC. The Mirant entities that are parties to the California Settlement (collectively, the “Mirant Settling Parties”) include Mirant Corporation, Mirant Americas Energy Marketing, the Company, and Mirant North America (as the successor to Mirant California Investments, Inc.). The California Settlement was approved by the FERC on April 13, 2005, and became effective April 15, 2005, upon its approval by the Bankruptcy Court. The California Settlement resulted in the release of most of Mirant Americas Energy Marketing’s potential liability (1) in the FERC Refund Proceedings for sales made in the CAISO or the Cal PX markets, (2) in the proceeding also initiated by the FERC in July 2001 to determine whether there had been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest from December 25, 2000, through June 20, 2001, and (3) in any proceedings at the FERC resulting from the Ninth Circuit’s reversal of the FERC’s dismissal of the complaint filed in 2002 by the California Attorney General. Under the California Settlement, the California Parties and those other market participants who have opted into the settlement have released the Mirant Settling Parties from any liability for refunds related to sales of electricity and natural gas in the western markets from January 1, 1998, through July 14,

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2003. Also, the California Parties have assumed the obligation of Mirant Americas Energy Marketing to pay any refunds determined by the FERC to be owed by Mirant Americas Energy Marketing to other parties that do not opt into the settlement for transactions in the CAISO and Cal PX markets during the Refund Period, with the liability of the California Parties for such refund obligation limited to the amount of certain receivables assigned by Mirant Americas Energy Marketing to the California Parties under the California Settlement. The settlement did not relieve Mirant Americas Energy Marketing of liability for any refunds that the FERC determines it to owe (1) to participants in the Cal PX and CAISO markets that are not California Parties (or that did not elect to opt into the settlement) for periods outside of the Refund Period and (2) to participants in bilateral transactions with Mirant Americas Energy Marketing that are not California Parties (or that did not elect to opt into the settlement).

The Company’s view is that the bulk of any obligations of Mirant Americas Energy Marketing to make refunds as a result of sales completed prior to July 14, 2003, in the CAISO or Cal PX markets or in bilateral transactions either have been addressed by the California Settlement or have been resolved as part of Mirant Americas Energy Marketing’s bankruptcy proceedings. To the extent that Mirant Americas Energy Marketing’s potential refund liability arises from contracts that were transferred to Mirant Energy Trading as part of the transfer of the trading and marketing business under the Plan, Mirant Energy Trading may have exposure to any refund liability related to transactions under those contracts.

FERC Show Cause Proceeding Relating to Trading Practices. On June 25, 2003, the FERC issued a show cause order (the “Trading Practices Order”) to more than 50 parties, including Mirant Americas Energy Marketing and subsidiaries of the Company, that a FERC staff report issued on March 26, 2003, identified as having potentially engaged in one or more trading strategies of the type employed by Enron Corporation and its affiliates (“Enron”), as described in Enron memos released by the FERC in May 2002. The Trading Practices Order identified certain specific trading practices that the FERC indicated could constitute gaming or anomalous market behavior in violation of the CAISO and Cal PX tariffs. The Trading Practices Order requires the CAISO to identify transactions between January 1, 2000, and June 20, 2001, that may involve the identified trading strategies, and then requires the applicable sellers involved in those transactions to demonstrate why such transactions were not violations of the CAISO and Cal PX tariffs. On September 30, 2003, the Mirant entities filed with the FERC for approval of a settlement agreement (the “Trading Settlement Agreement”) entered into between certain Mirant entities and the FERC Trial Staff, under which Mirant Americas Energy Marketing would pay $332,411 to settle the show cause proceeding, except for an issue related to sales of ancillary services, which is discussed below. In a November 14, 2003, order in a different proceeding, the FERC ruled that certain allegations of improper trading conduct with respect to the selling of ancillary services during 2000 should be resolved in the show cause proceeding. On December 19, 2003, the Mirant entities filed with the FERC for approval of an amendment to the Trading Settlement Agreement reached with the FERC Trial Staff with respect to the sale of ancillary services. Under that amendment, the FERC would have an allowed unsecured claim in Mirant Americas Energy Marketing’s bankruptcy proceeding for $3.67 million in settlement of the allegations with respect to the sale of ancillary services. The FERC approved the Trading Settlement Agreement, as amended, on June 27, 2005, and the Bankruptcy Court approved it on August 24, 2005. Certain parties filed motions for rehearing, which the FERC denied on October 11, 2006. A party to the proceeding has appealed the FERC’s June 27, 2005, order to the Ninth Circuit.

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Mirant Americas Energy Marketing Contract Dispute with Nevada Power. On December 5, 2001, Nevada Power Co. filed a complaint at the FERC seeking reformation of the purchase price of energy under a contract it had entered with Mirant Americas Energy Marketing, claiming that the prices under that contract were unjust and unreasonable because, when it entered into the contract, western power markets were dysfunctional and non-competitive markets. On June 25, 2003, the FERC dismissed this complaint. Nevada Power appealed that dismissal to the United States Court of Appeals for the Ninth Circuit, which on December 19, 2006, reversed the dismissal of the complaint and remanded the proceeding to the FERC. The sales made under the contract with Nevada Power have been completed, and the Company expects that any refund claim related to that contract, if not now barred, will be addressed in the Chapter 11 proceedings.

Mirant Americas Energy Marketing Contract Dispute with Southern California Water. On December 21, 2001, Southern California Water Co. filed a complaint at the FERC seeking reformation of the purchase price of energy under a long-term contract it had entered with Mirant Americas Energy Marketing, claiming that the prices under that contract were unjust and unreasonable because, when it entered the contract, western power markets were dysfunctional and non-competitive markets. The contract was for the purchase of 15 MWs during the period April 1, 2001, through December 31, 2006. On June 25, 2003, the FERC dismissed this proceeding. Southern California Water appealed that dismissal to the United States Court of Appeals for the Ninth Circuit, which on December 19, 2006, reversed the dismissal of the complaint and remanded the proceeding to the FERC. Upon the transfer of the assets of the trading and marketing business to Mirant Energy Trading under the Plan, Mirant Energy Trading assumed Mirant Americas Energy Marketing’s contract obligations to Southern California Water Company, including any potential refund obligations.

U.S. Government Inquiries

Environmental Matters

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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 subsidiaries’ acquisition or lease of the plants. If a violation is determined to have occurred at any of the plants, the Company 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’s subsidiaries owning or leasing the Chalk Point, Dickerson and Morgantown plants in Maryland will be installing a variety of emissions control equipment on those plants to comply with the Maryland Healthy Air Act, but that equipment will 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’s subsidiaries acquired or leased the plants or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, the Company’s 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, Mirant Potomac River, Mirant Mid-Atlantic, 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 Mirant Mid-Atlantic to (1) install pollution control equipment at the Potomac River plant in Virginia and at the Morgantown plant in Maryland leased by Mirant Mid-Atlantic, (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 Mirant Mid-Atlantic’s Morgantown units 1 and 2 in 2007 and 2008, the Original Consent Decree would not have obligated the Company’s subsidiaries 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, Mirant Mid-Atlantic 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.

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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.

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.

128

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.

129

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.

On August 30, 2006, the four environmental organizations filed suit in the United States District Court for the District of Maryland against Mirant, Mirant Mid-Atlantic, 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.

130

New York State Administrative Claim. On January 24, 2006, the State of New York and the NYSDEC filed a notice of administrative claims in the Mirant Debtors’ Chapter 11 proceedings asserting a claim seeking to require the Mirant Debtors to provide funding to the Company’s subsidiaries owning generating facilities in New York to satisfy certain specified environmental compliance obligations. The State of New York alleges that during the pendency of the Chapter 11 proceedings the Mirant Debtors that have emerged from bankruptcy made decisions on behalf of the Company’s subsidiaries owning generating facilities in New York and did not appropriately maintain the corporate separateness between themselves and those subsidiaries. The Company disputes those allegations. The State of New York cites various existing outstanding matters between the State and the Company’s subsidiaries owning generating facilities in New York related to compliance with environmental laws and regulations, most of which are not material. The most significant compliance obligation identified by the State of New York in its notice of administrative claim relates to the “2003 Consent Decree” entered into by Mirant New York and Mirant Lovett with the State of New York to resolve issues related to NSR requirements under the Clean Air Act related to the Lovett plant. Under the 2003 Consent Decree, Mirant Lovett is required to make an election to install certain environmental controls on units 5 and 4 of the Lovett facility or shut down those units by April 30, 2007, and April 30, 2008, respectively. The State of New York notes in its notice of administrative claim that the cost of implementing such environmental controls could exceed $200 million. On October 19, 2006, Mirant Lovett notified the New York Public Service Commission and the NYISO of its intent to discontinue operation of unit 5 of the Lovett facility in April 2007 in accordance with the requirements of the 2003 Consent Decree. If Mirant Lovett is able to agree with the State of New York and the NYSDEC on alternative control technologies that would allow unit 5 to remain in operation past April 30, 2007, then Mirant Lovett may rescind the notice of its intent to discontinue operations at unit 5. The State of New York and the NYSDEC have executed a stipulated order with the Company, its New York subsidiaries and the other Mirant Debtors to stay resolution of this administrative claim. That stipulated order was approved by the Bankruptcy Court on February 23, 2006.

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.

131

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.

132

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.

New York Tax Proceedings

133

to adopt the New York state court’s assessed values for the Bowline Facility and the Lovett Facility for 2003 as the assessed values for each facility for 2004 through 2006. The parties agreed that the assessed values for the HVG Property for 2004 through 2006 should be the values determined previously by Haverstraw. The Tax Jurisdictions agreed to cancel penalties on the unpaid taxes owed by the New York Companies and to collect interest on those taxes at a rate of 8% per year for Mirant Bowline and Mirant Lovett and 12% per year for Hudson Valley Gas. Overall, the New York Companies under the settlement received total refunds of $163 million from the Tax Jurisdictions and paid unpaid taxes to the Tax Jurisdictions of $115 million, resulting in the New York Companies receiving a net cash payment in the amount of $48 million. The refunds and unpaid taxes were paid in early February 2007, and the New York Companies and the Tax Jurisdictions are in the process of dismissing all pending litigation related to the refunds and the unpaid taxes.

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.

Other Contingencies

Swinging Bridge. On May 5, 2005, Mirant NY-Gen discovered a sinkhole at its Swinging Bridge dam, located in Sullivan County, New York. In response, Mirant NY-Gen filled this sinkhole, inspected for damage the dam’s slopes and the enclosed pipe that delivers water from the reservoir to the generator, drew down the lake level, and cleaned the diversion tunnel. Mirant NY-Gen’s analysis indicated that the most probable cause of the sinkhole was erosion of soil comprising the dam from water flow through a hole in the pipe that delivers water from the reservoir to the generator. The dam is currently stabilized, and Mirant NY-Gen is performing additional remediation repairs. Mirant NY-Gen currently expects to incur additional costs to repair the dam and to recover insurance proceeds for a portion of these repair costs. By letter dated June 14, 2006, the FERC authorized Mirant NY-Gen to proceed with its remediation plan for the sinkhole. The FERC has also concurred with the results of Mirant NY-Gen’s flood study for its New York Swinging Bridge, Rio and Mongaup generation facilities, which study concluded that no additional remediation is required. The Bankruptcy Court authorized Mirant NY-Gen to proceed with implementation of the remediation plan on June 29, 2006. The current estimated cost to remediate the dam at Swinging Bridge is approximately $29 million, of which approximately $22 million had been incurred through December 31, 2006. The Bankruptcy Court has approved a debtor-in-possession loan to Mirant NY-Gen from Mirant Americas under which Mirant Americas, subject to certain conditions, would lend up to $16.5 million to Mirant NY-Gen to provide funding for the repairs on the Swinging Bridge dam.

California Settlement. The California Settlement described above in California and Western Power Markets—FERC Refund Proceedings included a provision that either (1) the partially constructed Contra Costa 8 project, which is a planned 530 MW combined cycle generating facility, and related equipment (collectively, the “CC8 Assets”) were to be transferred to PG&E or (2) PG&E would receive additional alternative consideration of $70 million (the “CC8 Alternative Consideration”). To fund the CC8 Alternative Consideration, PG&E received an allowed, unsecured claim in the bankruptcy proceedings against Mirant Delta that resulted in a distribution to PG&E of cash and Mirant common stock with a

134

value of approximately $70 million. PG&E was required to liquidate the common stock received as part of that distribution and place the net resulting amount plus any cash received into an escrow account.

The California Settlement provided that if the transfer of the CC8 Assets to PG&E did not occur on or before June 30, 2008, then the CC8 Alternative Consideration was to be paid to PG&E and the Mirant Settling Parties would retain the CC8 Assets. If PG&E closed on its acquisition of the CC8 Assets, the funds in the escrow account were to be paid to Mirant Delta. The transfer of the CC8 Assets to PG&E was completed on November 28, 2006, and the $70 million escrow account was paid to Mirant Delta. The Company recognized in the fourth quarter of 2006 a gain of $27 million for the amount by which the escrow account exceeded the carrying amount of the CC8 Assets. The gain is included in other income in the Company’s consolidated statements of operations.

135

Delaware	N/A	51-0390520
(State or other jurisdiction of	(Commission	(I.R.S. Employer
Incorporation or Organization)	File Number)	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)

	At December 31,
	2006			2005
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	753		$	424
Funds on deposit	233			1,540
Receivables:
Affiliate	12			21
Nonaffiliate, less allowance for uncollectibles of $2 and $10 for 2006 and 2005, respectively	371			578
Price risk management assets—affiliate	3			—
Price risk management assets—nonaffiliate	728			603
Prepaid rent and other payments	131			134
Inventories	288			275
Investment in securities available for sale	—			30
Assets held for sale	519			543
Total current assets	3,038			4,148
Property, Plant and Equipment, net	2,187			2,295
Noncurrent Assets:
Intangible assets, net	212			221
Price risk management assets—affiliate	1			—
Price risk management assets—nonaffiliate	104			105
Prepaid rent	218			208
Funds on deposit	6			5
Debt issuance costs, net	59			37
Other	12			1
Total noncurrent assets	612			577
Total assets	$	5,837		$	7,020
LIABILITIES AND EQUITY
Current Liabilities:
Notes payable—affiliate	$	13		$	21
Current portion of long-term debt	141			3
Claims payable and estimated claims accrual	5			1,831
Accounts payable and accrued liabilities	329			483
Payable to affiliate	48			305
Price risk management liabilities—affiliate	13			5
Price risk management liabilities—nonaffiliate	286			791
Accrued property taxes	75			184
Other	27			16
Total current liabilities	937			3,639
Noncurrent Liabilities:
Long-term debt	3,131			2,579
Price risk management liabilities—affiliate	4			—
Price risk management liabilities—nonaffiliate	39			27
Asset retirement obligations	41			33
Other	7			5
Total noncurrent liabilities	3,222			2,644
Liabilities Subject to Compromise	34			34
Commitments and Contingencies
Equity:
Member’s interest	1,983			995
Preferred stock in affiliate	(339		)	(319		)
Accumulated other comprehensive income	—			27
Total equity	1,644			703
Total liabilities and equity	$	5,837		$	7,020

		Page
	Glossary of Certain Defined Terms		i-v
	PART I
Item 1.	Business		5
Item 1A.	Risk Factors		22
Item 1B.	Unresolved Staff Comments		31
Item 2.	Properties		32
Item 3.	Legal Proceedings		33
Item 4.	Submission of Matters to a Vote of Security Holders		43
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		44
Item 6.	Selected Financial Data		44
Item 7.	Management’s Discussion and Analysis of Results of Operations and Financial Condition		45
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		75
Item 8.	Financial Statements and Supplementary Data		78
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		137
Item 9A.	Controls and Procedures		137
Item 9B.	Other Information		137
	PART III
Item 10.	Directors and Executive Officers of the Registrant		138
Item 11.	Executive Compensation		140
Item 12.	Security Ownership of Certain Beneficial Owners and Management		140
Item 13.	Certain Relationships and Related Transactions		140
Item 14.	Principal Accountant Fees and Services		140
	PART IV
Item 15.	Exhibits and Financial Statements		141

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 Corporation. Board Manager of Mirant Mid-Atlantic. 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 Corporation.
James V. Iaco	62	Board Manager as of January 3, 2006. Executive Vice President and Chief Financial Officer of Mirant Corporation since November 2005. Board Manager of Mirant Mid-Atlantic. 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, Mirant Americas Generation and Mirant North America as of January 9, 2006. Chairman of the Board of Mirant Mid-Atlantic. Mr. Edgell is Executive Vice President and U.S. Region Head of Mirant Corporation since 2006. He was employed as Executive Vice President and General Manager of the Asia Pacific Region for Edison Mission Energy from 1996-2000.

Exhibit Number		Exhibit Name
2.1*		Purchase and Sale Agreement, dated as of January 15, 2007, by and between Mirant Americas, Inc. and LS Power (Designated on Form 8-K dated January 18, 2007 as Exhibit 2.1)
3.1*		Certificate of Formation for Mirant Americas Generation, LLC, filed with the Delaware Secretary of State on November 1, 2001(designated in Mirant Americas Generation, LLC Form 10-Q for the Quarter Ended September 30, 2001 as Exhibit 3.1)
3.2*		Amended and Restated Limited Liability Company Agreement for Mirant Americas Generation LLC, dated January 3, 2006, (designated on Form 10-Q for the quarter ended September 30, 2006, as Exhibit 3.2)
4.1*		Indenture between the Company and Bankers Trust Company, as Trustee, relating to the Notes (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4, Registration No. 333-63240 as Exhibit 4.1)
4.2*		First Supplemental Indenture (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4, Registration No. 333-63240 as Exhibit 4.2)
4.3*		Second Supplemental Indenture (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4, Registration No. 333-63240 as Exhibit 4.3)
4.4*		Third Supplemental Indenture (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4, Registration No. 333-63240 as Exhibit 4.4)
4.5*		Form of Notes (included in Exhibits 4.2, 4.3, and 4.4) (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4, Registration No. 333-63240 as Exhibit 4.5)
4.6*		Registration Rights Agreement, dated as of October 9, 2001, among the Company and the Initial Purchasers (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4/A Amendment No. 1, Registration No. 333-85124 as Exhibit 4.8)
4.7*		Fourth Supplemental Indenture (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4/A Amendment No. 1, Registration No. 333-85124 as Exhibit 4.5)
4.8*		Fifth Supplemental Indenture (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4/A Amendment No. 1, Registration No. 333-85124 as Exhibit 4.6)
4.9*		Form of Senior Note Indenture between Mirant North America, LLC, Mirant North America Escrow, LLC, MNA Finance Corp. and Law Debenture Trust Company of New York, as Trustee (Designated in Mirant Corporation 10-K for the year ended December 31, 2005 as Exhibit 4.2)
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*		Tax Settlement Agreement, dated as of December 13, 2006, by and among Mirant Corporation, Mirant New York, Inc., Mirant Bowline, LLC, Mirant Lovett, LLC, Hudson Valley Gas Corporation and the Town of Haverstraw, the Town of Stony Point, the Haverstraw-Stony Point Central School District, the County of Rockland, the Village of Haverstraw, and the Village of West Haverstraw (Designated on Form 8-K filed December 15, 2006 as Exhibit 10.1)
10.3*		Mirant Americas Generation, LLC—Facility B Credit Agreement (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.70)
10.4*		Mirant Americas Generation, LLC—Facility C Credit Agreement (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.71)
10.5*		Mirant North America, LLC—Credit Agreement with Deutsche Bank Securities Inc., Goldman Sachs Credit Partners L.P., and JPMorgan Chase Bank, N.A. (designated in Mirant Corporation Form 10-K for the year ended December 31, 2005 as Exhibit 10.33)
10.6*		Administrative Services Agreement dated as of January 3, 2006 between Mirant Americas Generation, Inc. and Mirant Services, LLC (Designated on Form 10-K filed March 31, 2006 as Exhibit 10.5)
10.7*		Power Sale, Fuel Supply and Services Agreement dated as of January 3, 2006 among Mirant Americas Energy Marketing, LP, Mirant Bowline, LLC, Mirant Lovett, LLC, and Mirant NY-Gen, LLC (Designated on Form 10-K filed March 31, 2006 as Exhibit 10.6)
10.8*		Power Sale, Fuel Supply and Services Agreement dated as of January 3, 2006 among Mirant Americas Energy Marketing, LP, Mirant Canal, LLC, and Mirant Kendall, LLC (Designated on Form 10-K filed March 31, 2006 as Exhibit 10.7)
10.9*		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 10.8)
10.10*		Power Sale, Fuel Supply and Services Agreement dated as of January 3, 2006 between Mirant Americas Energy Marketing, LP and Mirant Mid-Atlantic, LLC (Designated on Form 10-K filed March 31, 2006 as Exhibit 10.9)
10.11*		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 10.10)
10.12*		Power Sale, Fuel Supply and Services Agreement dated January 3, 2006 between Mirant Americas Energy Marketing, LP and Mirant Texas, LP (Designated on Form 10-K filed March 31, 2006 as Exhibit 10.10)
10.13*		Power Sale, Fuel Supply and Services Agreement dated January 3, 2006 among Mirant Americas Energy Marketing, LP, Mirant Delta, LLC, and Mirant Potrero, LLC (Designated on Form 10-K filed March 31, 2006 as Exhibit 10.11)
10.14*		Power Sale, Fuel Supply and Services Agreement dated January 3, 2006 among Mirant Americas Energy Marketing, LP and Mirant Zeeland, LLC (Designated on Form 10-K filed March 31, 2006 as Exhibit 10.13)
21.1		Subsidiaries of Mirant Americas Generation, 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)).

	MIRANT AMERICAS GENERATION, LLC
	By:	/s/ ROBERT E. DRISCOLL
		Robert E. Driscoll
		President and Chief Executive Officer
		(Principal Executive Officer)

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

Name of Company	Jurisdiction of Organization
Mirant Americas Generation, LLC		Delaware
Mirant North America, LLC		Delaware
MNA Finance Corp.		Delaware
Mirant Energy Trading, LLC		Delaware
Mirant California, LLC		Delaware
Mirant Delta, LLC		Delaware
Mirant Potrero, LLC		Delaware
Mirant Canal, LLC		Delaware
Mirant Kendall, LLC		Delaware
Mirant New York, Inc.		Delaware
Mirant Bowline, LLC		Delaware
Mirant Lovett, LLC		Delaware
Mirant NY-Gen, LLC		Delaware
Hudson Valley Gas Corporation		New York
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
Mirant Special Procurement, Inc.		Delaware
Mirant Texas Management, LLC		Delaware
Mirant Texas, LP (1%—Mirant Texas Management, LLC; 99%—Mirant North America, LLC)		Delaware
MLW Development, LLC (1%—Mirant Texas Management, LLC; 99%—Mirant North America, LLC)		Delaware
Mirant Zeeland, LLC		Delaware

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

Name:		/s/ ROBERT E. DRISCOLL
		President and Chief Executive Officer