**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C.20549**

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**Form 10-K**

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

**For the Fiscal YearEnded December 31, 2005**

**Or**

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

**For the TransitionPeriodfrom              to**

**Mirant AmericasGeneration, LLC**

(Exact name of registrantas specified in its charter)

| **Delaware**                                                      | **N/A**                   | **51-0390520**                        |
|-------------------------------------------------------------------|---------------------------|---------------------------------------|
| (State or other  jurisdiction of  Incorporation or Organization)  | (Commission File  Number) | (I.R.S. Employer  Identification No.) |
| **1155 Perimeter Center West,  Suite 100, Atlanta, Georgia** | **30338**                 |
| (Address of  Principal Executive Offices)                         | (Zip Code)                |
| **(678) 579-5000**                                                |                      |
| (Registrant’s Telephone  Number, Including Area Code)        |                      |
|                                                                   |                           |                                       |  |  |

 

**Securities registered pursuant to Section 12(b) ofthe Act:**

**None**

**Securities registered pursuant to Section 12(g) ofthe Act:**

**None**

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 Indicate by check mark whether the registrantis a well-known seasoned issuer (as defined by Rule 405 of the SecuritiesAct). o Yes  x  No

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

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required tofile such reports), and (2) has been subject to such filing requirementsfor the past 90 days. o  Yes  x  No

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K isnot contained herein, and will not be contained, to the best of the registrants’knowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment tothis Form 10-K. x

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer or anon-accelerated filer. See definition of “accelerated filer and largeaccelerated filer” in Rule 12b-2 of the Exchange Act. o  Large Accelerated Filer  o  Accelerated Filer  x  Non-accelerated Filer

Indicate by check markwhether the registrant is a shell company (as defined by Rule 12b-2of the Act). o Yes    x No

Indicate by check markwhether the registrant has filed all documents and reports required to be filedby Section 12, 13 or 15(d) of the Securities Exchange Act of 1934subsequent to the distribution of securities under a plan confirmed by a court.x  Yes  o  No

All of our outstandingmembership interests are held by our parent, Mirant Americas, Inc., so wehave no membership interests held by nonaffiliates.

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

 

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**TABLE OF CONTENTS**

|               | ** ** | ** **                                                                                                         | ** ** | **Page** | ** ** |
|---------------|------------|--------------------------------------------------------------------------------------------------------------------|------------|----------|------------|
| ** **    | ** ** | **PART I**                                                                                                    |       |     |       |   |   |
| Item 1.       |       | Business                                                                                                           |       |     | 5          |   |   |
| Item 1A.      |       | Risk  Factors                                                                                                      |       |     | 24         |   |   |
| Item 1B.      |       | Unresolved Staff Comments                                                                                          |       |     | 34         |   |   |
| Item 2.       |       | Properties                                                                                                         |       |     | 34         |   |   |
| Item 3.       |       | Legal  Proceedings                                                                                                 |       |     | 35         |   |   |
| Item 4.       |       | Submission of Matters to a Vote of Security Holders                                                                |       |     | 44         |   |   |
| ** **    | ** ** | **PART II**                                                                                                   |       |     |       |   |   |
| Item 5.       |       | Market for Registrant’s Common Equity, Related  Stockholder Matters and Issuer Purchases of Equity Securities |       |     | 45         |   |   |
| Item 6.       |       | Selected  Financial Data                                                                                           |       |     | 45         |   |   |
| Item 7.       |       | Management’s Discussion and Analysis of Financial  Condition and Results of Operations                        |       |     | 46         |   |   |
| Item 7A. |       | Quantitative and Qualitative Disclosures About Market  Risk                                                        |       |     | 74         |   |   |
| Item 8.       |       | Financial Statements and Supplementary Data                                                                        |       |     | 77         |   |   |
| Item 9.       |       | Changes In and Disagreements with Accountants on  Accounting and Financial Disclosure                              |       |     | 132        |   |   |
| Item 9A.      |       | Controls and Procedures                                                                                            |       |     | 132        |   |   |
| ** **    | ** ** | **PART III**                                                                                                  |       |     |       |   |   |
| Item 10.      |       | Directors and Executive Officers of the Registrant                                                                 |       |     | 133        |   |   |
| Item 11.      |       | Executive Compensation                                                                                             |       |     | 135        |   |   |
| Item 12.      |       | Security Ownership of Certain Beneficial Owners and  Management                                                    |       |     | 135        |   |   |
| Item 13.      |       | Certain Relationships and Related Transactions                                                                     |       |     | 135        |   |   |
| Item 14.      |       | Principal Accountant Fees and Services                                                                             |       |     | 135        |   |   |
| ** **    | ** ** | **PART IV**                                                                                                   |       |     |       |   |   |
| Item 15.      |       | Exhibits and Financial Statement Schedules                                                                         |       |     | 136        |   |   |

 

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**CAUTIONARY STATEMENT REGARDING FORWARD-LOOKINGINFORMATION**

The information presented in this Form 10-Kincludes forward-looking statements within the meaning of Section 27Aof the Securities Act of 1933 and Section 21E of the Securities ExchangeAct of 1934 in addition to historical information. These statements involveknown and unknown risks and uncertainties and relate to future events, ourfuture financial performance or our projected business results. In some cases,you can identify forward-looking statements by terminology such as “may,”“will,” “should,” “expect,” “plan,” “anticipate,” “estimate,” “predict,” “target,”“potential” or “continue” or the negative of these terms or other comparableterminology.

Forward-lookingstatements are only predictions. Actual events or results may differ materiallyfrom any forward-looking statement as a result of various factors, whichinclude:

·       legislativeand regulatory initiatives regarding deregulation, regulation or restructuringof the electric utility industry; changes in state, federal and otherregulations (including rate and other regulations); changes in, or changes inthe application of, environmental and other laws and regulations to which weand our subsidiaries and affiliates are or could become subject;

·       failureof our assets to perform as expected, including outages for unscheduledmaintenance or repair;

·       ourpursuit of potential business strategies, including the disposition orutilization of assets;

·       changesin market conditions, including developments in energy and commodity supply,demand, volume and pricing, or the extent and timing of the entry of additionalcompetition in our markets or those of our subsidiaries and affiliates;

·       increased marginrequirements, market volatility or other market conditions that could increaseour obligations to post collateral beyond amounts which are expected;

·       our inability to accesseffectively the over-the-counter and exchange-based commodity markets orchanges in commodity market liquidity or other commodity market conditions,which may affect our ability to engage in asset management and proprietarytrading activities as expected;

·       ourability to borrow additional funds and access capital markets;

·       strikes,union activity or labor unrest;

·       weatherand other natural phenomena, including hurricanes and earthquakes;

·       thecost and availability of emissions allowances;

·       ourability to obtain adequate fuel supply and delivery for our facilities;

·       curtailmentof operations due to transmission constraints;

·       environmentalregulations that restrict our ability to operate our business;

·       war,terrorist activities or the occurrence of a catastrophic loss;

·       deteriorationin the financial condition of our counterparties and the resulting failure topay amounts owed to us or to perform obligations or services due to us;

·       hazardscustomary to the power generation industry and the possibility that we may nothave adequate insurance to cover losses as a result of such hazards;

·       pricemitigation strategies employed by independent system operators (“ISOs”) orregional transmission organizations (“RTOs”) that result in a failure tocompensate our generation units adequately for all of their costs;

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·       volatilityin our gross margin as a result of our accounting for derivative financialinstruments used in our asset management activities and volatility in our cashflow from operations resulting from working capital requirements, includingcollateral, to support our asset management and proprietary trading activities;

·       ourinability to enter into intermediate and long-term contracts to sell power andprocure fuel on terms and prices acceptable to us;

·       theinability of our operating subsidiaries to generate sufficient cash flow andour inability to access that cash flow to enable us to make debt service andother payments;

·  the fact that our New York subsidiariesremain in bankruptcy;

·       oursubstantial consolidated indebtedness and the possibility that we or oursubsidiaries may incur additional indebtedness in the future;

·       restrictionson the ability of our subsidiaries to pay dividends, make distributions orotherwise transfer funds to us, including restrictions on Mirant Mid-Atlantic,LLC (“Mirant Mid-Atlantic”) contained in its leveraged lease financingagreements;

·  the resolution of claims and obligations thatwere not resolved during the Chapter 11 process that may have a materialadverse effect on our results of operations;

·  our ability to negotiate favorable terms fromsuppliers, counterparties and others and to retain customers because we werepreviously subject to bankruptcy protection; and

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

·       Weundertake no obligation to publicly update or revise any forward lookingstatements to reflect events or circumstances that may arise after the date ofthis report.

Other factors that could affect our future performance(business, financial condition or results of operations and cash flows) are setforth under “Item 1A. Risk Factors.”

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**PART I**

**Item 1.**   *Business*

**Overview**

**Mirant Americas Generation, LLC,including its subsidiaries (collectively, the “Company” or “Mirant Americas Generation”)is a national independent power provider and an indirect wholly-ownedsubsidiary of Mirant Corporation (“Mirant”). We produce and sell substantiallyall of the output from our generating facilities in the forward and spotmarkets and the remainder under contracts with third parties. We use derivativefinancial instruments, such as commodity forwards, futures, options and swapsto manage our exposure to fluctuations in electric energy and fuel prices. Weare a Delaware limited liability company that owns or leases approximately12,035 megawatts (“MW”) of electric generation capacity in the United States.We operate 72 generating units at 21 plants serving customers located nearmajor metropolitan load centers in Maryland, California, New York,Massachusetts and Texas.**

**Pursuant to the Plan ofReorganization (the “Plan”), in December 2005 Mirant contributed its interestin Mirant Potomac River, LLC (“Mirant Potomac River”) and Mirant Peaker, LLC(“Mirant Peaker”) our indirect wholly owned subsidiary Mirant Mid-Atlantic, LLC(“Mirant Mid-Atlantic”) and its interest in Mirant Zeeland, LLC (“MirantZeeland”) and Mirant Americas Energy Marketing, LP (“Mirant Americas EnergyMarketing”), Mirant Americas Development, Inc., Mirant Americas ProductionCompany, Mirant Americas Energy Capital, LLC, Mirant Americas Energy CapitalAssets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas RetailEnergy Marketing, L.P., and Mirant Americas Gas Marketing, LLC, (collectively,the “Trading Debtors”) to Mirant North America, LLC (“Mirant North America”), anewly organized holding company subsidiary. All of the contributed subsidiarieswere under the common control of Mirant and are collectively referred to as the“Contributed Subsidiaries.” Mirant’s contribution of the ContributedSubsidiaries resulted in a change in the Mirant Americas Generation reportingentity under Accounting Principles Board Opinion No. 20, “*Accounting Changes*”, and accordingly we have restated thefinancial statements for all prior periods to reflect the financial informationof the new reporting entity. See Note 4 for further discussion. On January 31,2006, the trading and marketing business of the Trading Debtors was transferredto Mirant Energy Trading, LLC (“Mirant Energy Trading”) a wholly-ownedsubsidiary of MirantNorth America.**

**We have a number of serviceagreements for labor and administrative services with Mirant and MirantServices, LLC (“Mirant Services”). In addition, Mirant Energy Trading, andpreviously Mirant Americas Energy Marketing, provides services to other Mirantaffiliates related to the sale of electric power and the procurement of fuel andemissions allowances. These agreements are discussed further in Note 6.**

**The annual, quarterly and currentreports, and any amendments to those reports, that we file with or furnish tothe U.S. Securities and Exchange Commission (“SEC”) are available free ofcharge on Mirant’s website at *www.mirant.com*as soon as reasonably practicable after they are electronically filed with orfurnished to the SEC. Information contained in this website is not incorporatedinto this Form 10-K,**

**As used in this report, “we,” “us,”“our,” the “Company” and “Mirant Americas Generation” refer to Mirant AmericasGeneration, LLC and its subsidiaries, unless the context requires otherwise.**

**Reorganizationunder Chapter 11 of the Bankruptcy Code**

On July 14, 2003 (the “Petition Date”), andvarious dates thereafter, Mirant Americas Generation and its subsidiaries wereamong the 83 direct and indirect Mirant subsidiaries in the United States that,along with Mirant (collectively, the “Mirant Debtors”), filed with the United States Bankruptcy Court for the NorthernDistrict of Texas, Fort Worth Division (the “Bankruptcy Court”) voluntarypetitions for relief under Chapter 11 of Title 11 of the United StatesBankruptcy Code (as amended, the “Bankruptcy Code”), commencing the case*In re Mirant**Corporationet al.,* Case No. 03-46590 (DML).

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During the pendency of the Chapter 11 proceedings, we,along with the other Mirant Debtors, operated our business asdebtors-in-possession under the jurisdiction of the Bankruptcy Court and inaccordance with the applicable provisions of the Bankruptcy Code, the Federal Rules ofBankruptcy Procedure and applicable orders, as well as other applicable lawsand rules. In general, each of the Mirant Debtors, as a debtor-in-possession,was authorized under the Bankruptcy Code to continue to operate as an ongoingbusiness, but not to engage in transactions outside the ordinary course ofbusiness without the prior approval of the Bankruptcy Court.

On December 9, 2005, the Bankruptcy Court enteredan order confirming our Plan, which became effective on January 3, 2006.The Plan set forth the structure of the MirantDebtors at emergence and outlined how the claims of creditors and stockholderswere to be treated. The implementation of the Plan resulted in, amongother things, a new Mirant capital structure, the discharge of certainindebtedness, the satisfaction or disposition of various types of claimsagainst the Mirant Debtors, the assumption or rejection of certain contractsand the establishment of a new Mirant Board of Directors.

On January 3, 2006,substantially all of the assets of the old Mirant were transferred to NewMirant, which, pursuant to the Plan, has no successor liability for anyunassumed obligations of the old Mirant. Additionally Mirant Energy Trading,pursuant to the Plan, has no successor liability for any unassumed obligationsof the Trading Debtors. After these transfers took place, old Mirant and theTrading Debtors, were transferred to a trust created under the Plan.

**Competitive Environment**

Historically, vertically integrated electric utilitieswith monopolistic control over franchised territories dominated the powergeneration industry in the United States. The enactment of the Public UtilityRegulatory Policies Act of 1978 (“PURPA”), and the subsequent passage of theEnergy Policy Act of 1992, fostered the growth of independent power producers.During the 1990s, a series of regulatory policies were partially implemented atboth the federal and state levels to encourage competition in wholesale electricitymarkets.

As a result, independent power producers built newgenerating plants, purchased plants from regulated utilities and marketedwholesale power. Independent system operators (“ISOs”) and regionaltransmission organizations (“RTOs”) were created to administer the new marketsand maintain system reliability. Beginning in the fall of 2001, however, inresponse to extreme price volatility and energy shortages in California,regulators began to re-examine the nature and pace of deregulation of wholesaleelectricity markets and that re-examination is continuing.

Independent power producers, as well as utilities,constructed primarily natural gas fired plants in the 1990s because such plantscould be constructed more quickly and were less expensive to permit and buildthan nuclear facilities or plants fired by other fossil fuels. Stagnation inthe growth of natural gas supplies, the increased demand from new generationfacilities and the damage caused by hurricanes Katrina and Rita resulted in a sharpincrease in the prices of natural gas during 2005. These high natural gasprices have significantly affected electricity prices in markets where gasfired units generally set the price. Some companies are constructing orattempting to obtain permits to construct additional liquefied natural gasreceiving facilities which would increase the non-domestic supply of naturalgas to the United States and could help to mitigate natural gas prices.

Coal fired generation and nuclear generation accountfor approximately 50% and 20%, respectively, of the electricity produced in theUnited States. Current high electricity prices as a result of high natural gasprices have led to renewed interest in new coal fired or nuclear plants. Someregulated utilities are proposing to construct clean coal units or new nuclearplants, in some cases with governmental subsidies or under legislative mandate.These utilities often are able to recover fixed costs through regulated retailrates, including, in many circumstances, the costs of environmentalimprovements to existing coal facilities, 

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allowing them to build,buy and upgrade without relying on market prices to recover their investmentsas we must do.

A number of factors combined to create excessgenerating capacity in certain U.S. markets, including the substantial increasein construction of generation facilities following the deregulation effortsdescribed above, capital investments by utilities aimed at extending the livesof older units and the inability to decommission certain plants for reliabilityreasons. Although electricity supply and demand spreads have begun to tighten,we do not expect our primary markets to reach target reserve margins,approximately 15% of excess capacity over peak demand, until 2008 to 2010. However,given the time necessary to permit and construct new power plants, we thinkthat certain markets in the United States need to begin now the process ofadding generating capacity to meet growing demand. Many ISOs are consideringcapacity markets as a way to encourage such construction of additionalgeneration, but it is not clear whether independent power producers will besufficiently incentivized to build this new generation.

As a result of recentevents, many regulated utilities are seeking to acquire distressed assets orbuild new generation, in each case with regulatory assurance that the utilitywill 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 adisadvantage because they rely heavily on market prices rather than regulatoryassurances.

**Operating Regions**

*Overview*

Our core business is theproduction and sale of electrical energy, electrical capacity (the ability toproduce electricity on demand) and ancillary services (services that areancillary to transmission services). Our customers are ISOs, utilities,municipal systems, aggregators, electric cooperative utilities, producers,generators, marketers and large industrial customers. We serve four primarygeographic areas: (i) the Mid-Atlantic Region, (ii) the NortheastRegion, (iii) the Mid-Continent Region and (iv) the West Region,including Texas.

*Ownership andOperations of Electricity Generation Assets*

As of December 31,2005, we owned or leased generation facilities in the United States with anaggregate generation capacity of over 12,000 MW. Our generating portfolio isdiversified across fuel types, power markets and dispatch types and servescustomers located near many major metropolitan load centers. We own or controlapproximately 85% of Mirant’s U.S. generating capacity.

*CommercialOperations*

Our commercial operations consist primarily ofprocuring fuel, dispatching electricity, hedging the production and sale ofelectricity by our generating facilities, and providing logistical support forthe operation of our facilities (by, for example, procuring transportation forcoal). We often sell the electricity we produce into the wholesale market atthe prices in effect at the time we produce it (“spot prices”). Those pricesare volatile, however, and in order to reduce the risk of that volatility weoften enter into hedges—forward sales of electricity into the wholesale marketand purchases of enough fuel and emissions allowances to allow us to produceand sell the electricity—for different periods of time. We procure these hedgesin over-the-counter transactions or exchanges where electricity, fuel andemissions allowances are broadly traded, or through specific transactions witha seller, using futures, forwards, swaps and options. We also sell capacity andancillary services where there are markets for such products and when it iseconomic to do so. In addition to selling the electricity we produce and buyingthe fuel and emissions allowances we need to produce electricity (“assetmanagement”), and subsequent to Mirant’s contribution of the trading andmarketing operations to us, we buy and sell some electricity that we do notproduce and some fuel and emissions allowances that we do not need to produceelectricity (“proprietary trading”). 

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Proprietary trading is asmall part of our commercial operations, which we do in order to gaininformation about the markets, in support of our asset management, and to takeadvantage of opportunities that we may see from time to time. All of ourcommercial activities are governed by a comprehensive Risk Management Policy,which requires that our hedging activities with respect to our assets be riskreducing and sets limits on the size of trading positions and value-at-risk inour proprietary trading activities.

Commercial operations for our subsidiaries and otherMirant subsidiaries were conducted historically through Mirant Americas EnergyMarketing. As of February 1, 2006, the energy trading and marketingoperations of Mirant Americas Energy Marketing are being performed by MirantEnergy Trading.

Mirant Energy Trading has contracted with oursubsidiaries and other Mirant subsidiaries that own generation facilities toprocure fuel, dispatch facilities and sell the electricity generated in thewholesale market. Mirant Energy Trading uses dispatch models to make dailydecisions regarding the quantity and the price of the power that our facilitieswill generate and sell into the markets. In markets governed by ISOs and RTOs,Mirant Energy Trading bids the energy from generation facilities into theday-ahead energy market and sells ancillary services through the ISO markets.Mirant Energy Trading works with the ISOs and RTOs in real time to ensure thatMirant and our generation facilities are dispatched economically to meet thereliability needs of the market. In non-ISO markets, Mirant Energy Tradingconducts business through bilateral transactions pursuant to which MirantEnergy Trading provides dispatch schedules to the generation facilities.

We currently economically hedge a substantial portionof our Mid-Atlantic coal fired baseload generation (generation that isdispatched most of the time) and our New England oil fired generation throughover-the-counter transactions. However, we generally do not hedge most of ourcycling and peaking units (generating facilities that are not dispatched asfrequently) due to the limited value we can extract in the marketplace and thehigh cost of collateral typically required to support these contracts. As of March 3,2006, we have economically hedged approximately 90%, 60%, 30%, and 30% of ourexpected Mid-Atlantic coal fired generation for the remainder of 2006, 2007,2008 and 2009, respectively, and purchased approximately 100%, 80%, 30% and 30%of the expected Mid-Atlantic coal requirements for such periods. Included insuch amounts are financial swap transactions entered into by MirantMid-Atlantic with a counterparty in January 2006 pursuant to which MirantMid-Atlantic economically hedged approximately 80%, 50%, and 50% of itsexpected on-peak coal fired baseload generation for 2007, 2008 and 2009,respectively. The financial swap transactions are senior unsecured obligationsof Mirant Mid-Atlantic and do not require us to post cash collateral either inthe form of initial margin or to secure exposure due to changes in powerprices. In addition, as of March 3, 2006, we have economically hedgedapproximately 50% of our expected oil fired generation in New England for the remainderof 2006 and procured approximately 50% of the corresponding expected oilrequirements.

While over-the-counter transactions make up asubstantial portion of our economic hedge portfolio, Mirant Energy Trading alsosells non-standard, structured products to customers. In addition to energy,these products typically include capacity, ancillary services and other energyproducts. We view these transactions as a method of mitigating the risk ofcertain portions of our business that are not easy to economically hedge in theover-the-counter market. Typically, we are able to sell these products at ahigher premium than standard products. For certain generation facilities, wehave sought to enter into longer-term transactions to provide certainty of cashflows over an extended period. These transactions are typically tollingtransactions whereby we receive a fixed capacity payment and, in return, grantan exclusive right for the counterparty to procure the fuel for the generationfacility and take title to the power generated. Additionally, we havefacilities in our business unit operating under long-term contracted capacityand reliability must run (“RMR”) contracts. At December 31, 2005, ourcontracted capacity pursuant to these agreements was approximately 2,699 MWwith terms expiring through April 2014.

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We enter into contracts of varying terms to secureappropriate quantities of fuel that meet the varying specifications of ourgenerating facilities. For our coal fired generation facilities, we purchase coalfrom a variety of suppliers under contracts with terms of varying lengths, someof which extend to 2009. For our oil fired units, fuel is typically purchasedunder short-term contracts usually linked to a transparent oil indexprice. For our gas fired units, fuel is typically purchased under short-termcontracts with a variety of suppliers on a day-ahead or monthly basis.

Our coal supply primarilycomes from both the Central Appalachian and Northern Appalachian coal regions.All of our coal is delivered by rail. We monitor coal supply and deliverylogistics carefully, and despite occasional interruptions of scheduleddeliveries 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 disruptionsdue to strikes or other reasons or as a result of rail system disruptions dueto weather or other reasons.

*Mid-Atlantic Region*

We own or lease four generation facilities with atotal generation capacity of approximately 5,256 MW in the Washington D.C.area: Chalk Point, Morgantown, Dickerson and Potomac River. Our Mid-Atlanticregion had a combined 2005 capacity factor of 39%. The Chalk Point facility isour largest facility in the region. It consists of two coal fired baseloadunits, two oil and gas fired intermediate units, two oil fired and five gas andoil fired peaking units, for a total generation capacity of 2,429 MW. Our nextlargest facility in the region is the Morgantown facility, and it consists oftwo 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 threecoal fired baseload units, one oil fired and two gas and oil fired peakingunits, for a total generation capacity of 853 MW. The Potomac River station hasthree coal fired baseload units and two coal fired intermediate units, for atotal generation capacity of 482 MW.

Power generated by our Mid-Atlantic facilities is soldinto the Pennsylvania-New Jersey-Maryland Interconnection, LLC (“PJM”) market.For a discussion of the PJM market, see “Regulatory Environment*—*U.S. Public Utility Regulation” below. In connection withthe acquisition of the Mid-Atlantic facilities from Potomac Electric PowerCompany (“PEPCO”) in 2000, Mirant Americas Energy Marketing agreed to supplyPEPCO its full load requirement in the District of Columbia under a transitionpower agreement (“TPA”), which expired in January 2005 (the “DC TPA”).There was a similar TPA in place to supply PEPCO’s load in Maryland, whichexpired in June 2004 (the “Maryland TPA”). We also have participatedin standard offer service auctions in Maryland and Washington, D.C. Powersales, made either directly through these functions or indirectly throughsubsequent market transactions that are a result of the auction process, serveas economic hedges for the Mid-Atlantic assets.

On August 24, 2005,power production at all five units of the Potomac River generating facility wastemporarily halted in response to a directive from the Virginia Department ofEnvironmental Quality (“Virginia DEQ”). The decision to temporarily shut downthe facility arose from findings of a study commissioned under the order byconsent referred to above. The Virginia DEQ’s directive was based on resultsfrom the study’s computer modeling showing that air emissions from the facilityhave the potential to contribute to localized, modeled exceedances of thehealth-based national ambient air quality standards (“NAAQS”) under certainconditions. On August 25, 2005, theDistrict of Columbia Public Service Commission filed an emergency petition andcomplaint with the Federal Energy Regulatory Commission (“FERC”) and the Department of Energy (“DOE”) toprevent the shutdown of the Potomac River facility. The matter remains pendingbefore the FERC and the DOE. On December 20, 2005, due to a determinationby the DOE that an emergency situation exists with respect to a shortage ofelectric energy, the DOE ordered Mirant Potomac River to generate electricityat the Potomac River generation facility, as requested by PJM, during anyperiod in which one or both of the transmission lines serving the centralWashington, D.C. area are out of service due to a planned or unplanned outage.In addition, the DOE 

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ordered Mirant Potomac River, at all other times, forelectric reliability purposes, to keep as many units in operation as possibleand to reduce the start-up time of units not in operation. The DOE requiredMirant Potomac River to submit a plan, on or before December 30, 2005,that met this requirement and did not significantly contribute to NAAQSexceedances. The DOE advised that it would consider Mirant Potomac River’s planin consultation with the Environmental Protection Agency (“EPA”). The orderfurther provides that Mirant Potomac River and its customers should agree tomutually satisfactory terms for any costs incurred by it under this order orjust and reasonable terms shall be established by a supplemental order. Certainparties filed for rehearing of the DOE order, and on February 17, 2006,the DOE issued an order granting rehearing solely for purposes of consideringthe rehearing requests further. Mirant Potomac River submitted an operatingplan in accordance with the order. On January 4, 2006, the DOE issued aninterim response to Mirant Potomac River’s operating plan authorizing immediateoperation of one baseload unit and two cycling units, making it possible tobring the entire plant into service within approximately 28 hours. We areselling the output of the facility into PJM. The DOE’s order expires after September 30,2006, but we expect we will be able to continue to operate these units afterthat expiration. In a letter received December 30, 2005, the EPA invitedMirant Potomac River and the Virginia DEQ to work with the EPA to ensure that Mirant Potomac River’s operating plansubmitted to the DOE adequately addresses NAAQS issues. The EPA also asserts inits letter that Mirant Potomac River did not immediately undertake action asdirected by the Virginia DEQ’s August 19, 2005, letter and failed tocomply with the requirements of the Virginia State Implementation Planestablished by that letter. Mirant Potomac River received a second letter fromthe EPA on December 30, 2005, requiring Mirant to provide certainrequested information as part of an EPA investigation to determine the FederalClean Air Act (“Clean Air Act”) compliance status of the Potomac Riverfacility. The facility will not resume normal operations until it can satisfythe requirements of the Virginia DEQ and the EPA with respect to NAAQS, unless,for reliability purposes, it is required to return to operation by agovernmental agency having jurisdiction to order its operation. On January 9,2006, the FERC issued an order directing PJM and PEPCO to file a long-term planto maintain adequate reliability in the Washington D.C. area and surroundingregion and a plan to provide adequate reliability pending implementation ofthis long-term plan. On February 8, 2006, PJM and PEPCO filed theirproposed reliability plans. We are working with the relevant state and federalagencies with the goal of restoring all five units of the facility to normaloperation in 2007.

*Northeast Region*

We own generating facilities in the Northeast regionconsisting of approximately 3,063 MW of capacity. Our Northeast region had acombined 2005 capacity factor of 34%. The Northeast region is comprised of theNew York and New England sub-regions. The subsidiaries that own our New Yorkfacilities remain in bankruptcy. For further information, see “Item 3. LegalProceedings.” Generation is sold from our Northeast facilities through acombination of bilateral contracts, spot market transactions and structuredtransactions.

*NewYork.**  *Our NewYork generating facilities were acquired from Orange and Rockland Utilities, Inc.(“Orange and Rockland”) and Consolidated Edison Company of New York, Inc.in June 1999. The New York generating facilities consist of the Bowlineand Lovett facilities and various smaller generating facilities comprising atotal of approximately 1,672 MW of capacity. The Bowline facility is a 1,125 MWdual-fueled (natural gas and oil) facility comprised of oneintermediate/peaking unit and one intermediate unit. The Lovett facilityconsists of two baseload units capable of burning coal and gas comprising atotal of 348 MW and a peaking unit capable of burning gas or oil comprising 63MW. The smaller New York generating facilities have a total capacity of 136 MWand consist of the Hillburn and Shoemaker facilities, which each contain asingle peaking unit capable of running on natural gas or jet fuel, and theMongaup 1-4, Swinging Bridge 1-2 and Rio 1-2 facilities,which each contain a hydroelectric intermediate unit. We also have anoperational interest in the Grahamsville facility, which has a 

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hydroelectric baseloadunit. Our operational interest in the Grahamsville facility was pursuant to asublease between Orange and Rockland and Mirant NY-Gen, LLC (“Mirant NY-Gen”),which expired on December 30, 2005. We have executed an interim agreementto extend this arrangement, which will be in effect until the earlier of December 31,2006, or the end of the month following the month in which we receiveregulatory approvals from the FERC and the New York Public Service Commissionto transfer the facility to Orange and Rockland, which will transfer thefacility to the City of New York. We received approval of the transfer from theFERC on February 27, 2006. A proposed expansion at the Bowline facility toadd a natural gas and distillate oil fired unit with a total of 750 MW ofgeneration capacity is currently suspended and we are attempting to extendpermits such that we have the option to complete the project. Our New Yorkplants operate in a market operated by the Independent System Operator of NewYork (“NYISO”). For a discussion of the NYISO, see “Regulatory Environment-U.S.Public Utility Regulation” below.

Our current plan is to retire one unit of the MirantLovett, LLC (“Mirant Lovett”) facility in 2007 and the remaining two units in2008. However, we are exploring ways in which to avoid retiring the facility.In order for the facility to remain viable, we need to accomplish three primarytasks. First, we need agreements with the local taxing authorities to reduceproperty taxes. Although conditions remain to be met before the agreements arefinal, all of the taxing authorities have agreed in principle to refunds forpast disputed taxes and substantial reductions in property taxes through 2012.Second, we need to reach agreement with the State of New York on amendments toa consent decree entered into on June 11, 2003, to resolve issues relatedto the new source review (“NSR”) regulationspromulgated under the Clean Air Act (the “2003 Consent Decree”), whichamendments would address the installation of environmental equipment. Third, ascurrent market conditions do not allow Mirant Lovett to recover the necessaryreturns to fund the installation of environmental controls required under the2003 Consent Decree, we will need an agreement with a third party assuring usof enough revenue to justify required capital expenditures. It is our view thatthe Lovett facility is necessary to the provision of reliable electricity toNew York City and other areas within the NYISO.

In May of 2005, a sinkhole was discovered in thedam of our Swinging Bridge facility. Mirant NY-Gen is currently discussing withthe FERC appropriate remediation for this sinkhole. We conducted a flood studyto determine downstream consequences if the maximum capacity of the reservoirswere exceeded at our New York Swinging Bridge, Rio and Mongaup generationfacilities, which may require that Mirant NY-Gen be requested by the FERC toremediate these dams as well. Mirant NY-Gen has initiated discussions with theFERC for surrendering its permits to operate all the hydroelectric facilitiesat Swinging Bridge, Rio and Mongaup, and expects to begin that formal processsoon. It is not possible at this point to determine the cost of remediating thedam and surrendering the permits, but such costs may be substantial.

*New England.**  *Our New England generating facilities, with atotal capacity of 1,391 MW, were acquired from subsidiaries of CommonwealthEnergy System and Eastern Utilities Associates in December 1998. The NewEngland generating facilities consist of the Canal station, the Kendallstation, the Martha’s Vineyard diesels and an interest in the Wyman Unit 4facility. The Canal and Kendall facilities, located in close proximity toBoston, consist of approximately 1,112 MW and 256 MW of generating capacity,respectively, and are designed to operate during periods of intermediate andpeak demand. The Kendall facility is a combined cycle facility capable ofproducing both steam and electricity for sale. Both the Canal and Kendallfacilities possess the ability to burn both natural gas and fuel oil. TheMartha’s Vineyard diesels, with 14 MW of capacity, supply electricity on theisland of Martha’s Vineyard during periods of high demand or in the event of atransmission interruption. The Wyman Unit 4 interest is an approximate 1.4%ownership interest (equivalent to 8.8 MW) in the 614 MW Wyman Unit 4 located onCousin’s Island, Yarmouth, Maine. It is primarily owned and operated by theFlorida Power and Light Group.

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The capacity, energy andancillary services from our New England generating units are sold into the NewEngland Power Pool (“NEPOOL”) bilateral markets and into the marketsadministered by the Independent System Operator—New England (“ISO-NE”) throughMirant Energy Trading. For a discussion of the NEPOOL and the ISO-NE, see “RegulatoryEnvironment—U.S. Public Utility Regulation” below. We had made a determinationthat market fundamentals in NEPOOL did not permit us to operate the Kendallfacility on an economical basis as a merchant facility. We therefore planned toshut down, at least temporarily, the Kendall facility from January 2005through December 2007, with the possibility of restarting operations asearly as January 2008. However, the ISO-NE determined that part of thecapacity of the Kendall facility was needed for reliability and proposed an RMRagreement with a term lasting until the earlier of (1) the date alocational installed capacity cost recovery mechanism applicable to the Kendallfacility is in place or (2) 120-daysafter we are provided written notice. We entered into a settlement agreementwith NSTAR Electric and Gas Corporation and ISO-NE and filed the settlement,which included the RMR agreement with the FERC. The FERC has approved the RMRagreement and we expect that the agreement will extend at least through thesecond quarter of 2006.

*Mid-ContinentRegion*

Pursuant to the Plan, Mirant (indirectly through asubsidiary) contributed its interest in Mirant Zeeland to our subsidiary,Mirant North America. The Zeeland facility, located in Zeeland, Michigan, iscomprised of simple cycle units totaling 307 MW of capacity and a 530 MWcombined cycle facility (837 MW of total capacity). The Zeeland facility isinterconnected with the International Transmission Company, which is a memberof the Midwest Independent Transmission System Operator (“MISO”), and operatedunder the East Central Reliability Coordination Agreement (“ECAR”) which, as ofJanuary 2006, has been merged with the Mid-American Interconnected Network(“MAIN”) and the Mid-Atlantic Area Council (“MAAC”) reliability regions and ispart of ReliabilityFirst, the North American Electric Reliability Council (“NERC”)subregion. ReliabilityFirst is the successor organization to the three NERCregional reliability councils: MAAC, ECAR and MAIN.

We have a tolling agreement for the electrical energyoutput (307 MW, simple cycle) from the Zeeland plant, Units 1A and 1B, whichexpires on May 31, 2006. The tolling agreement provides for the generationowner to provide electric energy and related services using fuel supplied bythe customer or with a pass-through to the customer of actual fuel cost. Wereceive a monthly capacity payment, a variable operating and maintenancepayment on a per megawatt hour (“MWh”) basis and a start-up payment each timethe unit is turned on. Our counterparty provides to the Zeeland plant all thefuel required to operate the contractual portion of the plant. Mirant Zeelandindirectly provides a heat rate and availability guarantee. There are bonus andpenalty provisions in the agreement for availability outside allowable limits.

Mirant Zeeland Phase 2 (530 MW combined cycle output)has a tolling contract for 100% of its output through December 2006. Thetoll is with Mirant Energy Trading, which in turn has an agreement with acounterparty. We receive a monthly capacity payment, variable operations andmaintenance payments on a per MWh basis and a start up payment. There are heatrate and availability guarantees with associated bonuses and penalties forbeing outside of tolerance bands. The fuel required to operate the facilityduring the term of the toll is provided to Mirant Zeeland through Mirant EnergyTrading’s agreement with its counterparty. Mirant Zeeland operates under theMISO market and the ReliabilityFirst subregional reliability council of NERC.

For a discussion of theMISO, see “Regulatory Environment—U.S. Public Utility Regulation” below.

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*West Region*

Our West region facilities, with a total capacity of2,879 MW, are primarily gas fired generating facilities located in Californiaand Texas. Our West region had a combined 2005 capacity factor of 13%.

*California.**  *Our generating facilities in California consist ofthe Pittsburg, Contra Costa and Potrero facilities, which have generationcapacity of 1,311 MW, 674 MW and 362 MW, respectively, for a total capacity of2,347 MW. The Pittsburg and Contra Costa facilities are intermediate facilitiesand both generate electricity by using gas fired steam boilers. They are locatedin Contra Costa County, approximately ten miles apart along the Sacramento/SanJoaquin River. The Potrero facility, located in the City of San Francisco, hasone natural gas fired baseload steam boiler from which it generates electricityand three oil fired peaking distillate fueled combustion turbines.

The majority of our California assets are subject toRMR arrangements with the California Independent System Operator (“CAISO”).These agreements are described further under “Regulatory Environment—U.S.Public Utility Regulation” below. Our California subsidiaries currently havethe largest portfolio of units which operate under RMR arrangements inCalifornia, reflecting that the location of these units makes them key toelectric system reliability. In September 2005, the CAISO Board approvedRMR designations for 2006 that are the same as designations for 2005. PittsburgUnit 7 and Contra Costa Unit 6 are not subject to an RMR arrangement, and thusfunction solely as merchant facilities in the CAISO. Mirant Energy Tradingeither sells the output of Pittsburg Unit 7 and Contra Costa Unit 6 into themarket through bilateral transactions with utilities and other merchantgenerators, or dispatches the units in the CAISO clearing markets.

Pittsburg Unit 7, which has 682 MW of generationcapacity, operated pursuant to a tolling agreement with a third party thatexpired in December 2005. We are currently seeking proposals for a one-,two- or three-year tolling arrangement or resource adequacy capacity sale onboth Pittsburg Unit 7 and Contra Costa Unit 6. If we are unable to enter into anew tolling agreement for Pittsburg Unit 7 on acceptable terms, we may retirethis unit.

*Texas.**  *We operate one facility in Texas, the Bosquefacility, which consists of a gas fired combustion turbine with a correspondingsteam turbine with a capacity of 230 MW that is available to serve baseload andintermediate demand. Additionally, Bosque Units 1 and 2 are gas fired peakingfacilities with a capacity of 151 MW each. We have entered into a tollingagreement that grants the counterparty exclusive rights to the power andancillary services generated by the Bosque facility through December 2006.

Our Bosque facilityoperates in the Electric Reliability Council of Texas (“ERCOT”) market. For adiscussion of ERCOT, see “Regulatory Environment—U.S. Public Utility Regulation”below.

**Regulatory Environment**

***U.S. Public Utility Regulation***

The U.S. electricity industry is subject tocomprehensive regulation at the federal, state and local levels. At the federallevel, the FERC has exclusive jurisdiction under the Federal Power Act oversales of electricity at wholesale and the transmission of electricity in interstatecommerce. Any of our subsidiaries that owns generating facilities selling atwholesale or that markets electricity at wholesale outside of ERCOT is a “publicutility” subject to the FERC’s jurisdiction under the Federal Power Act. Thesesubsidiaries must comply with certain FERC reporting requirements andFERC-approved market rules and are subject to FERC oversight of mergersand acquisitions, the disposition of FERC-jurisdictional facilities, andthe issuance of securities. In addition, under the Natural Gas Act, the FERChas limited jurisdiction over certain sales for resale of natural gas, but doesnot regulate the prices received by our subsidiary that markets natural gas.

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The Energy Policy Act of 2005 (“EPAct 2005”) becamelaw on August 8, 2005, and it contains a wide range of provisionsaddressing many aspects of the electric industry. The EPAct 2005 repealed thePublic Utility Holding Company Act of 1935 (“PUHCA”) and enacted the PublicUtility Holding Company Act of 2005, which imposes on us additional obligationsto maintain books and records unless we qualify for an exemption from theserequirements, which is anticipated. The EPAct 2005 requires the FERC and otheragencies to engage in numerous rulemakings and we are evaluating the potential impactsand opportunities that may result from these rulemakings. The EPAct 2005authorizes the FERC to oversee new Electric Reliability Organizations that willdevelop and enforce national and regional reliability standards. In addition,the EPAct 2005 greatly expands the FERC’s ability to impose criminal and civilpenalties for violations of the Federal Power Act with a specific emphasis onmarket manipulation and market transparency.

The FERC has authorized our subsidiaries thatconstitute public utilities under the Federal Power Act to sell energy andcapacity at wholesale market-based rates and has authorized some of thesesubsidiaries to sell certain ancillary services at wholesale market-basedrates. The majority of the output of the generation facilities owned by oursubsidiaries that constitute public utilities is sold pursuant to thisauthorization, although certain of our facilities sell their output undercost-based RMR agreements, as explained below. The FERC may revoke or limit ourmarket-based rate authority if it determines that we possess market powerin a regional market. The FERC requires that our subsidiaries with market-basedrate authority, as well as those with blanket certificate authorizationpermitting market-based sales of natural gas, adhere to certain market behaviorrules and codes of conduct. If any of our subsidiaries violates the marketbehavior rules or codes of conduct, the FERC may require a disgorgement ofprofits or revoke its market-based rate authority or blanket certificateauthority. If the FERC were to revoke market-based rate authority, ouraffected subsidiary would have to file a cost-based rate schedule for all orsome of its sales of electricity at wholesale. If the FERC revoked the blanketcertificate authority of any of our subsidiaries, it would no longer be able tomake certain sales of natural gas.

The majority of our facilities operate in ISO/RTOregions. In areas where ISOs or RTOs control the regional transmission systems,market participants have expanded access to transmission service. ISOs and RTOsalso may operate real-time and day-ahead energy and ancillary services markets,which are governed by FERC-approved tariffs and market rules. Some RTOs andISOs also operate capacity markets. Changes to the applicable tariffs andmarket rules may be requested by market participants, state regulatoryagencies and the system operator, and such proposed changes, if approved by theFERC, could have an impact on our operations and business plan. Whileparticipation by transmission-owning public utilities in ISOs and RTOshas been and is expected to continue to be voluntary, the majority of suchpublic utilities in New England, New York, theMid-Atlantic, the Midwest and California have joined the existing ISO/RTOfor their respective region.

Our subsidiaries owning generation were exemptwholesale generators under the PUHCA, as amended. With the repeal of the PUHCAand the adoption of the Public Utility Holding Company Act of 2005, the FERChas put in place new regulations effective February 8, 2006, that allow oursubsidiaries owning generation to retain their exempt wholesale generatorstatus.

At the state and local levels, regulatory authoritieshistorically have overseen the distribution and sale of retail electricity tothe ultimate end user, as well as the siting, permitting and construction ofgenerating and transmission facilities. Our existing generation may be subjectto a variety of state and local regulations, including regulations regardingthe environment, health and safety, maintenance, and expansion of generationfacilities. To the extent that a subsidiary sells at the retail level in astate with a retail access program, it may be subject to state certificationrequirements and to bidding rules to provide default service to customerswho choose to remain with their regulated utility distribution companies.

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*Mid-AtlanticRegion.  *Our Mid-Atlantic facilities sell powerinto the markets operated by PJM, which the FERC approved to operate as an ISOin 1997 and as an RTO in 2002. We have access to the PJM transmission systempursuant to PJM’s Open Access Transmission Tariff. PJM operates the PJMInterchange Energy Market, which is the region’s spot market for wholesaleelectricity, provides ancillary services for its transmission customers,performs transmission planning for the region anddispatches generators accordingly. PJMadministers day-ahead and real-time marginal cost clearing price markets andcalculates electricity prices based on a locational marginal pricing model. Alocational marginal pricing model determines a price for energy at each node ina particular zone taking into account the limitations on transmission ofelectricity and losses involved in transmitting energy into the zone, resultingin a higher zonal price when cheaper power cannot be imported from anotherzone. Generation owners in PJM are subject to mitigation, which limits theprices that they may receive under certain specified conditions.

Load serving entities in PJM are required to haveadequate sources of capacity. PJM operates a capacity market whereby loadserving entities can procure their capacity requirements through a system-widesingle clearing price auction. In PJM, all capacity is assumed to beuniversally deliverable, regardless of its location. PJM has greatly expandedits system over the last three years to include Allegheny Power, Commonwealth Edison,American Electric Power, Inc. (“AEP”), Duquesne Light, Dayton Power &Light (“DP&L”) and Dominion-Virginia Power. As a result, capacity priceshave significantly declined. The PJM expansions have resulted in an apparentsystem-wide surplus of capacity, despite the fact that certain regions inPJM-Mid-Atlantic will need capacity additions within the next few years.

On August 31, 2005, PJM filed its ReliabilityPricing Model (“RPM”) with the FERC. This proposal is intended to replace itscurrent capacity market rules. The new RPM proposal would provide forestablishment of locational deliverability zones for capacity phased in over aseveral year period beginning on June 1, 2006. If ultimately approved bythe FERC in a form not materially different from what was filed, the new RPMwould result in increased opportunities for generators to receive more revenuesfor their capacity. However, on November 5, 2005, PJM proposed to delaythe effective date of the RPM until June 1, 2007, and it is impossible to predictwhether this or a similar proposal will be adopted.

In addition, PJM and the MISO have been directed bythe FERC to establish a common and seamless market, an effort that is largelydependent upon the MISO’s ability first to establish and operate its markets.The development of a joint market is contingent on the approval of the internalcosts to both entities to develop and operate the infrastructure necessary forjoint operations. It is unclear at this time if either the respective entitiesor the FERC will approve such costs to achieve a common and seamless market.

*NortheastRegion.  *Our New York plants participate in amarket controlled by the NYISO, which replaced the New York Power Pool. TheNYISO provides statewide transmission service under a single tariff andinterfaces with neighboring market control areas. To account for transmissioncongestion and losses, the NYISO calculates energy prices using a locationalmarginal pricing model that is similar to that used in PJM and ISO-NE. TheNYISO also administers a spot market for energy, as well as markets forinstalled capacity and services that are ancillary to transmission service,such as operating reserves and regulation service (which balances resourceswith load). The NYISO employs an Automated Mitigation Procedure (“AMP”) in itsday-ahead market that automatically caps energy bids when certain establishedbid screens indicate a bidder may have market power.****In response to a January 14, 2005, order of the U.S.Court of Appeals for the Washington, D.C. Circuit, in the spring of 2005 theNYISO discontinued use of the AMP in the upstate region known as ‘‘Rest ofState.’’ In addition, the NYISO’s locational capacity market rules use ademand curve mechanism to determine for every month the required amount ofinstalled capacity as well as installed capacity prices to be paid for three locationalzones: New York City, Long Island and Rest of State. Our facilities operateoutside of New York City and Long Island. On April 21, 2005, the FERCissued an order accepting the NYISO’s demand curves for capability years 

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2005/2006, 2006/2007 and 2007/2008with minor modifications to the NYISO’s proposal. It is possible that the newdemand curves may result in increased prices within the NYISO for capacity.

Our New England plants participatein a market administered by ISO-NE. Mirant Energy Trading is a member of  NEPOOL, which is a voluntary association ofelectric utilities and other market participants in Connecticut, Maine,Massachusetts, New Hampshire, Rhode Island and Vermont, and which functions asan advisory organization to ISO-NE. The FERC approved ISO-NE as the RTO for theNew England region effective on February 1, 2005, making ISO-NEresponsible for market rule filings at the FERC, in addition to itsresponsibilities for the operation of transmission systems and administrationand settlement of the wholesale electric energy, capacity and ancillaryservices markets. ISO-NE utilizes a locational marginal pricing model, with aprice mitigation method similar to the NYISO’s AMP (discussed above), althoughit is implemented via manual processes rather than the automated processemployed in New York. In 2004, the FERC approved a locational installedcapacity market for ISO-NE (the ‘‘LICAP proposal’’) based on the demand curveconcept used by the NYISO to be implemented in January 2006. The LICAP proposalincluded demand curves, which are administrative mechanisms used to establishelectricity generation capacity prices. A hearing on the demand curveparameters was held in February and March 2005 and an initialdecision was issued by the presiding administrative law judge that found infavor of many of the suppliers’ issues in the hearing. A subsequent FERC orderissued on October 21, 2005, pushed back the LICAP implementation date tono sooner than October 1, 2006, and put in place procedures to pursue asettlement on alternatives to the LICAP mechanism. On March 6, 2006, a settlement inprinciple was filed with FERC that provides for a capacity market with atransition period from December 2006 through June 2010 with fixedrate payments to generators and a Forward Capacity Market beginning in 2010.The settling parties request FERC approval of the settlement by June 30,2006. We expect that the settlement will be opposed by some parties to theoriginal LICAP proceeding. If approved, without modification, the settlementwill result in increased revenue opportunities for Mirant Canal and MirantKendall for the December 2006 to June 2010 time period. We cannot,however, predict if the settlement will be approved by the FERC withoutmodification nor can we predict whether the FERC will implement the settlementdates as requested.

*Mid-ContinentRegion.**  *OurMid-Continent plant is located in the Midwestmarket and participates in a market administered by the MISO. The MISOcommenced administering energy markets similar to those operated by PJM in thespring of 2005. The MISO uses locational marginal pricing for energy. The MISOproposes to implement a permanent solution to resource adequacy by June 1,2007, but has not yet identified a specific capacity market design or when itwill file a tariff with the FERC. The MISO also implements mitigation rules similarto those of the NYISO, without an automatic mitigation mechanism.

*WestRegion.**  *Ourgeneration facilities in the West are located in the Western Interconnectionand ERCOT market in Texas. Our California facilities are located in the CAISO’scontrol area. The CAISO schedules transmission transactions, arranges fornecessary ancillary services and administers a real-time balancing energymarket. Most sales in California are pursuant to bilateral contracts, but asignificant percentage is sold in the real-time market. The CAISO does notoperate a forward market like those described for PJM and other Eastern ISOmarkets, nor does it currently operate a capacity market.

The CAISO has proposed changes to its market design tomore closely mirror the Eastern ISO markets. The market redesign has beendelayed several times, with full implementation now expected in 2007 or 2008.The California Public Utilities Commission (“CPUC”) has taken the lead role forestablishing capacity requirements in California and has ordered California’sload serving entities to demonstrate, beginning in the summer of 2006, thatthey have acquired sufficient capacity to serve their forecast retail load plusa specified reserve margin. Any proposal for a capacity market in California issubject to filing with and approval by the FERC, and at this time, the CAISOhas not proposed a capacity market mechanism in its market redesign. The CPUChas also taken a role in developing recommended options with respect to awholesale capacity market in conjunction with the CAISO. We cannot at this time

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predict the outcome or theresult of the CPUC proceeding or the timing or development of a wholesalecapacity market by either the CPUC or the CAISO.

The majority of our assets in California are subjectto RMR arrangements with the CAISO. These agreements require certain of ourfacilities, under certain conditions and at the CAISO’s request, to operate atspecified levels in order to support grid reliability. Under the RMRarrangements, we recover through fixed charges either a portion (RMR ContractCondition 1) or all (RMR Contract Condition 2) of the annual fixed revenuerequirement of the generation assets as approved by the FERC (the “AnnualRequirement”). Our California generation facilities operating under RMRContract Condition 1 depend on revenue from sales of the output of the plantsat market prices to recover the portion of the plant’s fixed costs notrecovered through RMR payments.

Our subsidiaries owning facilities subject to the RMRarrangements have entered into two power purchase agreements (“PPAs”) with Pacific Gas & Electric (“PG&E”)that allow PG&E to dispatch and purchase the power output of all units ofthose generation facilities designated by the CAISO as RMR units under the RMRarrangements. The first agreement was in effect during 2005 and the secondagreement extends from 2006 through 2012. Under those agreements, those unitsdesignated as RMR by the CAISO are designated as RMR Contract Condition 1, butduring 2005 through 2008, PG&E is paying us charges equivalent to the rateswe charged during 2004 when the units were designated RMR Contract Condition 2,reduced on an aggregate basis from those 2004 rates by $5 million. After 2008,we will file annually for FERC approval of the Annual Requirement, which, onceapproved by the FERC, will set the rates to be charged.

The CAISO imposed a $400 per MWh cap, effective onJanuary 1, 2006, on prices for energy and has implemented an AMP similarto that used by the NYISO. In addition, owners of non-hydroelectric generationin California, including certain of our facilities, must offer to keep theirgeneration on line and stand ready to offer power into the CAISO’s spot marketsif the output is not under contract or scheduled for delivery within the hour,unless granted a waiver by the CAISO (the ‘‘must-offer requirement’’). Thepractical effect of this rule is to obtain operating reserves withoutpaying for them, and to release excess supply energy into the market, thusdepressing prices. On August 26, 2005, the Independent Energy Producers, atrade association, filed a complaint at the FERC, requesting that the FERCrequire the CAISO to implement a Reliability Capacity Services Tariff(‘‘RCST’’) that would pay generators for the capacity obtained pursuant to themust-offer requirement. If granted by the FERC, the new RCST may result inincreased capacity revenue opportunities for generators.

The CPUC has issued a series of orders purporting torequire exempt wholesale generators and other power plant owners to comply withdetailed operation, maintenance and logbook standards for electricitygenerating facilities. In its orders, the CPUC has stated its intent toimplement and enforce these detailed standards so as to maintain and protectthe public health and safety of California residents and businesses, to ensurethat electric generating facilities are effectively and appropriatelymaintained and efficiently operated, and to ensure electrical servicereliability and adequacy. The CPUC has adopted detailed reporting requirementsfor the standards, and conducts frequent on-site spot inspections and morecomprehensive facility audits to evaluate compliance. Some standards areintended to ensure that units are maintained in a state of readiness so as tobe available to operate if requested by a control area operator, while othersprovide procedures for changing a unit’s long-term status. The CPUC’s effortsto implement and enforce the operation, maintenance and logbook standards couldinterfere with our future ability to make economic business decisions regardingour units, including decisions regarding unit retirements, and could have amaterial adverse impact on our business activities in California.

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Our Texas plants participate in a market administeredby ERCOT, which manages a major portion of the state’s electric power grid.ERCOT oversees competitive wholesale and retail markets resulting fromelectricity restructuring in Texas and protects the overall reliability of theERCOT grid. ERCOT, the only ISO that manages both wholesale and retail marketoperations, is regulated by the Public Utility Commission of Texas (“PUCT”).The PUCT conducts market monitoring within ERCOT. Price mitigation measures inERCOT include a $1,000 per MWh price cap and RMR-type contracts for congestedareas. The PUCT has recently conducted hearings on wholesale market designissues that will focus on adding a congestion management mechanism based onlocational pricing, using nodal locational pricing with day-ahead and real-timemarkets. Presently, we cannot estimate when the enhancements will be completedand implemented.

***Environmental Regulation***

Our business is subject to extensive environmentalregulation by federal, state and local authorities. This requires us to complywith applicable laws and regulations, and to obtain and comply with the termsof government issued operating permits. Our costs of complying withenvironmental laws, regulations and permits are substantial. For example, weestimate that our capital expenditures for environmental compliance will beapproximately $300 million for 2006 and will be $1 billion to $1.5 billion from2006 through 2011. Our potential capital expenditures for environmentalregulation are difficult to estimate because we cannot now assess whatregulations may be applicable or what costs might be associated with certainregulations. Our capital expenditures will be materially impacted if the Stateof Maryland passes legislation or imposes regulations that increase beyondapplicable federal law the restrictions on emissions of sulfur dioxide (“SO2”), nitrogen oxide (“NOx”) andmercury, or imposes restrictions on emissions of carbon dioxide (“CO2”). Thislegislation or regulation, or similar legislation or regulations in otherstates or by the federal government, may render some of our units uneconomic.

*Airemissions regulations.**  *Ourmost significant environmental requirements generally fall under the Clean AirAct and similar state laws. Under the Clean Air Act, we are required to complywith a broad range of mandates concerning air emissions, operating practicesand pollution control equipment. Several of our facilities are located in ornear metropolitan areas, such as New York City, Boston, San Francisco andWashington, D.C., which are classified by the EPA as not achieving certainNAAQS. As a result of the NAAQS classification of these areas, our operationsare subject to more stringent air pollution requirements, including, in some cases,further emissions reductions. In the future, we anticipate increased regulationof generation facilities under the Clean Air Act and applicable state laws andregulations concerning air quality. Significant air regulatory programs towhich we are subject include those described below.

*Acidrain program.**  *The EPA promulgated regulations that establish capand trade programs for SO2 emissions(the ‘‘Acid Rain Program’’) from electric generating units in the UnitedStates. Under this system, the Acid Rain Program set a permanent ceiling (orcap) of 8.95 million allowances for total annual SO2 allowance allocations to utilities. Each allowance permits aunit to emit one ton of SO2 duringor after a specified year. Affected utility units were allocated allowancesbased on their historic fuel consumption and a specific emissions rate.Allowances may be bought, sold or banked. Some of our facilities have surplusallowances, and some are required to purchase additional SO2 allowances to cover their emissionsand maintain compliance. The costs of SO2allowances have increased substantially in recent years. Prior to 2004,prices generally ranged between $100 and $200 per ton. Prices rose fromapproximately $200 per ton to approximately $800 per ton during 2004 and toapproximately $1,600 per ton in 2005. We expect to be a net purchaser ofallowances for 2006. Many factors can affect the price of SO2 allowances, and we cannot be certainthat the price of allowances will not increase substantially from currenthistorical highs in future years. Depending on the actual price and number ofSO2 allowances we need to buy,such costs may materially impact us. This program and other regulationsrequiring further reductions in SO2 emissions,such as the Clean Air Interstate Rule (“CAIR”), may result in our decidingto further reduce emissions at 

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some of our facilitiesthrough new control technology. The cost of additional pollution controltechnology could be significant; however, it could be partially offset by theavoided cost of purchasing SO2 allowances. For additional discussion of SO2 control technology see the discussionof the CAIR below.

*NOxSIP call.**  *New NOx regulations will require a combination ofcapital expenditures and the purchase of emissions allowances in the future.The EPA has promulgated regulations that established emissions cap and tradeprograms for NOx emissions fromelectric generating units in most of the eastern states (the “NOx SIP Call”).These programs were implemented beginning May 2003 in the Northeast and May 2004in the rest of the Eastern United States. Under these regulations, a facilityreceives an allocation of NOx emissionsallowances. If a facility exceeds its allocated allowances, the facility mustpurchase additional allowances. Some of our facilities in these states havebeen required to purchase NOx allowancesto cover emissions to maintain compliance. The cost of allowances willfluctuate in future years, and depending on the actual price and number of NOx allowances we need to buy, such costscould materially affect our operations. As a result, we may decide to reduce NOx emissions through control technologyin addition to what is already installed or planned. The cost of additionalpollution control technology could be significant; however, it may be partiallyoffset by the avoided cost of purchasing NOx allowances to operate the facility.

*CAIR.*   In March 2005,the EPA issued the CAIR, which establishes in the Eastern United States a morestringent SO2 cap andallowance-trading program and a year round NOx cap and allowance-trading program applicable to generationfacilities. These cap and trade programs would be implemented in two phases,with the first phase going into effect in 2010 and more stringent caps goinginto 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 purchaseadditional emissions allowances, at significant cost. Currently, we areplanning to install pollution control equipment at our facilities to address,in part, our requirements under the first phase of the CAIR. The costs of thatequipment are included in our estimate of anticipated environmental capitalexpenditures from 2006 through 2011. However, since the determination of howmuch pollution control equipment to install is based upon factors such as thecost of emissions allowances and the operational demands on our generationfacilities, our plans may change significantly over the coming years.

*CAMR.**  *The EPApromulgated the Clean Air Mercury Rule (“CAMR”) on March 15, 2005,which utilizes a market-based cap and trade approach under Section 111 ofthe Clean Air Act. It requires emissions reductions in two phases, with thefirst phase going into effect in 2010 and the more stringent cap going intoeffect in 2018. It is our view that the pollution control equipment we intendto install to comply with the CAIR should adequately reduce mercury emissionsto the levels required by 2010. We cannot currently estimate the costs tocomply with the reductions required by 2018, but they may be material. The CAMRhas faced considerable political and legal opposition, as a result of which theEPA in October 2005 issued a notice of proposed rulemaking to reconsidercertain aspects of the CAMR. The CAMR is currently being challenged in federalcourt. Those challenges may lead to amendments to the CAMR or passage ofdifferent mercury control legislation, which could require stricter control ofmercury emissions and/or more expensive control equipment.

*NSRenforcement initiative.**  *In 1999, the Department ofJustice (“DOJ”) on behalf of the EPA commenced enforcement actions against anumber of companies in the power generation industry for alleged violations ofthe NSR regulations, which require permitting and impose other requirements forcertain maintenance, repairs and replacement work on facilities. Theseenforcement actions can result in a facility owner having obligations to, amongother things, install emissions controls at significant costs. Theseenforcement actions were broadly challenged by the industry in the courts andthe EPA. We have complied with the NSR regulations as they have beeninterpreted in final, binding decisions. In 2001 the EPA requested informationconcerning some of our facilities covering a time period that predates ourownership or leasing. The challenges to the new interpretation of the NSRregulations may affect the 

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enforcement actions, butthere is no assurance that there will not be further requests or enforcementproceedings that can materially affect our plants.

*Stateair regulations.**  *Various states where we do business also have otherair quality laws and regulations with increasingly stringent limitations andrequirements that will become applicable in future years to our facilities andoperations. We expect to incur additional compliance costs as a result of theseadditional state requirements, which could include significant expenditures onemissions controls or have other impacts on operations.

For example, the Commonwealth of Massachusetts hasfinalized regulations to further reduce NOx and SO2 emissionsfrom certain generation facilities and to regulate CO2 and mercury emissionsfor the first time. Mercury emissions reductions will be required exclusivelyfrom coal fired facilities. Portions of these regulations, which become effectivein the 2005-2008 time frame, will apply to our oil fired Canal facilityin the state, will increase our operating costs and will likely necessitate theinstallation of additional emissions control technology.

Another example of state regulation that affects ourgeneration facilities arises in the San Francisco Bay area, where we owngeneration facilities. Regional NOx emissions standards have become increasingly stringent on aspecified schedule over a several year period, culminating in 2005. We continuedto apply our NOx implementationplan for these facilities, which included the installation of selectivecatalytic reduction (“SCR”) emissions control equipment at our Potrero Unit 3facility and the partial curtailment of two of our higher NOx emitting units.

In 2000, the State of New York issued a notice ofviolation (“NOV”) to the previous owner of our Lovett facility alleging NSRviolations associated with the operation of that facility prior to itsacquisition by us. On June 11, 2003, Mirant New York, Inc. (“MirantNew York”), Mirant Lovett and the State of New York entered into the 2003Consent Decree. The 2003 Consent Decree was approved by the Bankruptcy Court onOctober 15, 2003. Under the 2003 Consent Decree, Mirant Lovett has threeoptions: (1) install emissions controls on Lovett’s two coal fired units; (2) shutdown one unit and convert one unit to natural gas; or (3) shut down bothcoal burning units in 2007 and 2008. If Mirant Lovett elects to installemissions controls on its two coal fired units by 2007 through 2008, it mustinstall: (1) emissions controls consisting of SCR technology to reduce NOx emissions; (2) alkaline in-ductinjection technology to reduce SO2 emissions;and (3) a baghouse. Additionally, in 2003, the State of New York finalizedair regulations that significantly reduced allowances for NOx and SO2 emissions from generation facilities through a state emissionscap and trade program, which will become effective during the 2005-2008timeframe. We have recognized that the 2003 Consent Decree and the newregulations, taken together with property taxes based on assessed values forour New York facilities that are far in excess of actual values and with NYISO rules thatdo not take into consideration the importance of the Mirant Lovett facility tothe reliable supply of electricity, would have rendered the continuingoperation of the Mirant Lovett facility uneconomic. It is therefore our currentplan to retire the Lovett generating facility by 2008. In an effort to keep theplant operating, we are trying to negotiate agreements to reduce property taxesand to compensate Mirant Lovett for its contribution to the reliability of theelectricity system, which will enable us to agree with the State of New York tomake capital expenditures on environmental controls in excess of $200 million,significantly more than contemplated by the 2003 Consent Decree. The 2003Consent Decree required Mirant Lovett to notify the state of its selectedoption by August 1, 2004, which date was extended by the State of New Yorkto August 1, 2005, with subsequent extensions to February 15, 2006.On February 15, 2006, Mirant Lovett submitted a proposal to the State ofNew York for the installation of certain environmental controls in excess ofthose in the 2003 Consent Decree conditioned on execution and approval ofacceptable property tax and reliability agreements. Pursuant to the BankruptcyCourt’s order approving the 2003 Consent Decree, Mirant Lovett may not enterinto a binding agreement to construct the environmental controls or to elect ashutdown of the facility without first obtaining the approval of the BankruptcyCourt.

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*Climatechange.**  *Concern over climate change deemed by many to beinduced by rising levels of greenhouse gases in the atmosphere has led tosignificant legislative and regulatory efforts to limit greenhouse gasemissions.

In 1998, the United States became a signatory to theKyoto Protocol of the United Nations Framework Convention on Climate Change.The Kyoto Protocol, which became effective in February 2005 after Russia’sratification in November 2004, calls for developed nations to reduce theiremissions of greenhouse gases to 5% below 1990 levels by 2012. CO2, which is amajor byproduct of the combustion of fossil fuel, is a greenhouse gas thatwould be regulated under the Kyoto Protocol. The United States Senate indicatedthat it would not enact the Kyoto Protocol, and in 2002 President Bushconfirmed that the United States would not enter into the Kyoto Protocol.Instead, the President indicated that the United States would support voluntarymeasures for reducing greenhouse gases and technologies that would use ordispose of CO2 effectively and economically. As the Kyoto Protocol becomeseffective in other countries, there is increasing pressure for sources in theUnited States to be subject to mandatory restrictions on CO2 emissions. In thelast year, the United States Congress has considered bills that would regulatedomestic greenhouse gas emissions, but such bills have not received sufficientCongressional approval to date to become law. If the United States ultimatelyratifies the Kyoto Protocol and/or if the United States Congress or individualstates or groups of states in which we operate ultimately pass legislationregulating the emissions of greenhouse gases (see discussion of the RegionalGreenhouse Gas Initiative below), any resulting limitations on generationfacility CO2 emissions could have a material adverse impact on all fossil fuelfired generation facilities (particularly coal fired facilities), includingours.

On December 20, 2005, seven states in theNortheast agreed to go forward with the implementation of a cooperative knownas the Regional Greenhouse Gas Initiative (“RGGI”). This is the firstmulti-state regional initiative that uses a regional cap and trade program toreduce CO2 emissions from power plants of 25 MW or greater. The program aims tostabilize CO2 emissions to current levels from 2009 to 2015. This will befollowed by a 10% reduction in emissions by 2019. This initiative envisionsparticipating states executing a memorandum of understanding and thenpromulgating implementing regulations based on the RGGI template. Therecommended allocation scheme calls for allocation of 20% of allowances to apublic benefit purpose and 5% to a regional strategic carbon fund, therebyfurther reducing allowances available to affected facilities. In the future,the RGGI may include other sources of greenhouse gas emissions and greenhousegases other than CO2. If the RGGI results in mandatory regulations in stateswhere we have generating units, our costs of implementation may be material.New York, where we have generating units, is a participant in the RGGI.Massachusetts, where we also have generating units, originally agreed toparticipate but later withdrew.

On June 1, 2005, the Governor of Californiaestablished greenhouse gas reductiontargets for California, which would by 2010, reduce statewide greenhouse gas emissions to 2000 emissionslevels; by 2020, reduce statewide greenhousegas emissions to 1990 emissions levels; and by 2050, reduce statewide greenhouse gas emissions to 80% below 1990levels. Implementing strategies to reach these targets will be theresponsibility of a Climate Action Team, an interagency team established by theGovernor. The team is led by the California EPA and is composed of high levelrepresentatives from key state agencies. This team will report to the Governorand the Legislature in early 2006.

*ProposedMaryland clean power rule and other air legislative and regulatorydevelopments.**  *In addition to the implementation of existingrequirements, there are additional environmental requirements underconsideration by the federal and various state legislatures and environmentalregulatory bodies. Maryland’s governor announced in November 2005 that heintends to propose a Maryland Clean Power Rule, that would require deepreductions in NOx emissions (69%reduction) by the year 2009, and in SO2 emissions(85% reduction) and mercury emissions (70% reduction) by the year 2010, at sixMaryland coal fired generation facilities, including our Chalk Point, Dickersonand Morgantown facilities. If the rulemaking proceeds according to the timingindicated by the Governor’s office, that regulation would 

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become effective in thesummer of 2006. Although we have not fully evaluated the impacts of theGovernor’s proposed rule as announced, if adopted, it would limit ourability to acquire emissions allowances for use associated with our Marylandpower facilities, and would require us to consider the economic impact ofincreasing substantially our capital expenditures from 2006 through 2010, whichmay have a material impact on us. The Governor’s rule, which does not requirelegislative approval, was approved by the Air Quality Control Advisory Councilon March 13, 2006, and will be the subject of regional public hearings inthe early spring of 2006. Maryland hopes to adopt the rule during thesummer of 2006.

In addition to the proposed state regulations, theMaryland Legislature is in the process of moving the Healthy Air Act in boththe Senate (“SB 154”) and in the House (“HB 189”). The House and Senate billswere introduced simultaneously on January 19, 2006. The legislation issimilar to the Maryland Clean Power Rule; however, it would require deeperreductions of NOx, SO2, mercury and CO2. On March 20, 2006, the Senatepassed their version of the bill which requires reductions of NOx in two phasesbeginning in 2009 and 2012 and SO2 in 2010 and 2015. It also requiresreductions of mercury emissions by the years 2010 and 2012. More importantly,unlike the Maryland Clean Power Rule, the legislation also addresses CO2 byrequiring the State to join the Northeast Regional Greenhouse Gas Initiative (“RGGI”).RGGI will require mandatory reductions of CO2 emissions beginning in 2009 witha second phase in 2019. The House bill is likely to be acted upon by March 31,2006. If passed in the House, the two bills would be debated and combined intoone to be sent to the Governor for his approval. The reductions would be requiredat all three of our Maryland coal fired generation facilities. There iscurrently no technology that would meet the proposed requirements for mercuryand CO2, and we would have to consider running the facilities less in order tocomply.

In addition to the state activities, at the federallevel, the Bush Administration has submitted to Congress Clean Air Actmulti-emissions reform legislation, which would promulgate a new emissions capand trade program for NOx,SO2 and mercury emissions fromgeneration facilities. This legislation would require generation facilities toreduce overall emissions of these pollutants by approximately 50-75%phased in during the 2008-2018 timeframe, which is similar to the typesof overall reductions required under CAIR and CAMR. More stringentmulti-emissions reform legislation also has been proposed in Congress by somelawmakers. If enacted as proposed, some of this legislation may materiallyimpact us.

The EPA and the states are also in the process ofimplementing new, more stringent ozone and particulate matter ambient airquality standards and the EPA’s rules addressing regional haze visibilityissues. The full implementation of any of these rules may result infurther emissions reduction requirements for some of our facilities.

*Waterregulations.**  *We are required under the Federal Water PollutionControl Act (“Clean Water Act”) to comply with effluent and intakerequirements, technological controls requirements and operating practices. Ourwastewater discharges are subject to permitting under the Clean Water Act, andour permits under the Clean Water Act are subject to review every five years.As with air quality regulations, federal and state water regulations areexpected to increase and impose additional and more stringent requirements orlimitations in the future. It is our view that the regulations  promulgated by the EPA to implement Section 316(b) ofthe Clean Water Act, will require us to incur substantial expenses in futureyears. These regulations address the need to require the best technologyavailable for cooling water intake structures to minimize adverse effects onfish and shellfish. These regulations set performance standards for allexisting large power plants and are intended to reduce the losses of aquatic organismsinadvertently pulled into a power plant’s circulating water system. Potentialcompliance alternatives include using existing technologies, selectingadditional fish protection technologies and using restoration measures. Overthe next few years, our generation facilities subject to this cooling waterintake regulation (Bowline, Canal, Kendall, Pittsburg, Contra Costa, Potrero,Chalk Point, Morgantown, Potomac River and Dickerson) will be evaluating andimplementing the requirements of the 316 (b) regulation by completing 

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impingement andentrainment studies, evaluating technologies, operational measures, andrestoration measures. The cost of performing the studies and capitalexpenditures to install barriers or control devices or to implement other protectivemeasures at three of our facilities is expected to approximate $10 million from2006 through 2011. The cost of installing protection technologies may bematerial.

In early 2006, the U.S. Department of the Interior,through its Fish and Wildlife Services division (the “FWS”), sent a letter tothe U.S. Army Corps of Engineers requesting that it reinitiate formalconsultation on the biological opinion that permits Mirant Delta, LLC (“MirantDelta”) to use and recycle water from the San Joaquin river for its operationof the Pittsburg and Contra Costa power plants. The formal consultation processexplores the environmental impacts of Mirant Delta’s water usage, including theimpacts on certain species of fish in the river, and then provides directivesregarding the manner in which Mirant Delta may utilize river water for coolingin the plants’ operations. It is our view that Mirant Delta is operating incompliance with its water usage permits and that this reopening of the formalconsultation process is improper. Mirant Delta responded to the FWS, assertingthat it has implemented all investigative and operational measures prescribedby the FWS to reduce the impact of its water usage on the endangered species inthe San Joaquin River, and it is currently waiting for a response from the FWSto this communication.

*Wastes,hazardous materials and contamination.**  *Our facilitiesare subject to several waste management laws and regulations. The ResourceConservation and Recovery Act of 1976 set forth comprehensive requirements forhandling of solid and hazardous wastes. The generation of electricity producesnon-hazardous and hazardous materials, and we incur substantial costs to storeand dispose of waste materials from these facilities. The EPA may develop newregulations that impose additional requirements on facilities that store ordispose of fossil fuel combustion materials, including types of coal ash. Ifso, we may be required to change the current waste management practices at somefacilities and incur additional costs for increased waste managementrequirements.

Additionally, the FederalComprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”or “Superfund”) establishes a framework for dealing with the cleanup ofcontaminated sites. Many states have enacted similar state superfund statutesas well as other laws imposing obligations to investigate and clean upcontamination. Areas of soil and groundwater contamination are known to existat our Pittsburg, Contra Costa and Potrero facilities. Prior to our acquisitionof those facilities from PG&E in 1998, PG&E conducted soil and groundwaterinvestigations at those facilities which revealed significant contamination.The consultants conducting the investigation estimated the aggregate cleanupcosts at those facilities could be as much as $60 million. Pursuant to theterms of the Purchase and Sale Agreement with PG&E, PG&E hasresponsibility for the containment or capping of all soil and groundwatercontamination at the Potrero generating facility and the disposition of up to60,000 cubic yards of contaminated soil at the Potrero generating facility andto remediate any groundwater or solid contamination identified by PG&E atthe Pittsburg and Contra Costa generating facilities. To date, we haverequested that PG&E dispose of 807 cubic yards of contaminated soil at thePotrero generating facility and they have performed such disposal. We are notaware of soil or groundwater conditions that are not covered by third partyagreements or insurance policies for which we expect our remediation costs tobe material.

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**Employees**

AtDecember 31, 2005, we employed through contracts with Mirant Services, LLC(“Mirant Services”), a direct subsidiary of Mirant, approximately 1,290 people,of whom approximately 1,180 were employed at our power plants. Approximately74% of the employees at our power plants were represented by the followingunions:

·       UtilityWorker’s Union of America, A.F.L.-C.I.O., Local #369 in Cambridge,Massachusetts. The current collective bargaining agreement expires onFebruary 28, 2009.

·       UtilityWorker’s Union of America, A.F.L.-C.I.O., Local #480 in Sandwich,Massachusetts. The current collective bargaining agreement expires onMay 31, 2006.

·       LocalUnion 503, International Brotherhood of Electrical Workers (“I.B.E.W.”) in NewYork. The current collective bargaining agreement expires on June 1, 2008.

·       LocalUnion 1900, I.B.E.W. in Maryland and Virginia. The current collectivebargaining agreement expires on June 1, 2010.

·       LocalUnion 1245, I.B.E.W. in California. The current collective bargaining agreementexpires on October 31, 2008.

·       UnitedSteel Workers Local 12502 in Michigan. The current collective bargainingagreement expires on January 1, 2007.

When we enter into andconduct labor negotiations, we engage in contingency planning to mitigate andreduce the risk of disruption, and ensure continuation of our generationactivities to the maximum extent possible in the event of an adverse collectiveaction by the union with whom we are negotiating.

**Item 1A.****                RiskFactors**

The following are factorsthat could affect our future performance:

***Our revenues are unpredictable because many of ourfacilities operate without long-term power purchase agreements, and ourrevenues and results of operations depend on market and competitive forces thatare beyond our control.***

We sell capacity, energy and ancillary services frommany of our generating facilities into competitive power markets or on ashort-term fixed price basis through power sales agreements. We are notguaranteed recovery of our costs or any return on our capital investmentsthrough mandated rates. The market for wholesale electric energy and energyservices reflects various market conditions beyond our control, including thebalance of supply and demand, the marginal and long run costs incurred by our competitorsand the impact of market regulation. The price for which we can sell our outputmay fluctuate on a day-to-day basis. The markets in which we compete remainsubject to one or more forms of regulation that limit our ability to raiseprices during periods of shortage to the degree that would occur in a fullyderegulated market, limiting our ability to recover costs and an adequatereturn on our investment.

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

·       thefailure of market regulators to develop efficient mechanisms to compensatemerchant generators for the value of providing capacity needed to meet demand;

·       actionsby regulators, ISOs, RTOs and other bodies that may prevent capacity and energyprices from rising to the level sufficient for recovery of our costs, ourinvestment and an adequate return on our investment;

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·       theability of wholesale purchasers of power to make timely payment for energy orcapacity, which may be adversely impacted by factors such as retail rate caps,refusal by regulators to allow utilities to fully recover their wholesale powercosts and investments through rates, catastrophic losses, and losses frominvestments in unregulated businesses;

·       thefact that increases in prevailing market prices for fuel oil, coal, natural gasand emissions allowances may not be reflected in increased prices we receivefor sales of energy;

·       increasesin supplies due to actions of our current competitors or new market entrants,including the development of new generating facilities that may be able toproduce electricity less expensively than our generating facilities, andimprovements in transmission that allow additional supply to reach our markets;

·       thecompetitive advantages of certain competitors including continued operation ofolder power plants in strategic locations after recovery of historic capitalcosts from ratepayers;

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

·       regulatorypolicies of state agencies which affect the willingness of our customers toenter into long-term contracts generally, and contracts for capacity inparticular;

·       weatherconditions that depress demand or increase the supply of hydro power; and

·       changesin the rate of growth in electricity usage as a result of such factors asregional economic conditions and implementation of conservation programs.

In addition, unlike mostother commodities, electric energy can only be stored on a very limited basisand generally must be produced at the time of use. As a result, the wholesalepower markets are subject to substantial price fluctuations over relativelyshort periods of time and can be unpredictable.

***Changes in commodity prices maynegatively impact our financial results by increasing the cost of producingpower or lowering the price at which we are able to sell our power, andwe may be unsuccessful at managing this risk.***

Our generation business is subject to changes in powerprices and fuel costs, which may impact our financial results and financialposition by increasing the cost of producing power and decreasing the amountswe receive from the sale of power. In addition, actual power prices and fuelcosts may differ from our expectations.

Mirant Energy Trading engages in asset hedgingactivities related to sales of electricity and purchases of fuel. The incomeand losses from these activities are recorded as generation revenues and fuelcosts. Mirant Energy Trading may use forward contracts and derivative financialinstruments to manage market risk and exposure to volatility in electricity,coal, natural gas, emissions and oil prices. We cannot provide assurance thatthese strategies will be successful in managing our price risks, or that theywill not result in net losses to us as a result of future volatility inelectricity and fuel markets.

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

Additionally, we expect tohave an open position in the market, within our established guidelines,resulting from the management of our portfolio. To the extent open positionsexist, fluctuating commodity prices can impact financial results and financialposition, either favorably or unfavorably. Furthermore, the risk managementprocedures we have in place may not always be followed or may not always workas 

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planned.As a result of these and other factors, we cannot predict the impact that riskmanagement decisions may have on our business, operating results or financialposition. Although management devotes a considerable amount of attention tothese issues, their outcome is uncertain.

***We are exposed to the risk of fuel and fueltransportation cost increases and volatility and interruption in fuel supplybecause our facilities generally do not have long-term agreements for naturalgas, coal and oil fuel supply.***

Although we attempt topurchase fuel based on our known fuel requirements, we still face the risks ofsupply interruptions and fuel price volatility. Our cost of fuel may notreflect changes in energy and fuel prices in part because we must pre-purchaseinventories of coal and oil for reliability and dispatch requirements, and thusthe price of fuel may have been determined at an earlier date than the price ofenergy generated from it. The price we can obtain from the sale of energy may notrise 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. Thevolatility of fuel prices could adversely affect our financial results andoperations.

***Some of our generation facilities depend on only oneor a few customers or suppliers. These parties, as well as other parties withwhom we have contracts, may fail to perform their obligations, or may terminatetheir existing agreements, which may result in a default on project debt or aloss in revenues and may require us to institute legal proceedings to enforcethe relevant agreements.***

Several of our power production facilities depend on asingle customer or a few customers to purchase most or all of the facility’soutput or on a single supplier or a few suppliers to provide fuel, water andother services required for the operation of the facility. The sale andprocurement agreements for these facilities may also provide support for anyproject debt used to finance the related facilities. The failure of anysupplier or customer to fulfill its contractual obligations to the facilitycould have a material adverse effect on such facility’s financial results. Thefinancial performance of these facilities is dependent on the continuedperformance by customers and suppliers of their obligations under theirlong-term agreements.

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

***Operation of our generation facilities involves risksthat may have a material adverse impact on our cash flows and results ofoperations.***

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

·       theoutput and efficiency levels at which those generation facilities perform;

·       interruptionsin fuel supply;

·       disruptionsin the delivery of electricity;

·       adversezoning;

·       breakdownsor equipment failures (whether due to age or otherwise);

·       restrictionson emissions;

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

·       releasesof pollutants and hazardous substances to air, soil, surface water or groundwater;

·       shortagesof equipment or spare parts;

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·       labordisputes;

·       operatorerrors;

·       curtailmentof operations due to transmission constraints;

·       failuresin the electricity transmission system which may cause large energy blackouts;

·       implementationof unproven technologies in connection with environmental improvements; and

·       catastrophicevents such as fires, explosions, floods, earthquakes, hurricanes or othersimilar occurrences.

A decrease in, or the elimination of, the revenuesgenerated by our facilities or an increase in the costs of operating suchfacilities could materially impact our cash flows and results of operations,including cash flows available to us to make payments on our debt or our otherobligations.

For example on December 16, 2005, one of thegenerating units at our Chalk Point facility experienced a forced outage as aresult of a structural failure in one of its retired-in-place precipitators.The failure caused damage to associated ductwork. The Chalk Point facilityresumed normal operations on January 17, 2006.

On September 18,2005, Unit No. 1 at the Morgantown facility experienced a forced outage inresponse to high turbine vibration resulting from the failure of one lowpressure turbine blade. This failure required the unit to be shut down. Theunit returned to service on November 18, 2005.

***The accounting for our asset hedging and proprietarytrading activities may increase the volatility of our quarterly and annualfinancial results.***

Weengage in asset management activities in order to economically hedge ourexposure to market risk with respect to (1) electricity sales from ourgeneration facilities, (2) fuel utilized by those facilities and (3) emissionsallowances. We generally attempt to balance our fixed-price physical andfinancial purchases and sales commitments in terms of contract volumes and thetiming of performance and delivery obligations through the use of financial andphysical derivative contracts. We also use derivative contracts with respect toour limited proprietary trading activities, through which we attempt to achieveincremental returns by transacting where we have specific market expertise.Some of the derivatives from our asset hedging and proprietary tradingactivities are recorded on our balance sheet at fair value pursuant toStatement of Financial Accounting Standards Board (“SFAS”) No. 133, “*Accounting for Derivative Instruments and Hedging Activities*,”(“SFAS No. 133”). None of our derivatives recorded at fair market valueare designated as hedges under SFAS No. 133 and changes in their fairvalue are therefore recognized currently in earnings as unrealized gains orlosses. As a result, our financial results—including gross margin, operatingincome and balance sheet ratios—will, at times, be volatile and subject tofluctuations in value primarily due to changes in electricity and fuel prices.For example, for the year ended December 31, 2005, we were required tomark-to-market contracts resulting in a $21 million charge as compared to theyear ended December 31, 2004, when we were required to mark-to-marketcontracts resulting in a $167 million gain. For a more detailed discussion ofthe accounting treatment of our asset hedging and proprietary tradingactivities, see Note 7 to our combined and consolidated financial statements,included herein.

***Our results are subject to quarterly and seasonalfluctuations.***

Our operatingresults have fluctuated in the past and may continue to do so in the future asa result of a number of factors, including:

·       seasonalvariations in demand and corresponding energy and fuel prices; and

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·       variations in levels ofproduction.

***We compete to sell energy and capacity in thewholesale power markets against some competitors that enjoy competitiveadvantages, including the ability to recover fixed costs through rate basemechanisms and a lower cost of capital.***

Regulated utilities in thewholesale markets generally enjoy a lower cost of capital than we do and oftenare able to recover fixed costs through regulated retail rates including, inmany cases, the costs of generation, allowing them to build, buy and upgradegeneration facilities without relying exclusively on market clearing prices torecover their investments. The competitive advantages of such participantscould adversely impact our ability to compete effectively and could have anadverse impact on the revenues generated by our facilities.

***Our business and activities are subject to extensiveenvironmental requirements and could be adversely affected by suchrequirements, including future changes to them.***

Our business is subject to extensive environmentalregulation by federal, state and local authorities, which, among other things,restricts the discharge of pollutants into the air, water and soil, and alsogoverns the use of water from adjacent waterways. Such laws and regulationsfrequently require us to obtain operating permits and remain in continuouscompliance with the conditions established by those operating permits. Tocomply with these legal requirements and the terms of our operating permits, wemust spend significant sums on environmental monitoring, pollution controlequipment and emissions allowances. If we were to fail to comply with theserequirements, we could be subject to civil or criminal liability and theimposition of liens or fines. In addition, we may be required to shut downfacilities if we are unable to comply with the requirements, such as with CO2regulations for which there currently is not a technical compliance solution,or if we determine the expenditures required to comply are uneconomic. Forexample, we currently intend to retire our Lovett generation facility in NewYork, in part because of substantial environmental capital expenditurerequirements, starting with Unit 5 in 2007 and Units 3 and 4 in 2008. We arepursuing alternatives that would make it economically feasible for thisgeneration facility to remain in operation, but there can be no assurances thatwe will be successful. Furthermore, we had planned to shut down, at leasttemporarily, the Kendall facility from January 2006 through December 2007,with the possibility of restarting operations in January 2008. However,the ISO-NE determined that a small part of the capacity of the Kendall facilityis needed for reliability and negotiated an RMR arrangement for the facility.We may mothball the Kendall facility following the expiration of the RMRarrangement if it is not economically feasible to continue to operate thefacility.

In addition, environmental laws, particularly withrespect to air emissions, wastewater discharge and cooling water intakestructures, are generally becoming more stringent, which may require us to makeexpensive facility upgrades or restrict our operations to meet more stringentstandards. With the trend toward stricter standards, greater regulation, andmore extensive permitting requirements, we expect our environmentalexpenditures to be substantial in the future. Although we have budgeted forsignificant expenditures to comply with these requirements, actual expendituresmay be greater than budgeted amounts. We may have underestimated the cost ofthe environmental work we are planning or the air emissions allowances weanticipate buying. In addition, new environmental laws may be enacted, new orrevised regulations under those laws may be issued, the interpretation of suchlaws and regulations by regulatory authorities may change, or additionalinformation concerning the way in which such requirements apply to us may beidentified. For example, in November 2005, Maryland’s governor announcedthat he intends to propose a Maryland Clean Power Rule that would requiredeep reductions in NOx emissions by 2009 and in SO2 and mercury emissions by2010 at six Maryland coal fired power facilities, including our Chalk Point,Dickerson and Morgantown facilities. If the rulemaking proceeds according tothe timing indicated by the Governor’s office, that rule would become lawin the summer of 

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2006. Although we have notfully evaluated the impacts of the Governor’s proposed rule as announced,if adopted as proposed, it would require us to increase substantially ourcapital expenditure requirements from 2006 through 2010 in a way that couldmaterially and adversely affect us. We may not be able to recover incrementalcapital costs of compliance with new environmental regulations, which mayadversely affect our financial performance and condition.

From time to time we may not be able to obtainnecessary environmental regulatory approvals. Such approvals could be delayedor subject to onerous conditions. If there is a delay in obtaining anyenvironmental regulatory approvals or if onerous conditions are imposed, theoperation of our generation facilities or the sale of electricity to thirdparties could be prevented or become subject to additional costs. Such delaysor onerous conditions could have a material adverse effect on our financialperformance and condition.

Certain environmentallaws, including CERCLA and comparable state laws, impose strict and, in manycircumstances, joint and several liability for costs of contamination in soil,groundwater and elsewhere. Some of our facilities have areas with known soiland/or groundwater contamination. Releases of hazardous substances at ourgeneration facilities, or at locations where we dispose of (or in the pastdisposed of) hazardous substances and other waste, could require us to spendsignificant sums to remediate contamination, regardless of whether we causedsuch contamination. The discovery of significant contamination at our generationfacilities, at disposal sites we currently utilize or have formerly utilized,or at other locations for which we may be liable, or the failure or inabilityof parties contractually responsible to us for contamination to respond whenclaims or obligations regarding such contamination arise, could have a materialadverse effect on our financial performance and condition.

***The expected decommissioning and/or site remediationobligations of certain of our generation facilities may negatively impact our cashflows.***

We expect that certain ofour generation facilities and related properties will become subject todecommissioning and/or site remediation obligations that may require materialexpenditures. The exact amount and timing of such expenditures, if any, is notpresently known. Furthermore, laws and regulations may change to imposematerial additional decommissioning and remediation obligations on us in thefuture. If we are required to make material expenditures to decommission orremediate one or more of our facilities, such obligations will impact our cashflows and may adversely impact our ability to make payments on our obligations.

***Our level of indebtedness could adversely affect ourability to raise additional capital to fund our operations, limit our abilityto react to changes in the economy or our industry and prevent us from meetingour obligations.***

As of December 31,2005, our total indebtedness wasapproximately $2.6 billion. In addition, the present value of lease paymentsunder the Mirant Mid-Atlantic leveraged leases is approximately $1 billion(assuming a 10% discount rate) and the termination value of the MirantMid-Atlantic leveraged leases is $1.4 billion. Our substantial degree ofleverage could have important consequences, including the following: (1) itmay limit our ability to obtain additional debt or equity financing for workingcapital, capital expenditures, debt service requirements, acquisitions andgeneral corporate or other purposes; (2) a substantial portion of our cashflows from operations must be dedicated to the payment of principal andinterest on our indebtedness and will not be available for other purposes,including our operations, capital expenditures and future businessopportunities; (3) the debt service requirements of our other indebtednesscould make it more difficult for us to satisfy our financial obligations; (4) certainof our borrowings, including borrowings under Mirant North America’s seniorsecured credit facilities, are at variable rates of interest, exposing us tothe risk of increased interest rates; (5) it may limit our ability toadjust to changing market conditions and place us at a competitive disadvantagecompared with our competitors that have less debt; and (6) we may be morevulnerable in a downturn in general economic 

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conditionsor in our business and we may be unable to carry out capital expenditures thatare important to our long-term growth or necessary to comply with environmentalregulations.

***We are a holding company and may not have access tosufficient cash to meet our obligations***.

Our operations may not generate sufficient cash toenable us to make principal and interest payments on our indebtedness. In addition, payments to us by oursubsidiaries will be contingent upon our subsidiaries’ earnings. Oursubsidiaries are permitted under the terms of our indebtedness to incuradditional indebtedness that may restrict payments from those subsidiaries tous. We cannot assure you that agreements governing current and futureindebtedness of our subsidiaries will permit those subsidiaries to provide uswith sufficient cash to fund our obligations.

The Company has no operations and no subsidiaries withoperations other than Mirant North America and the subsidiaries that it owns,including Mirant Mid-Atlantic. We have no source of revenue to pay interest orprincipal on our debt other than money received from distributions. MirantNorth America, Mirant Mid-Atlantic and our other subsidiaries are separate anddistinct legal entities and they have no obligation, contingent or otherwise,to pay our obligations or to make any funds available to pay those obligations,whether by dividend, distribution, loan or other payment.

Our obligations areeffectively subordinated to the obligations or indebtedness of any of oursubsidiaries. As of March 3, 2006, Mirant North America had approximately $1.6billion of indebtedness outstanding under its notes and credit facility. Thenotes and senior secured credit facilities permit Mirant North America, subjectto certain limitations and the condition that there is no default or event ofdefault, to make distributions to us to fund our debt service. A significantportion of our cash from operations is generated by Mirant Mid-Atlantic. Underthe Mirant Mid-Atlantic leveraged leases, Mirant Mid-Atlantic is subject to acovenant that does not permit them to make distributions to us unless (1)certain fixed charge coverage ratio and projected fixed charge coverage ratiotests are met and (2) at the time of and after giving effect to suchdistribution, no significant lease default or lease event of default hasoccurred and is continuing.

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

Our ability to pay principal and interest on our debtdepends on our future operating performance. If our cash flows and capitalresources are insufficient to allow us to make scheduled payments on our debt,we may have to reduce or delay capital expenditures, sell assets, seekadditional capital, restructure or refinance. There can be no assurance thatthe terms of our debt will allow these alternative measures, that the financialmarkets will be available to us on acceptable terms or that such measures wouldsatisfy our scheduled debt service obligations.

We seek to manage the risks associated with thevolatility in the price at which we sell power produced by our generationfacilities and in the prices of fuel, emissions allowances and other inputsrequired to produce such power by entering into hedging transactions. Theseasset hedging activities generally require us to post a significant amount ofcollateral either in the form of cash or letters of credit. As of December 31,2005, we had approximately $685 million of posted cash collateral and $56million of letters of credit outstanding primarily to support our asset hedgingactivities and debt service reserve requirements. While we seek to structuretransactions in a way that reduces our potential liquidity needs forcollateral, we may be unable to execute our hedging strategy successfully if weare unable to post the amount of collateral required to enter into and supporthedging contracts.

In our efforts to hedge commodity price risk, we arean active participant in energy exchange and clearing markets. These marketsrequire a per contract initial margin to be posted, regardless of the creditquality of the participant. The initial margins are determined by the exchangesthrough the use of 

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proprietary models thatrely on a variety of inputs and factors, including market conditions. We havelimited notice of any changes to the margin rates. Consequently, we are exposedto changes in the per unit margin rates required by the exchanges and could berequired to post additional collateral on short notice.

If our facilitiesexperience unplanned outages, we may be required to procure replacement powerin the open market to satisfy contractual commitments. Without adequateliquidity to post margin and collateral requirements, we may be exposed tosignificant losses and may miss significant opportunities, and we may haveincreased exposure to the volatility of spot markets.

***Our business is subject to complex governmentregulations. Changes in these regulations, or their administration, bylegislatures, state and federal regulatory agencies, or other bodies may affectthe costs of operating our facilities or our ability to operate our facilities.Such cost impacts, in turn, may negatively impact our financial condition andresults of operations.***

Generally, we are subject to regulation by the FERCregarding the terms and conditions of wholesale service and rates, as well asby state agencies regarding physical aspects of the generation facilities. Themajority of our generation is sold at market prices under the market-based rateauthority granted by the FERC. If certain conditions are not met, the FERC hasthe authority to withhold or rescind market-based rate authority and requiresales to be made based on cost-of-service rates. A loss of our market-basedrate authority could have a materially negative impact on our generationbusiness.

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

Changes in the markets in which we compete may have anadverse impact on the results of our operations. For example, in the fall of2004, 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 providingcapacity to all areas of PJM. This has depressed the prices that can be chargedfor capacity in PJM.

Certain of our assets are located in the ERCOT market.Such assets are not generally subject to regulation by the FERC, but aresubject to similar types of regulation by the PUCT.

To conduct our business, we must obtain licenses,permits and approvals for our facilities. These licenses, permits and approvalscan be in addition to any required environmental permits. No assurance can beprovided that we will be able to obtain and comply with all necessary licenses,permits and approvals for these facilities. If we cannot comply with allapplicable regulations, our business, results of operations and financialcondition could be adversely affected.

On August 8, 2005, the EPAct 2005 was enacted.Among other things, the EPAct 2005 provides incentives for various forms ofelectric generation technologies, which will subsidize our competitors. Manyregulations that could be issued pursuant to the EPAct 2005 may have an adverseimpact on our business.

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In 2003, the Northeastern United States and parts ofCanada suffered a massive blackout allegedly stemming from transmissionproblems originating in Ohio. In part as a result of this, the EPAct 2005requires the FERC to select an industry self-regulatory organization which willimpose mandatory reliability rules and standards. We cannot predict theimpact of this on us.

We cannot predict whetherthe federal or state legislatures will adopt legislation relating to therestructuring of the energy industry. There are proposals in many jurisdictionsboth to advance and to roll back the movement toward competitive markets forsupply of electricity, at both the wholesale and retail level. In addition, anyfuture legislation favoring large, vertically integrated utilities and aconcentration of ownership of such utilities could impact our ability tocompete successfully, and our business and results of operations could suffer.We cannot provide assurance that the introductions of new laws, or other futureregulatory developments, will not have a material adverse impact on ourbusiness, operations or financial condition.

***Changes in technology may significantly impact ourgeneration business by making our generation facilities less competitive.***

A basic premise of our generationbusiness is that generating power at central facilities achieves economies ofscale and produces electricity at a low price. There are other technologiesthat can produce electricity, most notably fuel cells, microturbines, windmillsand photovoltaic solar cells. It is possible that advances in technology willreduce the cost of alternative methods of electricity production to levels thatare equal to or below that of most central station electric production, whichcould have a material impact on our results of operations.

***Terrorist attacks, future war or risk of war mayadversely impact our results of operations, our ability to raise capital or ourfuture growth.***

As power generators, weface heightened risk of an act of terrorism, either a direct act against one ofour generation facilities or an inability to operate as a result of systemicdamage resulting from an act against the transmission and distributioninfrastructure that we use to transport our power. If such an attack were tooccur, our business, financial condition and results of operations could bematerially adversely impacted. In addition, such an attack could impact ourability to service our indebtedness, our ability to raise capital and ourfuture growth opportunities.

***Our operations are subject to hazards customary to thepower generation industry. We may not have adequate insurance to cover all ofthese hazards.***

Our operations are subjectto many hazards associated with the power generation industry, which may exposeus to significant liabilities for which we may not have adequate insurancecoverage. Power generation involves hazardous activities, including acquiring,transporting and unloading fuel, operating large pieces of rotating equipmentand delivering electricity to transmission and distribution systems. Inaddition to natural risks, such as earthquake, flood, lightning, hurricane andwind, hazards, such as fire, explosion, collapse and machinery failure, areinherent risks in our operations. These hazards can cause significant personalinjury or loss of life, severe damage to and destruction of property, plant andequipment, contamination of, or damage to, the environment and suspension ofoperations. The occurrence of any one of these events may result in our beingnamed as a defendant in lawsuits asserting claims for substantial damages,environmental cleanup costs, personal injury and fines and/or penalties. Wemaintain an amount of insurance protection that we consider adequate, but wecannot assure that our insurance will be sufficient or effective under allcircumstances and against all hazards or liabilities to which we may besubject. A successful claim for which we are not fully insured could hurt ourfinancial results and materially harm our financial condition.

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***The subsidiaries that own our generation facilities inNew York, including our Lovett and Bowline facilities, have not emerged fromChapter 11.***

Our Lovett and Bowline generation facilities in NewYork are subject to disputes with local tax authorities regarding property taxassessments and with the New York State Department of EnvironmentalConservation (the “NYSDEC”) regarding environmental controls. We are also indiscussions with the NYISO and utilities regarding an agreement that wouldcompensate Mirant Lovett for its contribution to the reliability of the NewYork electric power system. The facilities are forecasted to have negativeoperating cash flows at their current tax valuations. Until a settlement isreached on property taxes, environmental controls and reliability that wouldpermit economically feasible operation, our subsidiaries that own thefacilities, Mirant Lovett and Mirant Bowline, LLC (“Mirant Bowline”), willremain in Chapter 11. The Lovett and Bowline facilities are currently innegotiations on all of these issues. Although negotiations are continuing,resolutions may not be reached in the near future or not at all. Untilresolutions are reached and the companies emerge from bankruptcy, we will nothave access to the cash from operations generated from these subsidiaries.

Mirant NY-Gen, whichincludes hydroelectric facilities at Swinging Bridge, Rio and Mongaup, andsmall combustion turbine facilities at Hillburn and Shoemaker, is insolvent.Its expenses are being funded under a debtor-in-possession facility made byMirant Americas, Inc. (“Mirant Americas”), with the approval of, and underthe supervision of, the Bankruptcy Court. Mirant NY-Gen is currently discussingwith the FERC appropriate remediation for a sinkhole discovered in May 2005in the dam at the Swinging Bridge facility. We also conducted a flood study todetermine downstream consequences if the maximum capacities of the reservoirswere exceeded at our New York Swinging Bridge, Rio and Mongaup generationfacilities, which may cause the FERC to request that Mirant NY-Gen remediatethose dams as well. Mirant NY-Gen has initiated discussions with the FERC forsurrendering its permits to operate all the hydroelectric facilities atSwinging Bridge, Rio and Mongaup, and expects to begin that formal processsoon. It is not possible at this point to determine the cost of remediating thedam and surrendering the permits, but such costs may be substantial.

***We may be subject to claims that were not dischargedin the bankruptcy cases, which could have a material adverse effect on ourresults of operations and profitability.***

The nature of our businessfrequently subjects us to litigation. Substantially all of the material claimsagainst us that arose prior to the date of the bankruptcy filing were resolvedduring our Chapter 11 proceedings. In addition, the Bankruptcy Code providesthat the confirmation of a plan of reorganization discharges a debtor fromsubstantially all debts arising prior to confirmation and certain debts arisingafterwards. With few exceptions, all claims that arose prior to our bankruptcyfiling and before confirmation of the Plan are (1) subject to compromiseand/or treatment under the Plan or (2) discharged, in accordance with theBankruptcy Code and terms of the Plan. Circumstances in which claims and otherobligations that arose prior to our bankruptcy filing were not dischargedprimarily relate to certain actions by governmental units under police powerauthority, where we have agreed to preserve a claimant’s claims, as well as,potentially, instances where a claimant had inadequate notice of the bankruptcyfiling. The ultimate resolution of such claims and other obligations may have amaterial adverse effect on our results of operations and profitability.

***We cannot be certain that the bankruptcy proceedingwill not adversely affect our operations going forward.***

Although we emerged frombankruptcy upon consummation of the Plan, we cannot assure you that having beensubject to bankruptcy protection will not adversely affect our operations goingforward, including our ability to negotiate favorable terms from suppliers,hedging counterparties and others and to attract and retain customers. Thefailure to obtain such favorable terms and retain customers could adverselyaffect our financial performance.

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**Item 1B.****               *Unresolved Staff Comments***

None.

**Item 2.****                        *Properties***

Thefollowing properties were owned or leased as of December 31, 2005:

| **Power  Generation  Business**   | ** ** | **Location**  | ** ** | **Plant Type**             | ** ** | **Primary Fuel** | ** ** | **Mirant’s %  Leasehold/  Ownership  Interest** | ** ** | **Total  MW(1)** | ** ** | **Net Equity  Interest/  Lease in  Total  MW(1)** | ** ** | **2005  Capacity  Factor(2)** | ** ** |
|-----------------------------------|------------|---------------|------------|---------------------------------|------------|-----------------------|------------|------------------------------------------------------|------------|------------------|------------|-------------------------------------------------------------|------------|-------------------------------|------------|
| **Mid-Atlantic Region:**          |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        |       |                          |       |   |   |   |   |   |   |   |   |
| Chalk Point                       |       | Maryland      |       | Intermediate/Baseload/  Peaking |       | Natural Gas/Coal/Oil  |       |                                                 | 100        |             |       |                                                        | 2,429      |                          |       |   | 2,429 |   |   |   | 31 | % |   |
| Dickerson                         |       | Maryland      |       | Baseload/Peaking                |       | Natural Gas/Coal/Oil  |       |                                                 | 100        |             |       |                                                        | 853        |                          |       |   | 853 |   |   |   | 48 | % |   |
| Morgantown                        |       | Maryland      |       | Baseload/Peaking                |       | Coal/Oil              |       |                                                 | 100        |             |       |                                                        | 1,492      |                          |       |   | 1,492 |   |   |   | 50 | % |   |
| Potomac River                     |       | Virginia      |       | Intermediate/  Baseload         |       | Coal/Oil              |       |                                                 | 100        |             |       |                                                        | 482        |                          |       |   | 482 |   |   |   | 31 | % |   |
| Total Mid-Atlantic                |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        | 5,256      |                          |       |   | 5,256 |   |   |   | 39 | % |   |
| **Northeast Region:**             |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        |       |                          |       |   |   |   |   |   |   |   |   |
| Canal                             |       | Massachusetts |       | Intermediate                    |       | Natural Gas/Oil       |       |                                                 | 100        |             |       |                                                        | 1,112      |                          |       |   | 1,112 |   |   |   | 50 | % |   |
| Kendall                           |       | Massachusetts |       | Intermediate/Peaking            |       | Natural Gas/Oil       |       |                                                 | 100        |             |       |                                                        | 256        |                          |       |   | 256 |   |   |   | 59 | % |   |
| Martha’s Vineyard            |       | Massachusetts |       | Peaking                         |       | Diesel                |       |                                                 | 100        |             |       |                                                        | 14         |                          |       |   | 14 |   |   |   | 1 | % |   |
| Wyman                             |       | Maine         |       | Peaking                         |       | Fuel Oil              |       |                                                 | 1.4        |             |       |                                                        | 614        |                          |       |   | 9 |   |   |   | — |   |   |
| Total New England(3)         |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        | 1,996      |                          |       |   | 1,391 |   |   |   | 51 | % |   |
| Bowline                           |       | New York      |       | Intermediate/Peaking            |       | Natural Gas/Oil       |       |                                                 | 100        |             |       |                                                        | 1,125      |                          |       |   | 1,125 |   |   |   | 12 | % |   |
| Grahamsville                      |       | New York      |       | Baseload                        |       | Hydro                 |       |                                                 | 100        |             |       |                                                        | 16         |                          |       |   | 16 |   |   |   | 66 | % |   |
| 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 |   |   |   | 25 | % |   |
| Rio                               |       | New York      |       | Intermediate/Peaking            |       | Hydro                 |       |                                                 | 100        |             |       |                                                        | 9          |                          |       |   | 9 |   |   |   | 30 | % |   |
| Shoemaker                         |       | New York      |       | Peaking                         |       | Natural Gas/Jet Fuel  |       |                                                 | 100        |             |       |                                                        | 44         |                          |       |   | 44 |   |   |   | — |   |   |
| Swinging Bridge                   |       | New York      |       | Intermediate/Peaking            |       | Hydro                 |       |                                                 | 100        |             |       |                                                        | 12         |                          |       |   | 12 |   |   |   | 14 | % |   |
| Total New York                    |       |          |       |                            |       |                  |       |                                                 | 100        |             |       |                                                        | 1,672      |                          |       |   | 1,672 |   |   |   | 20 | % |   |
| Total Northeast                   |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        | 3,668      |                          |       |   | 3,063 |   |   |   | 34 | % |   |
| **West Region:**                  |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        |       |                          |       |   |   |   |   |   |   |   |   |
| Contra Costa                      |       | California    |       | Intermediate                    |       | Natural Gas           |       |                                                 | 100        |             |       |                                                        | 674        |                          |       |   | 674 |   |   |   | 6 | % |   |
| Pittsburg                         |       | California    |       | Intermediate                    |       | Natural Gas           |       |                                                 | 100        |             |       |                                                        | 1,311      |                          |       |   | 1,311 |   |   |   | 6 | % |   |
| Potrero                           |       | California    |       | Baseload/Peaking                |       | Natural Gas/Oil       |       |                                                 | 100        |             |       |                                                        | 362        |                          |       |   | 362 |   |   |   | 14 | % |   |
| Total California                  |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        | 2,347      |                          |       |   | 2,347 |   |   |   | 7 | % |   |
| Mirant Texas                      |       | Texas         |       | Baseload/Peaking                |       | Natural Gas           |       |                                                 | 100        |             |       |                                                        | 532        |                          |       |   | 532 |   |   |   | 38 | % |   |
| Total West                        |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        | 2,879      |                          |       |   | 2,879 |   |   |   | 13 | % |   |
| **Mid-Continent Region:**         |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        |       |                          |       |   |   |   |   |   |   |   |   |
| Mirant Zeeland                    |       | Michigan      |       | Intermediate/Peaking            |       | Natural Gas           |       |                                                 | 100        |             |       |                                                        | 837        |                          |       |   | 837 |   |   |   | 8 | % |   |
| Mirant Americas  Generation Total |       |          |       |                            |       |                  |       |                                                 |       |             |       |                                                        | 12,640     |                          |       |   | 12,035 |   |   |   | 30 | % |   |

 

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(1)              MW amounts reflect net dependable capacity.

(2)              Capacity factor is the****averagepercentage of full capacity used over a year.

(3)              Total MW reflects a 1.4% ownershipinterest, or 8.8 MW, in the 614 MW Wyman plant.

We also own an oil pipeline, which is approximately51.5 miles long and serves the Chalk Point and Morgantown generatingfacilities.

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**Item 3.**                        *Legal Proceedings*

***Chapter 11 Proceedings***

On the Petition Date, and various dates thereafter,the Mirant Debtors filed voluntary petitions for relief under Chapter 11of the Bankruptcy Code. On August 21, 2003, and September 8, 2003,the Bankruptcy Court entered orders establishing a December 16, 2003, bardate (the “Bar Date”) for filing proofs of claim against the Mirant Debtors’estates.

Most of the material claims filed against the MirantDebtors’ estates were disallowed or were resolved and became “allowed” claimsbefore confirmation of the Plan. For example, the claims filed by theCalifornia Attorney General, PG&E, various other California parties,plaintiffs in certain rate payer class action lawsuits, the plaintiffs incertain bondholder litigation, and Utility Choice, L.P., which are described inour 2004 Form 10-K, are among the claims that were resolved prior toconfirmation of the Plan. A number of claims, however, remain unresolved.

Except for claims and other obligations not subject todischarge under the Plan and unless otherwise provided below, all claimsagainst the Mirant Debtors’ estates representing obligations that arose priorto July 14, 2003, are subject to compromise under the Plan. This meansthat the claimant will receive a distribution of Mirant common stock, cash orboth common stock and cash in accordance with the terms of the Plan insatisfaction of the claim. As a result, the exact amount of the claim may stillbe litigated, but we will not be required to make any payment in respect ofsuch litigation until a resolution is obtained, through settlement, judgment orotherwise.

As of December 31, 2005, approximately 23.5million of the shares of Mirant common stock to be distributed under the Planto creditors have been reserved for distribution with respect to claims thatare disputed by the Mirant Debtors and have not been resolved. Under the termsof the Plan, to the extent such claims are resolved now that we have emergedfrom bankruptcy, the claimants will be paid from the reserve of 23.5 millionshares on the same basis as if they had been paid out when the Plan becameeffective. That means that their allowed claims will receive the same pro ratadistributions of Mirant common stock, cash or both common stock and cash aspreviously allowed claims in accordance with the terms of the Plan. It is ourview that we have funded the disputed claims reserve at a sufficient level tosettle the remaining unresolved proofs of claim we received during thebankruptcy proceedings and any claims resulting from Mirant’s rejection ofcertain contracts with PEPCO, as described below in *PEPCOLitigation*. However, to the extent the aggregate amount of thepayouts determined to be due with respect to such disputed claims ultimatelyexceeds the amount of the funded claim reserve, Mirant would have to issueadditional shares of common stock to address the shortfall, which would diluteexisting shareholders, and we would have to pay additional cash amounts asnecessary under the terms of the Plan to satisfy such pre-petition claims. Wewill continue to monitor our obligations as the disputed claims are resolved.

Our Lovett and Bowlinegeneration facilities in New York are subject to disputes with local taxauthorities regarding property tax assessments and with the NYSDEC regardingenvironmental controls. Mirant Lovett is also in discussions with the NYISO andutilities regarding an agreement that would compensate Mirant Lovett for thecontribution of the Lovett facility to the reliability of the New York electricpower system. The facilities are forecasted to have negative operating cashflows at their current tax valuations. Until a settlement is reached onproperty taxes, environmental controls and reliability, that would permiteconomically feasible operation, our subsidiaries that own the facilities,Mirant Lovett and Mirant Bowline, will remain in Chapter 11. Mirant Lovett andMirant Bowline are currently in settlement discussions on all of these issues.Although negotiations are continuing, settlements may not be reached in thenear future, or at all. Until such settlements are reached and the companiesemerge from bankruptcy, we will not have access to the cash from operationsgenerated from these subsidiaries. Mirant NY-Gen, which owns hydroelectricfacilities at Swinging Bridge, Rio and Mongaup, and small combustion turbine facilities at Hillburn and Shoemaker, isinsolvent. Its expenses are being funded under a debtor-in-possession

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facilitymade by Mirant Americas with the approval of, and under the supervision of, theBankruptcy Court. Mirant NY-Gen is currently discussing with the FERCappropriate remediation for a sinkhole discovered in May 2005 in the damat the Swinging Bridge facility. We conducted a flood study to determinedownstream consequences if the maximum capacities of the reservoirs wereexceeded at our New York Swinging Bridge, Rio and Mongaup generationfacilities, and Mirant NY-Gen could be requested by the FERC to remediate thosedams as well. Mirant NY-Gen has initiated discussions with the FERC forsurrendering its permits to operate all the hydroelectric facilities atSwinging Bridge, Rio and Mongaup, and expects to begin that formal processsoon. It is not possible at this point to determine the cost of remediating thedam at Swinging Bridge and surrendering the permits, but such costs may besubstantial.

***PEPCO Litigation***

In 2000, Mirant purchased power generating facilitiesand other assets from PEPCO, including certain PPAs between PEPCO and thirdparties. Under the terms of the Asset Purchase and Sale Agreement (“APSA”), Mirant and PEPCO entered into the Back-to-BackAgreement with respect to certain PPAs, including PEPCO’s long-term PPAs withOhio Edison and Panda-Brandywine L.P. (“Panda”), under which (1) PEPCO agreedto resell to Mirant all capacity, energy, ancillary services and other benefitsto which it is entitled under those agreements; and (2) Mirant agreed topay PEPCO each month all amounts due from PEPCO to the sellers under thoseagreements for the immediately preceding month associated with such capacity,energy, ancillary services and other benefits. The Ohio Edison PPAterminated in December 2005 and the Panda PPA runs until 2021. Under theBack-to-Back Agreement, Mirant is obligated to purchase power from PEPCO atprices that are typically higher than the market prices for power.

Mirant assigned its rightsand obligations under the Back-to-Back Agreement to Mirant Americas EnergyMarketing. In the Chapter 11 cases of the Mirant Debtors, PEPCO asserted thatan Assignment and Assumption Agreement dated December 19, 2000, thatincludes as parties PEPCO and various subsidiaries of ours causes oursubsidiaries that are parties to the agreement to be jointly and severallyliable to PEPCO for various obligations, including the obligations under theBack-to-Back Agreement. The Mirant Debtors have sought to reject the APSA, theBack-to-Back Agreement, and the Assignment and Assumption Agreement, and therejection motions have not been resolved. Under the Plan, the obligations ofthe Mirant Debtors under the APSA (including any other agreements executedpursuant to the terms of the APSA and found by the final court order to be partof the APSA), the Back-to-Back Agreement, and the Assignment and AssumptionAgreement are to be performed by Mirant Power Purchase, LLC (“Mirant PowerPurchase”), whose performance is guaranteed by Mirant. If any of the agreementsis successfully rejected, the obligations of Mirant Power Purchase and Mirant’sguarantee obligations terminate with respect to that agreement, and PEPCO wouldbe 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 theBankruptcy Court were to conclude that the Assignment and Assumption Agreementimposed liability upon our subsidiaries for the obligations under theBack-to-Back Agreement and the Back-to-Back Agreement were to be rejected, theresulting rejection damages claim could result in a claim in the Chapter 11proceedings against our subsidiaries but any such claim would be reduced by theamount recovered by PEPCO on its comparable claim against Mirant.

***California and Western Power Markets***

*California Rate PayerLitigation.**  *Certainof our subsidiaries are subject to litigation related to their activities inCalifornia and the western power markets and the high prices for wholesaleelectricity experienced in the western markets during 2000 and 2001. Variouslawsuits were filed in 2000 through 2003 that asserted claims under Californialaw based on allegations that certain owners of electricity generationfacilities in California and energy marketers, including the Company, MirantAmericas Energy 

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Marketing and oursubsidiaries owning generating facilities in California, engaged in variousunlawful and anti-competitive acts that served to manipulate wholesale powermarkets and inflate wholesale electricity prices in California. All of thesesuits have been dismissed by final orders except for six such suits that werefiled between November 27, 2000, and May 2, 2001, in variousCalifornia Superior Courts and consolidated before the Superior Court for theCounty of San Diego for pretrial purposes. Although the plaintiffs dismissedMirant from those suits, they have not filed to dismiss certain of oursubsidiaries that are also defendants. On October 3, 2005, the Californiastate court dismissed those six consolidated suits on the grounds that theplaintiffs’ claims were barred by federal preemption as a result of the FederalPower Act. On December 5, 2005, the plaintiffs filed an appeal of thedismissal. The plaintiffs in the six consolidated suits did not file claims inthe bankruptcy proceedings, and we expect that their claims are barred by thePlan now that it has become effective.

***Bondholder Litigation***

*Mirant Americas GenerationBondholder Suit.**  *On June 10,2003, certain holders of senior notes of Mirant Americas Generation maturingafter 2006 filed a complaint in the Court of Chancery of the State of Delaware*, California Public Employees’ Retirement System, et al. v. MirantCorporation, et al.,* that named as defendants Mirant, MirantAmericas, Mirant Americas Generation, certain past and present Mirantdirectors, and certain past and present Mirant Americas Generation managers.Among other claims, the plaintiffs assert that a restructuring plan pursued bythe Company prior to its filing a petition for reorganization under Chapter 11of the Bankruptcy Code was in breach of fiduciary duties allegedly owed to themby Mirant, Mirant Americas and Mirant Americas Generation’s managers. Inaddition, the plaintiffs challenge certain dividends and distributions made byMirant Americas Generation prior to the Petition Date. The plaintiffs seekdamages in excess of $1 billion. Mirant has removed this suit to the UnitedStates District Court for the District of Delaware. This action was stayed withrespect to the Mirant entities that are defendants by the filing of the Chapter11 proceedings of these entities. The order entered by the Bankruptcy Courtconfirming the Plan enjoins the prosecution of this action and requires that itbe dismissed. On March 8, 2006, the Bankruptcy Court entered an ordercompelling the plaintiffs in this action to dismiss their complaint inaccordance with the terms of the Plan. On March 17, 2006, the partiesfiled a stipulation of dismissal dismissing the suit.

***U.S. Government Inquiries***

*Department of JusticeInquiries.**  *In November 2002,Mirant received a subpoena from the DOJ, acting through the United StatesAttorney’s office for the Northern District of California, requestinginformation about its activities and those of its subsidiaries for the periodsince January 1, 1998. The subpoena requested information related to theCalifornia energy markets and other topics, including the reporting ofinaccurate information to the trade press that publish natural gas orelectricity spot price data. The subpoena was issued as part of a grand juryinvestigation. The DOJ’s investigation of the reporting of inaccurate naturalgas price information is continuing, and Mirant has held preliminarydiscussions with DOJ regarding the disposition of this matter. The DOJ’sinvestigation is based upon the same circumstances that were the subject of aninvestigation by the Commodity Futures Trading Commission (“CFTC”) that wassettled in December 2004. As described****in Mirant’sAnnual Report on Form 10-K for the year ended December 31, 2004,in*Legal Proceeding— Other Governmental Proceedings—CFTCInquiry*, Mirant and Mirant Americas Energy Marketing pursuant to thesettlement consented to the entry of an order by the CFTC in which it madefindings, which are neither admitted nor denied by Mirant and Mirant AmericasEnergy Marketing, that (1) from January 2000 through December 2001,certain Mirant Americas Energy Marketing natural gas traders (a) knowinglyreported inaccurate price, volume, and/or counterparty information regardingnatural gas cash transactions to publishers of natural gas indices and (b) inaccuratelyreported to index publishers transactions observed in the market as MirantAmericas Energy Marketing transactions and (2) from January to October 2000,certain Mirant Americas Energy 

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Marketing westregion traders knowingly delivered the false reports in an attempt tomanipulate the price of natural gas. Under the settlement, the CFTC received asubordinated allowed, unsecured claim against Mirant Americas Energy Marketingof $12.5 million in the Chapter 11 proceedings. The DOJ could decide thatfurther action against Mirant and Mirant Americas Energy Marketing is notappropriate or could seek indictments against one or more Mirant entities, orthe DOJ and Mirant could agree to a disposition that might involve undertakingsor fines, the amount of which cannot be reasonably estimated at this time butwhich could be material. Mirant has cooperated fully with the DOJ and intendsto continue to do so. At this time, it is our view that any action taken by theDOJ against Mirant or its subsidiaries related to the reporting of natural gasprice information would not involve us or our subsidiaries except to the extentthat any disposition of this matter results in ongoing undertakings by MirantEnergy Trading as the recipient of the assets of Mirant Americas EnergyMarketing under the Plan.

***Environmental Matters***

*EPAInformation Request.**  *InJanuary 2001, the EPA issued a request for information to Mirantconcerning the air permitting and air emissions control implications under theNSR of past repair and maintenance activities at the Potomac River plant inVirginia and the Chalk Point, Dickerson and Morgantown plants in Maryland. Therequested information concerns the period of operations that predates theCompany subsidiaries’ ownership and lease of those plants. Mirant has respondedfully to this request. Under the APSA, PEPCO is responsible for fines andpenalties arising from any violation associated with historical operationsprior to the Company subsidiaries’ acquisition or lease of the plants. If theMirant Debtors succeed in rejecting the APSA as described above in *PEPCO Litigation*, PEPCO may assert that it has no obligationto reimburse Mirant for any fines or penalties imposed upon Mirant for periodsprior to the Company subsidiaries’ acquisition or lease of the plants. If aviolation is determined to have occurred at any of the plants, the Companysubsidiary owning or leasing the plant may be responsible for the cost ofpurchasing and installing emissions control equipment, the cost of which may bematerial. If such violation is determined to have occurred after the Company’ssubsidiaries acquired or leased the plants or, if occurring prior to theacquisition or lease, is determined to constitute a continuing violation, theCompany subsidiary owning or leasing the plant at issue would also be subjectto fines and penalties by the state or federal government for the periodsubsequent to its acquisition or lease of the plant, the cost of which may bematerial.

*MirantPotomac River Notice of Violation.**  *OnSeptember 10, 2003, the Virginia DEQ issued an NOV to Mirant Potomac Riveralleging that it violated its Virginia Stationary Source Permit to Operate byemitting NOx in excess of the “cap” established by the permit for the 2003summer ozone season. Mirant Potomac River responded to the NOV, asserting thatthe cap is unenforceable, noting that it can comply through the purchase ofemissions allowances and raising other equitable defenses. Virginia’s civilenforcement statute provides for injunctive relief and penalties. On January 22,2004, the EPA issued an NOV to Mirant Potomac River alleging the same violationof its Virginia Stationary Source Permit to Operate as set out in the NOVissued by the Virginia DEQ.

On September 27, 2004, Mirant Potomac River,Mirant Mid-Atlantic, the Virginia DEQ, the Maryland Department of theEnvironment, the DOJ and the EPA entered into, and filed for approval with theUnited States District Court for the Eastern District of Virginia, a consentdecree that, if approved, will resolve Mirant Potomac River’s potentialliability for matters addressed in the NOVs previously issued by the VirginiaDEQ and the EPA. The consent decree requires Mirant Potomac River and MirantMid-Atlantic to (1) install pollution control equipment at the PotomacRiver plant and at the Morgantown plant leased by Mirant Mid-Atlantic inMaryland, (2) comply with declining system-wide ozone season NOx emissionscaps from 2004 through 2010, (3) comply with system-wide annual NOxemissions caps starting in 2004, (4) meet seasonal system averageemissions rate targets in 2008 and (5) pay civil penalties and performsupplemental environmental projects in and around the Potomac River plantexpected to 

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achieve additionalenvironmental benefits. Except for the installation of the controls planned forthe Potomac River units and the installation of SCR or equivalent technology atMirant Mid-Atlantic’s Morgantown Units 1 and 2 in 2007 and 2008, the consentdecree does not obligate the Company’s subsidiaries to install specificallydesignated technology, but rather to reduce emissions sufficiently to meet thevarious NOx caps. Moreover, as to the required installations of SCRs atMorgantown, Mirant Mid-Atlantic may choose not to install the technology by theapplicable deadlines and leave the units off either permanently or until suchtime as the SCRs are installed. The consent decree is subject to the approvalof the district court and the Bankruptcy Court.

The owners/lessors under the lease-financingtransactions covering the Morgantown and Dickerson plants (the “Owners/Lessors”)objected to the proposed consent decree in the Bankruptcy Court and filed amotion to intervene in the district court action. As part of a resolution ofdisputed matters in the Chapter 11 proceedings, the Owners/Lessors have nowagreed not to object to the consent decree, subject to certain terms set forthin the Plan and Confirmation Order.

On July 22, 2005, the district court granted amotion filed by the City of Alexandria seeking to intervene in the districtcourt action, although the district court imposed certain limitations on theCity of Alexandria’s participation in the proceedings. On September 23,2005, the City of Alexandria filed a motion seeking authority to file anamended complaint in the action seeking injunctive relief and civil penaltiesunder the Clean Air Act for alleged violations by Mirant Potomac River of itsVirginia Stationary Source Permit To Operate and the State of Virginia’s StateImplementation Plan. Based upon a computer modeling, the City of Alexandriaasserted that emissions from the Potomac River plant exceed NAAQS for SO2,nitrogen dioxide (“NO2”), and particulate matter. The City of Alexandria alsocontended based on its modeling analysis that the plant’s emissions of hydrogenchloride and hydrogen fluoride exceed Virginia state emissions standards.Mirant Potomac River disputes the City of Alexandria’s allegations that it hasviolated the Clean Air Act and Virginia law. On December 2, 2005, thedistrict court denied the City of Alexandria’s motion seeking to file anamended complaint.

*MirantPotomac River Downwash Study.**  *OnSeptember 23, 2004, the Virginia DEQ and Mirant Potomac River entered intoan order by consent with respect to the Potomac River plant under which MirantPotomac River agreed to perform a modeling analysis to assess the potentialeffect of “downwash” from the plant (1) on ambient concentrations of SO2,NO2, carbon monoxide (“CO”) and particulate matter less than or equal to 10micrometers (“PM10”) for comparison to the applicable NAAQS and (2) onambient concentrations of mercury for comparison to Virginia Standards ofPerformance for Toxic Pollutants. Downwash is the effect that occurs whenaerodynamic turbulence induced by nearby structures causes emissions from anelevated source, such as a smokestack, to be mixed rapidly toward the groundresulting in higher ground level concentrations of emissions. If the modelinganalysis indicates that emissions from the facility may cause exceedances ofthe NAAQS for SO2, NO2, CO or PM10, or exceedances of mercury compared toVirginia Standards of Performance for Toxic Pollutants, the consent orderrequires Mirant Potomac River to submit to the Virginia DEQ a plan and scheduleto eliminate and prevent such exceedances on a timely basis. Upon approval bythe Virginia DEQ of the plan and schedule, the approved plan and schedule is tobe incorporated by reference into the consent order. The results of thecomputer modeling analysis showed that emissions from the Potomac River planthave the potential to contribute to localized, modeled instances of exceedancesof the NAAQS for SO2, NO2 and PM10 under certain conditions.

On August 24, 2005, powerproduction at all five units of the Potomac River generating facility wastemporarily halted in response to a directive from the Virginia DEQ. Thedecision to temporarily shut down the facility arose from findings of a studycommissioned under the order by consent referred to above. The Virginia DEQ’sdirective was based on results from the study’s computer modeling showing thatair emissions from the facility have the potential to contribute to localized,modeled exceedances of the health-based NAAQS under certain conditions. On August 25,2005, the District of Columbia Public 

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ServiceCommission filed an emergency petition and complaint with the FERC and the DOEto prevent the shutdown of the Potomac River facility. The matter remainspending before the FERC and the DOE. On September 21, 2005, Mirant PotomacRiver commenced partial operation of one unit of the plant. On December 20,2005, due to a determination by the DOE that an emergency situation exists withrespect to a shortage of electric energy, the DOE ordered Mirant Potomac Riverto generate electricity at the Potomac River generation facility, as requestedby PJM, during any period in which one or both of the transmission linesserving the central Washington, D.C. area are out of service due to a plannedor unplanned outage. In addition, the DOE ordered Mirant Potomac River, at allother times, for electric reliability purposes, to keep as many units inoperation as possible and to reduce the start-up time of units not inoperation. The DOE required Mirant Potomac River to submit a plan, on or beforeDecember 30, 2005, that met this requirement and did not significantlycontribute to NAAQS exceedances. The DOE advised that it would consider MirantPotomac River’s plan in consultation with the EPA. The order further providesthat Mirant Potomac River and its customers should agree to mutuallysatisfactory terms for any costs incurred by it under this order or just andreasonable terms shall be established by a supplemental order. Certain partiesfiled for rehearing of the DOE order, and on February 17, 2006, the DOEissued an order granting rehearing solely for purposes of considering therehearing requests further. Mirant Potomac River submitted an operating plan inaccordance with the order. On January 4, 2006, the DOE issued an interimresponse to Mirant Potomac River’s operating plan authorizing immediateoperation of one baseload unit and two cycling units, making it possible tobring the entire plant into service within approximately 28 hours. The DOE’sorder expires after September 30, 2006, but we expect we will be able tocontinue 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 withthe EPA to ensure that Mirant Potomac River’s operating plan submitted to theDOE adequately addresses NAAQS issues. The EPA also asserts in its letter thatMirant Potomac River did not immediately undertake action as directed by theVirginia DEQ’s August 19, 2005, letter and failed to comply with therequirements of the Virginia State Implementation Plan established by thatletter. Mirant Potomac River received a second letter from the EPA on December 30,2005, requiring Mirant to provide certain requested information as part of anEPA investigation to determine the Clean Air Act compliance status of thePotomac River facility. The facility will not resume normal operations until itcan satisfy the requirements of the Virginia DEQ and the EPA with respect toNAAQS, unless, for reliability purposes, it is required to return to operationby a governmental agency having jurisdiction to order its operation. On January 9,2006, the FERC issued an order directing PJM and PEPCO to file a long-term planto maintain adequate reliability in the Washington D.C. area and surroundingregion and a plan to provide adequate reliability pending implementation ofthis long-term plan. On February 8, 2006, PJM and PEPCO filed theirproposed reliability plans. We are working with the relevant state and federalagencies with the goal of restoring all five units of the facility to normaloperation in 2007. The financial and operational implications of thediscontinued or limited operation of the Potomac River plant or any suchmodifications are not known at this time, but could be material depending onthe length of time that operations are discontinued or limited.

*Cityof Alexandria Nuisance Suit.**  *OnOctober 7, 2005, the City of Alexandria filed a suit against MirantPotomac River and Mirant Mid-Atlantic in the Circuit Court for the City ofAlexandria. The suit asserts nuisance claims, alleging that the Potomac Riverplant’s emissions of coal dust, flyash, NOx, SO2, particulate matter, hydrogenchloride, hydrogen fluoride, mercury and oil pose a health risk to thesurrounding community and harm property owned by the City. The City seeksinjunctive relief, damages and attorneys’ fees. On February 17, 2006, theCity amended its complaint to add additional allegations in support of itsnuisance claims relating to noise and lighting, interruption of traffic flow bytrains delivering coal to the Potomac River plant, particulate matter from thetransport and storage of coal and flyash, and potential coal leachate into thesoil and groundwater from the coal pile.

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*New York StateAdministrative Claim.**  *OnJanuary 24, 2006, the State of New York and the NYSDEC filed a notice ofadministrative claims in the Company’s Chapter 11 proceedings asserting a claimseeking to require the Company to provide funding to its subsidiaries owninggenerating facilities in New York to satisfy certain specified environmentalcompliance obligations. The State of New York alleges that during the pendencyof the Chapter 11 proceedings the Company and its subsidiaries that haveemerged from bankruptcy made decisions on behalf of the Company’s subsidiariesowning generating facilities in New York and did not appropriately maintain thecorporate separateness between itself and those subsidiaries. The Companydisputes those allegations. The State of New York cites various existingoutstanding matters between the State and the Company’s subsidiaries owninggenerating facilities in New York related to compliance with environmental lawsand regulations, most of which are not material. The most significantcompliance obligation identified by the State of New York in its notice ofadministrative claim relates to the 2003 Consent Decree entered into by MirantNew York and Mirant Lovett with the State of New York to resolve issues relatedto NSR requirements under the Clean Air Act related to the Lovett plant. Underthe 2003 Consent Decree, Mirant Lovett is required to make an election toinstall certain environmental controls on units 4 and 5 of the Lovett facilityor shut down those units by 2007 to 2008. The State of New York notes in itsnotice of administrative claim that the cost of implementing such environmentalcontrols could exceed $200 million. The State of New York and the NYSDEC haveexecuted a stipulated order with the Company and its New York subsidiaries tostay resolution of this administrative claim. The stipulated order was enteredby the Bankruptcy Court on February 23, 2006.

*Riverkeeper Suit AgainstMirant Lovett.**  *On March 11,2005, Riverkeeper, Inc. filed suit against Mirant Lovett in the UnitedStates District Court for the Southern District of New York under the CleanWater Act. The suit alleges that Mirant Lovett’s failure to implement a marinelife exclusion system at its Lovett generating plant and to perform monitoringfor the exclusion of certain aquatic organisms from the plant’s cooling waterintake structures violates Mirant Lovett’s water discharge permit issued by theState of New York. The plaintiff requests the court to enjoin Mirant Lovettfrom continuing to operate the Lovett generating plant in a manner thatallegedly violates the Clean Water Act, to impose civil penalties of $32,500per day of violation, and to award the plaintiff attorney’s fees. OnApril 20, 2005, the district court approved a stipulation agreed to by theplaintiff and Mirant Lovett that stays the suit until 60 days after entry of anorder by the Bankruptcy Court confirming a plan of reorganization for MirantLovett becomes final and non-appealable.

*MirantLovett Coal Ash Management Facility.**  *On July 8, 2004, the NYSDEC issued an NOVfor improper closure of the coal ash management facility (“CAMF”) at the Lovettplant. The Notice of Violation identified two separate issues. The first wasthe failure of the previous owner/operator of the CAMF to obtain a closurecertification for Stage 1 of the CAMF that conformed with applicable New Yorkregulations. It is our view that we have submitted documentation demonstratingthat the CAMF was properly closed, however that issue is still in dispute. Thesecond issue relates to the closure of Stage 2 of the CAMF in 2002. Erosion ofthe barrier protection layer and topsoil developed within a few years of theclosure of Stage 2. On November 8, 2005, the NYSDEC issued an additionalnotice of violation to Mirant Lovett asserting that the leachate collectionsystem for the Lovett CAMF was not properly constructed because it allows stormwater or groundwater to come into contact with the disposed wastes andleachate. Due to the ongoing evaluation to determine what remedial actions arerequired, the exact cost of remedial action is unknown at this time.

*NewYork Dissolved Oxygen.**  *OnSeptember 29, 2003, the NYSDEC issued a complaint to Mirant New York, foralleged failure to comply with state regulatory standards for minimum dissolvedoxygen in the Mongaup River at the Swinging Bridge, Mongaup Falls and Riohydroelectric projects owned by Mirant NY-Gen. The complaint sought a civilpenalty of $120,000 and an order requiring Mirant New York to upgrade the threehydroelectric projects to prevent further discharges that do not meet thestandards for minimum dissolved oxygen. In its complaint the NYSDEC proposedthat $100,000 of the $120,000 penalty it was seeking be suspended on thecondition that Mirant New York complete corrective actions for each facility bya certain schedule it proposed. On June 1, 2004, Mirant New York filed an 

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answer and motion todismiss on grounds including that Mirant New York is not the owner of thehydroelectric projects. Mirant New York granted an extension of time to allowthe NYSDEC to respond, and the NYSDEC has not yet responded. Mirant NY-Gen, theowner of the hydroelectric projects, has agreed with the NYSDEC upon a consentorder to resolve the complaint. Under the consent order, Mirant NY-Gen will paya fine of $8,000 and install certain specified equipment on the operationalturbine at the Swinging Bridge facility. The specified equipment already hasbeen installed on the Mongaup Falls and Rio facilities. In addition, MirantNY-Gen is required to install this same equipment at the other, currentlynon-operational turbine at the Swinging Bridge facility within thirty days ofthat turbine becoming operational. The Bankruptcy Court approved the settlementon February 22, 2006, and the parties are proceeding to execute theconsent order.

*MirantBowline Oil Storage NOV.**  *OnJanuary 4, 2006, the NYSDEC issued an NOV asserting various violations ofregulations relating to a major oil storage facility, secondary containment,compliance report, underground storage tanks and a small oil storage facilityat the Bowline plant. The NOV identified issues with labeling, maintenance andmonitoring procedures and leak detection. The NOV did not seek a specificpenalty amount but noted that the violations identified could each subjectMirant Bowline to a civil penalty of up to $37,500 per day. Mirant Bowline isworking with the NYSDEC to address the issues identified.

*NewYork Major Oil Storage Facility Licenses.**  *The major oil storage facility license for theBowline generating facility expires on March 31, 2006. Mirant Bowline’srenewal application for the Bowline facility has not yet been approved by theNYSDEC. Mirant Bowline is working with the NYSDEC to obtain authorization forcontinued operation of the Bowline major oil storage facility; however, if suchauthorization is not timely approved, Mirant Bowline may be subject to certainpenalties or may be required to temporarily suspend operations at the Bowlinefacility.

*MirantBowline Oil Spill.**  *In November 2001,Mirant Bowline removed two underground oil storage tanks that had been used tocollect oil recovered from the oil/water separators that are used forpretreatment of wastewater from the Bowline generating facility. Contaminatedsoil was found during the removal of one of the tanks and was removed from thesite. Mirant Bowline is unable to confirm from documents at the facilitywhether the spill was reported to the NYSDEC and to the Rockland County, NewYork authorities. Consequently, Mirant Bowline reported a potentialnon-reported spill to the NYSDEC on February 23, 2006.

*Morgantown ParticulateEmissions.*   On March 3, 2006, Mirant Mid-Atlanticreceived a notice sent on behalf of the Maryland Department of the Environment(“MDE”) alleging that violations of particulate matter emissions limitsapplicable to Unit 1 at the Morgantown plant occurred on nineteen days in June andJuly 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 particulatematter limit. The letter further advises that the MDE has asked the MarylandAttorney General to file a civil suit under Maryland law based upon the allegedviolations.

***City of Alexandria Zoning Action***

On December 18, 2004, the City Council for theCity of Alexandria, Virginia (the “City Council”) adopted certain zoningordinance amendments recommended by the City Planning Commission that resultedin the zoning status of Mirant Potomac River’s generating plant being changedfrom “noncomplying use” to “nonconforming use subject to abatement.” Under thenonconforming use status, unless Mirant Potomac River applies for and isgranted a special use permit for the plant during the seven-year abatementperiod, the operation of the plant must be terminated within a seven-yearperiod, and no alterations that directly prolong the life of the plant will bepermitted during the seven-year period. If Mirant Potomac River were to applyfor and receive a special use permit for the plant, the City Council 

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would likely imposevarious conditions and stipulations as to the permitted use of the plant and toseek to limit the period for which it could continue to operate.

At its December 18, 2004, meeting, the CityCouncil also approved revocation of two special use permits issued in 1989 (the“1989 SUPs”), one applicable to the administrative office space at MirantPotomac River’s plant and the other for the plant’s transportation managementplan. Under the terms of the approved action, the revocation of the 1989 SUPswas to take effect 120 days after the City Council revocation, provided,however, that if Mirant Potomac River within such 120-day period filed anapplication for the necessary special use permits to bring the plant intocompliance with the zoning ordinance provisions then in effect, the effectivedate of the revocation of the 1989 SUPs would be stayed until final decision bythe City Council on such application. The approved action further provides thatif 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 Councildoes not approve the application, the revocation of the 1989 SUPs will becomeeffective 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 Cityof Alexandria and the City Council in the Circuit Court for the City ofAlexandria. The complaint seeks to overturn the actions taken by the City Councilon December 18, 2004, changing the zoning status of Mirant Potomac River’sgenerating plant and approving revocation of the 1989 SUPs, on the grounds thatthose actions violated federal, state and city laws. The complaint asserts,among other things, that the actions taken by the City Council constitutedunlawful spot zoning, were arbitrary and capricious, constituted an unlawfulattempt by the City Council to regulate emissions from the plant, and violatedMirant Potomac River’s due process rights. Mirant Potomac River and MirantMid-Atlantic request the court to enjoin the City of Alexandria and the CityCouncil from taking any enforcement action against Mirant Potomac River or fromrequiring it to obtain a special use permit for the continued operation of itsgenerating plant. On January 18, 2006, the court issued an oral rulingfollowing a trial that the City of Alexandria acted unreasonably andarbitrarily in changing the zoning status of Mirant Potomac River’s generatingplant and in revoking the 1989 SUPs. On February 24, 2006, the courtentered judgment in favor of Mirant Potomac River and Mirant Mid-Atlanticdeclaring the change in the zoning status of Mirant Potomac River’s generatingplant adopted December 18, 2004, to be invalid and vacating the CityCouncil’s revocation of the 1989 SUPs. The City of Alexandria has filed noticeof its appeal of this judgment.

***PEPCO Assertion of Breach of Local Area SupportAgreement***

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

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***New York Tax Proceedings***

The Company’s subsidiaries that own the Bowline andLovett generating plants in New York are the petitioners in various proceedings(“Tax Certiorari Proceedings”) initially brought in the New York state courtschallenging the assessed value of those generating plants determined by theirrespective local taxing authorities. Mirant Bowline has challenged the assessedvalue of the Bowline generating facility and the resulting local taxassessments paid for tax years 1995 through 2005. Mirant Bowline succeeded torights held by Orange & Rockland for the tax years prior to itsacquisition of the Bowline Plant in 1999 under its agreement with Orange &Rockland for the purchase of that plant. Mirant Lovett has initiatedproceedings challenging the assessed value of the Lovett facility for each ofthe years 2000 through 2005. If the Tax Certiorari Proceedings result in areduction of the assessed value of the generating facility at issue in eachproceeding, the New York Debtor owning the facility would be entitled to arefund with interest of any excess taxes paid for those tax years.

On September 30, 2003, the Mirant Debtors filed amotion (the “Tax Determination Motion”) with the Bankruptcy Court requestingthat it determine what the property tax liability should have been for theBowline generating facility in each of the years 1995 through 2003 and for theLovett generating facility in each of the years 2000 through 2003. The basesfor the relief requested in the Tax Determination Motion on behalf of MirantBowline and Mirant Lovett were that the assessed values of the generatingfacilities made by the relevant taxing authorities had no justifiable basis andwere far in excess of their actual value. The local taxing authorities haveopposed the Tax Determination Motion, arguing that the Bankruptcy Court eitherlacks jurisdiction over the matters addressed by the Tax Determination Motionor should abstain from addressing those issues so that they can be addressed bythe state courts in which the Tax Certiorari Proceedings described in thepreceding paragraph were originally filed.

Collectively, MirantBowline and Mirant Lovett have not paid approximately $62 million assessed bylocal taxing authorities on the Bowline and Lovett generating facilities for2003, which fell due on September 30, 2003, and January 30, 2004,approximately $53 million assessed by local taxing authorities on thegenerating facilities for 2004 that fell due on September 30, 2004, and January 30,2005, and approximately $59 million assessed by local taxing authorities on thegenerating facilities for 2005 that fell due on September 30, 2005, and January 30,2006, in order to preserve their respective rights to offset the overpaymentsof taxes made in earlier years against the sums payable on account of current taxes.The failure to pay the taxes due on September 30, 2003, January 30,2004, September 30, 2004, January 30, 2005, September 30, 2005,and January 30, 2006 could subject Mirant Bowline and Mirant Lovett toadditional penalties and interest.

***Other Legal Matters***

The Company is involved invarious other claims and legal actions arising in the ordinary course ofbusiness. In the opinion of management, the ultimate disposition of thesematters will not have a material adverse effect on the Company’s financialposition, results of operations or cash flows.

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

None.

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**PART II**

**Item 5.**                        *Market for Registrant’s Common Equity, Related Stockholder Matters andIssuer 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 interestsare held by our parent, Mirant Americas. Since filing for protection underChapter 11, we have not paid dividends. We have no equity compensation plansunder which we issue our membership interests.

**Item6.**                        *Selected Financial Data*

Theinformation set forth below should be read in conjunction with “Management’sDiscussion and Analysis of Financial Condition and Results of Operations” andour historical combined and consolidated financial statements and the notesthereto, which are included elsewhere in this Form 10-K. Theselected financial data has been derived from our combined and consolidatedfinancial statements. See Note 1 to our combined and consolidatedfinancial statements for further discussion.

From the Petition Datethrough emergence, our combined and consolidated financial statements wereprepared in accordance with Statement ofPosition 90-7, “*Financial Reporting byEntities in Reorganization Under the Bankruptcy Code”*(“SOP 90-7”).Our Statement of Operations Data for the years ended December 31, 2004 and2003 does not include interest expense on debt that was subject to compromisesubsequent to the Petition Date. Our Statement of Operations Data for the yearended December 31, 2005, reflects the effects of accounting for the Planconfirmed on December 9, 2005. Forfurther discussion of the effects of the Plan, see Note 4 to our combinedand consolidated financial statements.

| ** **                         | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------|------------|---------------------------------------------|------------|
| ** **                         | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| **Statement of Operations Data:**  |       |                                        |       |   |   |   |   |   |   |   |   |
| Operating  revenues                |       | $                                           | 3,049      |   | $ | 3,568 |   | $ | 4,057 |   | $ | (3,611 | ) | $ | (6,651 | ) |
| Net (loss) income                  |       | (779                                        | )          | 106 |   | (3,209 | ) | (227 | ) | (754 | ) |
| **Balance Sheet Data:**            |       |                                        |       |   |   |   |   |   |   |   |   |
| Total Assets                       |       | 7,020                                       |       | 6,157 |   | 6,296 |   | 11,752 |   | 12,980 |   |
| Total long-term  debt              |       | 2,593                                       |       | 50 |   | 55 |   | 3,581 |   | 3,213 |   |
| Liabilities  subject to compromise |       | 34                                          |       | 5,366 |   | 5,350 |   | — |   | — |   |
| Equity (deficit)                   |       | $                                           | 703        |   | $ | (326 | ) | $ | (439 | ) | $ | (2,338 | ) | $ | (1,948 | ) |

 

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

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**Item 7.**                        *Management’s Discussion and Analysis of Financial Condition and Resultsof Operations*

This section is intended to provide the reader withinformation that will assist in understanding our financial statements, thechanges in those financial statements from year to year and the primary factorscontributing to those changes. The following discussion should be read inconjunction with our combined and consolidated financial statements and thenotes accompanying those financial statements.

***Overview***

We are a national independent power provider that produces and sellselectricity in the United States. On July 14,2003 (the “Petition Date”), and various dates thereafter, the Company and itssubsidiaries wereamong the 83direct and indirect Mirant subsidiaries in the United States (collectively, the“Mirant Debtors”), that filed with the United States BankruptcyCourt for the Northern District of Texas, Fort Worth Division (the “BankruptcyCourt”) voluntary petitions for relief under Chapter 11 of Title 11 of theUnited States Bankruptcy Code (as amendedthe “Bankruptcy Code”). We continued tooperate our business as a debtor-in-possession under the jurisdiction of theBankruptcy Court in accordance with Chapter 11 of the Bankruptcy Code. As a result, our financial statementsinclude the results of the bankruptcy process.

The Plan of Reorganization (the “Plan”) was confirmed by theBankruptcy Court on December 9, 2005, and we emerged from bankruptcy on January 3,2006. As a result, we recorded theeffects of the Plan in our financial statements for the year ended December 31,2005. We recognized a gain of $30 million, included in reorganization items,net related to the effects of the Plan. Among other things, we recognized thereinstatement of certain debt and settlement amounts of claims, all asprescribed by the Plan. See Notes 1 and 3 to our combined and consolidatedfinancial statements contained elsewhere in this report for additional discussionof the key elements of the Plan and Note 4 for the impacts of the Plan on ourcombined and consolidated financial statements for the year endedDecember 31, 2005.

Theprimary factors impacting the earnings and cash flows of our operations are theprices for power, natural gas and coal, which are largely driven by supply anddemand. The increase in new generation capacitythat followed the restructuring of the power markets in the late 1990’s hascreated an oversupply situation in most markets which is expected to continueuntil 2008 to 2010. The imbalance between supply and demand, price controlsduring periods of high demand and local constraint and lack of appropriatecompensation for locational capacity value limit our ability to recover ourfixed costs such that we must rely almost entirely on energy grossmargins produced by generating electrical energy for a price greater than thecost of the fuel required to run the plants.Demand for power can also vary regionally and seasonally due to, among otherthings, weather and general economic conditions. Power supplies similarly varyby region and are impacted significantly by available generating capacity,transmission capacity and federal and state regulation. We also are impacted bythe relationship between prices for power and fuel, such as natural gas, coaland oil that impact our cost of generating electricity.

Weengage in asset hedging activities to economically hedge our positions in orderto reduce our exposure to commodity price fluctuations and to achieveacceptable gross margins. In general, we currently economically hedge asubstantial portion of our Mid-Atlantic coal fired generation and our NewEngland oil fired generation through over-the-counter transactions. However, wegenerally do not hedge most of our cycling and peaking capacity due to thelimited value we can extract in the marketplace and the high cost of collateraltypically required to support these contracts. Many of the power and fuelcontracts that we use to economically hedge our portfolio meet the criteria ofa derivative and are accounted for at fair value in our combined andconsolidated balance sheets. Changes in the fair value represent unrealizedgains and losses and result in income volatility when the underlying energyprices are volatile. We currently economically hedge a substantial portion ofour Mid-Atlantic coal fired baseload generation (generation that is dispatchedmost of the time) and our New England oil fired generation throughover-the-counter transactions. However, we generally do not hedge most of ourcycling and peaking units (generating facilities that are not dispatched asfrequently) due to the limited value we can extract in the marketplace and thehigh cost of collateral typically required to support these contracts. As of March 3,2006, we have 

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economically hedged approximately 90%, 60%, 30%, and30% of our expected Mid-Atlantic coal fired generation for the remainder of2006, 2007, 2008 and 2009, respectively, and purchased approximately 100%, 80%,30% and 30% of the expected Mid-Atlantic coal requirements for such periods.Included in such amounts are financial swap transactions entered into by MirantMid-Atlantic with a counterparty in January 2006 pursuant to which MirantMid-Atlantic economically hedged approximately 80%, 50%, and 50% of itsexpected on-peak coal fired baseload generation for 2007, 2008 and 2009,respectively. The financial swap transactions are senior unsecured obligationsof Mirant Mid-Atlantic and do not require us to post cash collateral either inthe form of initial margin or to secure exposure due to changes in powerprices. In addition, as of March 3, 2006, we have economically hedgedapproximately 50% of our expected oil fired generation in New England for theremainder of 2006 and procured approximately 50% of the corresponding expectedoil requirements.

Our business is subject to extensive environmentalregulation by federal, state and local authorities. This requires us tocomply with applicable laws and regulations, and to obtain and comply with theterms of government issued operating permits.Our costs of complying with environmental laws, regulations and permits aresubstantial. We estimate that our capital expenditures for environmentalcompliance will be approximately $300 million for 2006 and will be $1billion to $1.5 billion for 2006 through 2011. Our potential capitalexpenditures for environmental regulations are difficult to estimate because wecannot now assess what regulations may be applicable or what costs might beassociated with the regulation. Our actualcapital expenditures will be materially impacted if the State of Marylandpasses legislation or imposes regulations that increase beyondapplicable federal law the restrictions on emissions of SO2, NOx and mercury,or imposes restrictions on emissions of CO2. This legislation or regulation, orsimilar legislation or regulation in other states or by the federal government,may render some of our units uneconomic.

A significant portion of our capital resources, in theform of cash and letters of credit is needed to satisfy counterparty collateralrequirements. These counterparty collateral requirements reflect ournon-investment grade credit ratings, volatile energy prices, generally highermargin levels in the industry and other factors. Whenever feasible, we seek tostructure transactions in a way that reduces our potential liquidity needs forcollateral.

**BankruptcyConsiderations**

While in bankruptcy, our financial results werevolatile as asset impairments, asset dispositions, restructuring activities,contract terminations and rejections, and claims assessments significantlyimpacted our combined and consolidated financial statements. As a result, ourhistorical financial performance is likely not indicative of our financialperformance post-bankruptcy.

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**Resultsof Operations**

Our gross margins andexpenses from affiliates and nonaffiliates aggregated by classification are asfollows (in millions): 

| ** **                                            | ** ** | **Years Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                            | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **Increase/  (Decrease)** | ** ** | **2004** | ** ** | **2003** | ** ** | **Increase/  (Decrease)** | ** ** |
| Gross Margin                                          |       |                                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Affiliate                                             |       | $                                           | (20        | ) | $ | 325 |   |   | $ | (345 | ) |   | $ | 325 |   | $ | (218 | ) |   | $ | 543 |   |   |
| Nonaffiliate                                          |       | 901                                         |       | 803 |   |   | 98 |   |   | 803 |   | 1,315 |   |   | (512 | ) |   |
| Total gross margin                                    |       | 881                                         |       | 1,128 |   |   | (247 | ) |   | 1,128 |   | 1,097 |   |   | 31 |   |   |
| Operating Expenses:                                   |       |                                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Generation facilities  rent                           |       | 99                                          |       | 103 |   |   | (4 | ) |   | 103 |   | 96 |   |   | 7 |   |   |
| Depreciation and  amortization                        |       | 132                                         |       | 129 |   |   | 3 |   |   | 129 |   | 167 |   |   | (38 | ) |   |
| Operations and maintenance                            |       |                                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Affiliate                                             |       | 301                                         |       | 338 |   |   | (37 | ) |   | 338 |   | 254 |   |   | 84 |   |   |
| Nonaffiliate                                          |       | 289                                         |       | 250 |   |   | 39 |   |   | 250 |   | 298 |   |   | (48 | ) |   |
| (Gain) loss on sales of  assets, net                  |       | 1                                           |       | 65 |   |   | (64 | ) |   | 65 |   | (18 | ) |   | 83 |   |   |
| Impairment loss                                       |       | —                                      |       | 2 |   |   | (2 | ) |   | 2 |   | 3,030 |   |   | (3,028 | ) |   |
| Total operating expenses                              |       | 822                                         |       | 887 |   |   | (65 | ) |   | 887 |   | 3,827 |   |   | (2,940 | ) |   |
| Operating income (loss)                               |       | 59                                          |       | 241 |   |   | (182 | ) |   | 241 |   | (2,730 | ) |   | 2,971 |   |   |
| Other (expense) income , net                          |       |                                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Affiliate                                             |       | (23                                         | )          | (8 | ) |   | (15 | ) |   | (8 | ) | 5 |   |   | (13 | ) |   |
| Nonaffiliate                                          |       | (707                                        | )          | 7 |   |   | (714 | ) |   | 7 |   | (227 | ) |   | 234 |   |   |
| Reorganization items,  net                            |       | 87                                          |       | 149 |   |   | (62 | ) |   | 149 |   | 115 |   |   | 34 |   |   |
| Provision (benefit) for  income taxes                 |       | 5                                           |       | (15 | ) |   | 20 |   |   | (15 | ) | 111 |   |   | (126 | ) |   |
| Income from discontinued  operations                  |       | —                                      |       | — |   |   | — |   |   | — |   | (21 | ) |   | 21 |   |   |
| Cumulative effect of  change in accounting principles |       | (16                                         | )          | — |   |   | (16 | ) |   | — |   | (10 | ) |   | 10 |   |   |
| Net (Loss) Income                                     |       | $                                           | (779       | ) | $ | 106 |   |   | $ | (885 | ) |   | $ | 106 |   | $ | (3,209 | ) |   | $ | 3,315 |   |   |

 

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In the tables below, the Mid-Atlantic region includesour Morgantown, Chalk Point, Dickerson and Potomac River facilities. TheNortheast region includes our New England and New York facilities. The Westregion includes Mirant Texas, Mirant California and Mirant Zeeland. EnergyMarketing includes Mirant Americas Energy Marketing and the other TradingDebtors. Eliminations includes the elimination of intercompany transactionsbetween Mirant Americas Generation subsidiaries.

Thefollowing table summarizes capacity factor (average percentage of full capacityused over a year) by region for the years ended December 31, 2005, 2004and 2003:

| ** **   | ** ** | **Years Ended December 31,** | ** ** |
|--------------|------------|---------------------------------------------|------------|
| ** **   | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **Increase/  (Decrease)** | ** ** | **2004** | ** ** | **2003** | ** ** | **Increase/  (Decrease)** | ** ** |
| Mid-Atlantic |       |                                        | 39         | % |   |   | 40 | % |   |   | (1 | )% |   |   | 40 | % |   |   | 42 | % |   |   | (2 | )% |   |
| Northeast    |       |                                        | 34         | % |   |   | 33 | % |   |   | 1 | % |   |   | 33 | % |   |   | 31 | % |   |   | 2 | % |   |
| West         |       |                                        | 21         | % |   |   | 15 | % |   |   | 6 | % |   |   | 15 | % |   |   | 9 | % |   |   | 6 | % |   |

 

Thefollowing table summarizes power generation volumes by region for the yearsended December 31, 2005, 2004 and 2003 (in gigawatt hours):

| ** **   | ** ** | **Years Ended December 31,** | ** ** |
|--------------|------------|---------------------------------------------|------------|
| ** **   | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **Increase/  (Decrease)** | ** ** | **2004** | ** ** | **2003** | ** ** | **Increase/  (Decrease)** | ** ** |
| Mid-Atlantic |       | 18,200                                      |       | 18,712 |   |   | (512 | ) |   | 18,712 |   | 19,500 |   |   | (788 | ) |   |
| Northeast    |       | 9,184                                       |       | 8,831 |   |   | 353 |   |   | 8,831 |   | 8,492 |   |   | 339 |   |   |
| West         |       | 3,961                                       |       | 4,968 |   |   | (1,007 | ) |   | 4,968 |   | 4,400 |   |   | 568 |   |   |
| Total        |       | 31,345                                      |       | 32,511 |   |   | (1,166 | ) |   | 32,511 |   | 32,392 |   |   | 119 |   |   |

 

*2005 versus 2004*

*Grossmargin.**  *Our*g*ross margin decreased $247 million in 2005 compared to2004.

Thefollowing table summarizes the realized and unrealized gross margin for theyear ended December 31, 2005 compared to same period in 2004 (inmillions):

| ** **       | ** ** | **Years Ended December 31,** | ** ** |
|------------------|------------|---------------------------------------------|------------|
| ** **       | ** ** | **2005**                                    | ** ** | **2004** | ** ** |
| ** **       | ** ** | **Realized**                                | ** ** | **Unrealized** | ** ** | **Total** | ** ** | **Realized** | ** ** | **Unrealized** | ** ** | **Total** | ** ** |
| Mid-Atlantic     |       |                                        | $          | 552 |   |   |   | $ | (97 | ) |   | $ | 455 |   |   | $ | 576 |   |   |   | $ | (75 | ) |   | $ | 501 |   |
| Northeast        |       |                                        | 225        |   |   |   | (11 | ) |   | 214 |   |   | 218 |   |   |   | 31 |   |   | 249 |   |
| West             |       |                                        | 146        |   |   |   | 2 |   |   | 148 |   |   | 179 |   |   |   | (2 | ) |   | 177 |   |
| Energy Marketing |       |                                        | (30        | ) |   |   | 85 |   |   | 55 |   |   | 1 |   |   |   | 213 |   |   | 214 |   |
| Eliminations     |       |                                        | 9          |   |   |   | — |   |   | 9 |   |   | (13 | ) |   |   | — |   |   | (13 | ) |
| Total            |       |                                        | $          | 902 |   |   |   | $ | (21 | ) |   | $ | 881 |   |   | $ | 961 |   |   |   | $ | 167 |   |   | $ | 1,128 |   |

 

Thefollowing table summarizes the change in realized and unrealized gross marginfor the year ended December 31, 2005 compared to same period in 2004 (inmillions):

| ** **       | ** ** | **Years Ended December 31,** | ** ** |
|------------------|------------|---------------------------------------------|------------|
| ** **       | ** ** | **2005 vs. 2004**                 | ** ** |
| ** **       | ** ** | **Realized**                                | ** ** | **Unrealized** | ** ** | **Total** | ** ** |
| Mid-Atlantic     |       |                                        | $          | (24 | ) |   |   | $ | (22 | ) |   | $ | (46 | ) |
| Northeast        |       |                                        | 7          |   |   |   | (42 | ) |   | (35 | ) |
| West             |       |                                        | (33        | ) |   |   | 4 |   |   | (29 | ) |
| Energy Marketing |       |                                        | (31        | ) |   |   | (128 | ) |   | (159 | ) |
| Eliminations     |       |                                        | 22         |   |   |   | — |   |   | 22 |   |
| Total            |       |                                        | $          | (59 | ) |   |   | $ | (188 | ) |   | $ | (247 | ) |

 

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The$247 million decrease in gross margin is detailed as follows (in millions):

| ** **                                                         | ** ** | **Mid-Atlantic** | ** ** | **Northeast** | ** ** | **West** | ** ** | **Energy  Marketing** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|--------------------------------------------------------------------|------------|------------------|------------|---------------|------------|----------|------------|-----------------------|------------|------------------|------------|-----------|------------|
| Market prices-power                                                |       |             | $          | 570           |       |     |       | $                     | 290        |             |       | $         | —     |   |   | $ | — |   |   |   | $ | — |   |   | $ | 860 |   |
| Market  prices-fuel                                                |       |             | (152       | )             |       |     | (188       | )                     |       | —           |       |      | —     |   |   |   | — |   |   | (340 | ) |
| Ancillary  services                                                |       |             | 44         |          |       |     | 2          |                  |       | —           |       |      | —     |   |   |   | — |   |   | 46 |   |
| Generation  volumes                                                |       |             | (61        | )             |       |     | (11        | )                     |       | —           |       |      | —     |   |   |   | — |   |   | (72 | ) |
| Realized economic  hedges                                          |       |             | (414       | )             |       |     | (71        | )                     |       | (29              | )          |      | —     |   |   |   | — |   |   | (514 | ) |
| Installed  capacity, RMR and tolling agreements tolling agreements |       |             | (9         | )             |       |     | (2         | )                     |       | (19              | )          |      | —     |   |   |   | — |   |   | (30 | ) |
| Emissions  allowances                                              |       |             | (14        | )             |       |     | (9         | )                     |       | —           |       |      | —     |   |   |   | 19 |   |   | (4 | ) |
| Unrealized  gains/losses                                           |       |             | (22        | )             |       |     | (42        | )                     |       | 4                |       |      | (193       | ) |   |   | — |   |   | (253 | ) |
| Other                                                              |       |             | 12         |          |       |     | (4         | )                     |       | 15               |       |      | 34         |   |   |   | 3 |   |   | 60 |   |
| Total                                                              |       |             | $          | (46           | )          |     |       | $                     | (35        | )                |       | $         | (29        | ) |   | $ | (159 | ) |   |   | $ | 22 |   |   | $ | (247 | ) |

 

Mid-Atlanticoperations gross margin decreased $46 million primarily due to thefollowing:

·       anincrease of $570 million driven by higher market prices for power. Spot marketprices for power were higher during the year ended December 31, 2005,compared to the same period in 2004. Average settlement prices increased 63%;

·       adecrease of $152 million related to higher fuel prices during the period.Average prices for fuel increased as follows: gas 60%, coal 17% and oil 57%;

·       anincrease of $44 million related to an increase in prices for ancillaryservices, consistent with increased energy prices;

·       adecrease of $61 million related to generation volumes. Volumes decreasedby 2.7%, which had an unfavorable effect of $14 million on gross margin basedon average revenue and fuel costs per MWh in 2004. Also included is anunfavorable impact of $47 million due to a change in the mix of generation,with increases in volumes by the more expensive gas and oil fired units and aslight decrease in the generation volumes by the coal fired units. Volumes wereimpacted by significant unplanned outages primarily related to baseload units;

·       adecrease of $414 million due to losses on economic hedges compared to 2004related primarily to the impact of rising energy prices on the realizedeconomic hedges of our generation output during the 2005 period;

·       adecrease of $9 million related to a reduction in revenue due to lower pricesfor installed capacity as a result of the expansion of the PJM market;

·       adecrease of $14 million due to increased emissions expense of $19 million,partially offset by higher emissions revenue of $5 million. Prices for SO2 andNOx emissions allowances increased in 2005 compared to the same period in 2004;

·       adecrease of $22 million related to losses of $97 million in the year ended December 31,2005 on unrealized derivative contracts for future years, compared to losses of$75 million for the same period in 2004. As power prices increased during 2005,we recognized losses on short power positions used to hedge the expected outputof our power plants in future years. These losses on unrealized power hedgeswere greater in 2005 than in 2004, but were partly offset by the settlement ofhedges that had a negative value at the start of the year and by a gain in 2005on unrealized fuel hedges for future years, compared to a loss for the sameperiod in 2004; and

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·       anincrease of $12 million in other primarily due to a $13 million net settlementwith a coal supplier related to rail car transportation schedule issues thatresulted in lower fuel expense.

Northeast operations gross margin decreased $35 million primarily due tothe following:

·       anincrease of $290 million driven by higher market prices for power. Spot marketprices for power were higher during the year ended December 31, 2005compared to the same period in 2004. Average settlement prices increased 63% inNew York and 49% in New England. In 2005, we received $5 million from the NYISOrelated to adjustments from 2000-2003;

·       adecrease of $188 million related to higher fuel prices during the period.Average prices for fuel in New York increased as follows: gas 37%, coal 25%,and oil 56%. Residual oil prices increased 48% and gas prices increased by 42%in New England;

·       anincrease of $2 million related to an increase in prices for ancillary services,consistent with increased energy prices;

·       adecrease of $11 million related to an increase in generation volumes. Thisincremental generation has a favorable impact of $5 million on gross marginwhich is offset by an unfavorable variance of $16 million due to a change inthe mix of generation, with increases in volumes by the more expensive gasfired units and a slight decrease in the generation volumes by the coal firedunits;

·       adecrease of $71 million related primarily to the impact of rising energy priceson the realized economic hedges of our generation output, partly offset by theimpact of rising fuel prices on the realized economic hedges of our fuelrequirements during the period;

·       adecrease of $2 million that reflects lower revenues at New York of $11 milliondue to lower prices for installed capacity. This was partially offset byincreased revenues in New England of $9 million due to the Kendall RMRagreement;

·       adecrease of $9 million due to reduced sales of surplus emissions allowances tothe Mid-Atlantic facilities;

·         a decrease of $42 million related to lossesof $11 million in the year ended December 31, 2005 on unrealizedderivative contracts for future periods, compared to a gain of $31 million forthe same period in 2004. As power prices increased during 2005, we recognizedlosses on power sales contracts used to hedge the expected output of our powerplants in future years. These losses on unrealized power hedges for futureperiods were greater in 2005 than in 2004, but were partly offset by increasedgains on unrealized fuel hedges for future periods. In addition, the hedgessettled in 2005 had a net favorable value at the beginning of the year and thiscontributed to the reduction in value of unrealized derivative contracts. In2004 the settlement of hedges with a net unfavorable value at the beginning of2004 had the effect of increasing the value of derivative contracts for futureperiods; and

·       a decrease of $4 million in other which includes adecrease in gas sales and transport of $6 million offset by additional receiptsin 2005 of $5 million in insurance proceeds related to an outage at the Bowlinefacility in 2004, compared to $2 million of proceeds received in 2004.

West operationsgross margin decreased $29 million primarily due to the following:

·       adecrease of $29 million related to reduced merchant generation and the impactof rising energy prices on the realized economic hedges of our generationoutput, partly offset by the impact of rising fuel prices on the realizedeconomic hedges of our fuel requirements during the period;

·       adecrease of $19 million which includes a decrease of $32 million related to theexpiration of an RMR contract for one of our California generating facilitiesin 2004 partially offset by capacity 

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income from tollingagreements on those California assets not covered by RMR and our facility inTexas and an increase of $13 million related to capacity income from a tollingagreement at the Zeeland facility;

·       an increase of $4 millionrelated to a decrease in net unrealized gains on derivative contracts forfuture periods; and

·       an increase of $15 million in other primarily dueto lower gas transport costs and reduced losses on gas sales. Under the newpower purchase agreements entered into early in 2005, PG&E is responsiblefor purchasing the fuel for most of the California units. See “Item 1.Business” for further discussion.

Energy Marketinggross margin decreased $159 million primarily due to the following:

·       an increase of $304 in realized gross margin, which includes a decreaseof $226 million in realized losses on the transition power agreements (“TPAs”)and $19 million decrease in realized losses on the Back-to-Back Agreement.

·       a decrease of $335 million primarily related to amortization of the TPAs.The Maryland TPA expired in June 2004 and the DC TPA expired in January 2005.TPA amortization was $9 million at December 31, 2005 and $344 million forthe same period in 2004;

·       a decrease of $57 millionrelated to a decrease in net unrealized gains on derivative contracts forfuture periods; and

·       adecrease of $71 million related to an increase in unrealized losses on theBack-to-Back agreement. The Back-to-Back agreement was transferred to MirantPower Purchase, LLC (“Mirant Power Purchase”), a wholly owned subsidiary ofMirant Americas, Inc.

Eliminations grossmargin increased by $22 million primarily due to the following:

·       anincrease of $19 million due to the elimination of a gain on intercompany SO2emissions allowances transfers in 2004 and the elimination of the relatedexpense recorded in 2005.

*Operations and maintenance.  **Operations and maintenance expens*esincreased by $2 million primarily due to:

·       anincrease of $21 million in maintenance expenditures of which $8 million isrelated to maintenance on the dam at Swinging Bridge, $5 million is related toenvironmental remediation costs at the Lovett and Hillburn facilities and $11million is due to increased maintenance at Mid-Atlantic, which includes $3million related to the unplanned outages at the Morgantown and Chalk Pointfacilities and $2 million related to the Potomac River downwash project. See “Item1. Business” for further discussion;

·       anincrease of $10 million due to a reduction recorded in 2004 in the reserverelated to receivables from Enron;

·       anincrease of $8 million related to the property tax settlements of certainCalifornia and New York generation assets in 2004;

·       anincrease of $5 million due to an increase in the reserve for obsolete spareparts inventory; and

·       adecrease of $37 million in operations and maintenance-affiliate primarily dueto a $35 million reduction in corporate overhead allocations from MirantServices.

*(Gain) loss on sales of assets*.  (Gain) loss on sales of assets decreased $64million primarily due to a loss in 2004 related to the sale of three naturalgas combustion turbines.

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*Other (expense) income,net.**  *Other (expense)income, net increased $729 million primarily due to the recognition of $746million of interest on liabilities subject to compromise for the period fromthe Petition Date through December 31, 2005. This was offset by a gain of$44 million related to the 2005 sale of a portion of our investment in acompany that provides an electronic commerce platform for the purchase and saleof energy commodities. See Note 2 to our combined and consolidated financialstatements contained elsewhere in this report for further discussion.

*2004 versus 2003*

*Grossmargin.**  *Grossmargin increased $31 million in 2004, primarily due to the following:

Thefollowing table summarizes gross margin by region for the years ended December 31,2004 and 2003 (in millions):

| ** **       | ** ** | **Years Ended December 31,** | ** ** |
|------------------|------------|---------------------------------------------|------------|
| ** **       | ** ** | **2004**                                    | ** ** | **2003** | ** ** | **Increase/  Decrease** | ** ** |
| Mid-Atlantic     |       | $                                           | 501        |   | $ | 400 |   |   | $ | 101 |   |   |
| Northeast        |       | 249                                         |       | 143 |   |   | 106 |   |   |
| West             |       | 177                                         |       | 211 |   |   | (34 | ) |   |
| Energy Marketing |       | 214                                         |       | 365 |   |   | (151 | ) |   |
| Eliminations     |       | (13                                         | )          | (22 | ) |   | 9 |   |   |
| Total            |       | $                                           | 1,128      |   | $ | 1,097 |   |   | $ | 31 |   |   |

 

·       Mid-Atlantic operationsgross margin increased $101 million primarily due to the termination ofthe Energy and Capacity Sales Agreement (“ECSA”) with Mirant Americas EnergyMarketing in May 2003. Revenues received under the ECSA in 2003 were$110 million less than what would have been received from the PJM spotmarket. Excluding the impact of the ECSA,Mid-Atlantic gross margin would have been $9 million lower in 2004 than in2003, primarily due to the following:

·        an increase ofapproximately $44 million driven by higher market prices for power;

·        anincrease of $64 million related to an increase in prices for capacity andancillary services;

·        an increase of $15 milliondue to gains on realized power hedges;

·        a decrease ofapproximately $68 million related to net unrealized losses on derivativecontracts for future periods. Of these contracts, $58 million related to powerand $10 million related to oil and gas, and were entered into to economicallyhedge a portion of the energy price risk related to future Mid-Atlanticoperations. The decrease in value of these energy derivative contracts is dueto an increase in forward power prices;

·        adecrease of $14 million related to a higher emissions expense due mainly tohigher prices for SO2 emissions allowances. In order for us to meet our currentneeds to operate our generation facilities we had to purchase additionalemissions allowances. The average price of emissions allowances increased 136%from $180 per ton in 2003 to $425 per ton in 2004;

·        adecrease of $8 million due to lower generation volumes;

·        adecrease of $13 million due to higher coal prices, partly offset by lower oiland gas prices;

·        adecrease of $16 million related to a reduction in realized gains on economicfuel hedges; and

·        a decrease of $11 millionrelated to the termination of contracts in 2004.

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·       Northeastoperations gross margin increased $106 million primarily due to the following:

·        an increase of $43 million related to netunrealized gains on derivative instruments of approximately $31 million in 2004compared to $12 million in net unrealized losses in 2003;

·        an increase of $27 million due to certain forced outages and transmissionline problems in 2003 that did not recur in 2004;

·        an increase of $22 million in our realized economic hedging margin due tothe impact of 2003 short positions on power in a market where prices for powerwere rising; and

·        an increase of $16 million due to the impact ofintercompany emissions allowance sales.

·       Westoperations reflects a reduction in gross margin of $34 million for ourgeneration units in California, Texas and Michigan.

·        a decrease of $3 million in California primarily due to a decrease in gains onrealized economic hedges of $22 million as a result of reduced economichedging activity offset by $18 million of savings on gas reservation chargesfollowing a contract rejection;

·        adecrease of $16 million in Texas primarily due to lower energy prices and a newtolling agreement that began in August 2004 with a third party that is atlower prices than what these units received under a prior agreement with MirantAmericas Energy Marketing; and

·        adecrease of $16 million at our Zeeland facility primarily related to purchasingpower in the market rather than running the generation facility to serve loaddeals in 2004.

·       EnergyMarketing gross margin decreased $151 million primarily due to the following:

·        a decrease of $80 million related to amortization of the TPAs due to theexpiration of the Maryland TPA in June 2004 resulting in loweramortization and the impact of a late contract change in 2003. The DC TPAexpired in January 2005 (as actual MWhs are purchased or sold under theseagreements we amortize a ratable portion of the obligation as an increase inrevenue);

·        a decrease of $3 millionin unrealized gains on the Back-to-Back agreement, which were $168 million and$171 million in 2004 and 2003, respectively;

·        a decrease of $19 million as a result of an increase in realized losseson the TPA. Realized losses for 2004 and 2003 were $234 million and $215million, respectively;

·        a decrease of $44 million as a result of an increase in realized losseson the PPA, which were $96 million and $52 million in 2004 and 2003,respectively; and

·        adecrease of $333 million in energy marketing realized trading partially offsetby an increase of $329 million related to net unrealized losses on derivativeinstruments. Gross margin for the year ended December 31, 2003, reflectsunrealized losses offset by realized gross margin related to energy contractsterminated by counterparties as a result of our Chapter 11 filings. As a resultof the termination of these contracts the unrealized gains on these contractsbecame realized in 2003.

*Operating expenses.**  *Operating expenses decreased $2,940 million primarilydue to the following:

·       anincrease of $7 million in generation facilities rent related to the additionalrent expense for our Morgantown and Dickerson baseload units as a result of theBankruptcy Court’s granting the motion compelling us to pay incremental rent in2004. See Note 16 contained elsewhere in this report for further discussion.

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·       adecrease of $38 million in depreciation and amortization expense primarily dueto lower depreciation expense related to our property, plant and equipmentafter our $1,088 million impairment of long-lived assets in the fourthquarter of 2003;

·       an increase of $84 millionin operations and maintenance-affiliate related to an increase of $111 millionin our corporate overhead allocations from Mirant Services and a decrease of$27 million related to our serviceagreements with Mirant Services for management, personnel and services; and

·       adecrease of $48 million in operations and maintenance-nonaffiliate primarilydue to the following:

·        anincrease of $13 million related to the Commodity Futures TradingCommission (“CFTC”) settlement in December 2004. See Note 14 to ourcombined and consolidated financial statements contained elsewhere in thisreport;

·        a decrease of $10 million due to a reduction inthe allowance related to receivables from Enron;

·        adecrease of $8 million related to lower property taxes due to settlementsrelated to certain California and New York generation facilities; and

·        adecrease of $32 million related to an energy marketing customer bad debtexpense reflected in 2003;

·       anincrease of $83 million in loss on sales of assets, net primarily related to a$65 million loss on the sale of three natural gas combustion turbines atBowline 3 in 2004 as compared to a $15 million gain related to the sale of firmtransportation agreements and $3 million gain on the sale of crude oil at oneof our California facilities in 2003;

·       decreaseof $3,028 million for impairment losses comprised of the following:

·        adecrease of $1,940 million for goodwill impairment charges related to theimpairment of goodwill in 2003. For further discussion, see “CriticalAccounting Policies and Estimates” and Note 9 to our combined and consolidatedfinancial statements contained elsewhere in this report;

·        adecrease of $1,088 million for long-lived asset impairment losses due to animpairment of $1,090 recorded in 2003 for several of our assets. For furtherdiscussion, see “Critical Accounting Policies and Estimates” and Note 8 andNote 9 to our combined and consolidated financial statements containedelsewhere in this report.

*Other income (expense),net.**  *Otherincome (expense), net increased $221 million primarily due to suspension ofaccruals for interest expense after the Petition Date.

**Financial Condition**

***Liquidity and Capital Resources***

During the pendency of the Chapter 11 proceedings wesatisfied our liquidity and capital requirements with cash from operations anda $500 million Mirant debtor-in-possession credit facility that was approved bythe Bankruptcy Court and which provided for borrowings or the issuance ofletters of credit. The Chapter 11 proceedings resulted in various restrictionson our activities, including limitations on financing, and the implementationof a centralized cash management system that provided for the collection,concentration and disbursement of funds. The Chapter 11 proceedings also causeduncertainty in our relationships with vendors, suppliers, customers and otherswith whom we conducted or sought to conductbusiness. During the Chapter 11 proceedings, we typically posted cashcollateral with counterparties. Going forward, we expect relationshipswith vendors, suppliers, customers, counterparties and others to return tonormal industry practices, including the posting of letters of credit insteadof cash collateral.

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***Emergence from Bankruptcy***

On December 23, 2005,our subsidiary Mirant North America issued a note offering for $850 million of7.375% senior unsecured notes due 2013. The funds from this issuance wereinitially placed in escrow and were released from escrow on January 3,2006, upon consummation of the Plan. On January 3, 2006, Mirant NorthAmerica entered into an $800 million senior secured revolving credit facilityand a $700 million senior secured term loan. In connection with the closing,$200 million of drawings under the senior secured term loan were deposited intoa cash collateral account to support the issuance of up to $200 million ofletters of credit issued under the senior secured term loan.

***Sources of Funds and Capital Structure***

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

Our operating cash flows may be impacted by, amongother things: (i) the difference between the cost of a specific fuel usedto generate one megawatt hour of electricity and the market value of theelectricity generated (“conversion spread”); (ii) commodity prices(including prices for natural gas, coal, oil and electricity); (iii) thecost of ordinary course operations and maintenance expenses; (iv) plannedand unplanned outages; (v) contraction of terms by trade creditors; and (vi) cashrequirements for capital expenditures relating to certain facilities (includingthose necessary to comply with environmental regulations).

We and certain of oursubsidiaries, including Mirant North America, are holding companies and as aresult, we are dependent upon dividends, distributions and other payments fromour subsidiaries to generate the funds necessary to meet our obligations. Theability of certain of our subsidiaries to pay dividends and distributions isrestricted under the terms of their debt or other agreements. We have nooperations and no subsidiaries with operations other than Mirant North Americaand its subsidiaries, including Mirant Mid-Atlantic. The Mirant North Americanotes and senior secured credit facilities restrict its ability to makedistributions. In addition, under the Mirant Mid-Atlantic leveraged leases,Mirant Mid-Atlantic, which generates a significant portion of our cash fromoperations, is subject to a covenant that restricts its right to makedistributions to us and Mirant North America. Mirant Mid-Atlantic’s ability tosatisfy these ratio tests in the future could be impaired by factors whichnegatively affect the performance of its power generation facilities, includinginterruptions in operation such as the recent temporary shutdown and continuingcurtailment of operations of the Potomac River generation facility.

***Reinstated Senior Notes***

As part of the Plan, we reinstated senior notes of$1.7 billion maturing in 2011, 2021 and 2031 and agreed to pay $452 million ofaccrued interest.

*InterestRate; Maturity Date; Redemption Rights.**  *The notes, which mature on May 1, 2011, October 1,2021, and May 1, 2031, were issued in aggregate principal amounts of $850million, $450 million and $400 million and bear interest at 8.3%, 8.5%, and9.125%, respectively. Interest on the 2021 notes is payable on each April 1and October 1 and interest on the 2011 notes and 2031 notes is payable oneach May 1 and November 1.

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At any time and at our option, we may redeem the notesof each series, in whole or in part (if in part, by lot or by such other methodas the trustee shall deem fair or appropriate) at the redemption price of 100%of principal amount of such notes, plus accrued interest on the principalamount of such notes, if any, to the redemption date, plus the make-wholepremium for such notes. The make-whole premium is calculated as follows: (i) theaverage life of the remaining scheduled payments of principal in respect ofoutstanding notes of such series (the “Remaining Average Life” of the notes ofsuch series) as of the redemption date; (ii) the yield to maturity for theUnited States treasury security having an average life equal to the RemainingAverage Life of the notes of such series and trading in the secondary market atthe price closest to the principal amount thereof (the “Primary Issue” for thenotes of such series) (subject to extrapolation if no United States treasurysecurity has an average life equal to the Remaining Average Life of the notesof such series); and (iii) the discounted present value of thethen-remaining scheduled payments of principal and interest (but excluding thatportion of any scheduled payment of interest that is actually due and paid onthe redemption date) in respect of outstanding notes of such series as of theredemption date using a discount factor equal to the sum of (x) the yieldto maturity for the Primary Issue for the notes of such series, plus (y) 25basis points for the 2011 notes, 37.5 basis points for the 2021 notes, and 37.5basis points for the 2031 notes. The amount of make-whole premium in respect ofnotes to be redeemed shall be an amount equal to (x) the discountedpresent value of such notes to be redeemed determined in accordance with clause(iii) above, minus (y) the unpaid principal amount of such new notes;provided, however*,* that the make-whole premium shallnot be less than zero.

*Ranking.**  *The notes are senior unsecured obligations of theCompany, and are not secured by any of our affiliates or subsidiaries. Thus,the notes are structurally subordinated to all existing and future liabilitiesof Mirant North America and its subsidiaries, including the indebtednessdescribed below under “Mirant North America” and the obligations under theMirant Mid-Atlantic leveraged leases described below under “Mirant Mid-AtlanticOperating Leases.”

*Certain covenants.**  *The notes are issued under an indenture that limitsour ability to:

·       incur,assume or guarantee additional indebtedness, or permit its subsidiaries toincur, assume or guarantee indebtedness;

·       createliens;

·       sellassets; and

·       merge,consolidate or sell or otherwise dispose of all or substantially all of ourassets.

These covenants are subject to a number of importantexceptions and qualifications.

***Mirant North America***

As contemplated by thePlan, our subsidiary Mirant North America, entered into senior secured creditfacilities (the “senior secured credit facilities”) with a syndicate of banks,financial institutions and other entities, including JPMorgan Chase Bank, N.A.,Deutsche Bank Trust Company Americas and Goldman Sachs Credit Partners L.P., aslenders (the “Lenders”), and, together with Mirant North America Finance Corp.,a subsidiary of Mirant North America, has issued $850 million aggregateprincipal amount of 7.375% senior unsecured notes due 2013 (the “notes”).

*Senior SecuredCredit Facilities*

The Mirant North America senior secured creditfacilities are comprised of an $800 million six-year senior secured revolvingcredit facility and a $700 million seven-year senior secured term loan. Thefull amount of the senior secured revolving credit facility is available forthe issuance of letters of credit. The senior secured term loan was made in asingle drawing at closing and will amortize in nominal quarterly installmentsaggregating 0.25% of the original principal of the term loan per quarter forthe first 27 

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quarters, with theremainder payable on the final maturity date. In connection with the closing,$200 million of drawings under the senior secured term loan were deposited intoa cash collateral account to support the issuance of up to $200 million ofletters of credit issued under the senior secured term loan.

*Interestrates.**  *Loans under the senior secured creditfacilities are available at either of the following rates: (i) afluctuating rate of interest per annum equal to on any given day the greater of(a) the interest rate per annum publicly announced by JPMorgan Chase Bank,N.A. as its prime rate in effect at its principal office in New York City onthat day, and (b) the federal funds rate in effect on that day plus 0.50%,plus the applicable margin described below (“base rate”), or (ii) a fixedrate determined for certain interest periods selected equal to U.S. dollarLondon InterBank Offered Rate (“LIBOR”) plus the applicable margin describedbelow (“Eurodollar rate”).

The applicable margin with respect to loans under thesenior secured revolving credit facility is 1.25% in the case of base rateloans, or 2.25% in the case of Eurodollar rate loans. The applicable marginwill also be subject to a possible reduction of up to 0.50% based on theachievement and maintenance of certain leverage ratios by Mirant North America.The applicable margin with respect to the senior secured term loan is 0.75% inthe case of base rate loans, or 1.75% in the case of Eurodollar rate loans.

*Guarantees;Ranking and security.**  *The obligations of Mirant NorthAmerica under the senior secured credit facilities are unconditionally andirrevocably guaranteed by all of its direct and indirect subsidiaries, except (i) MirantEnergy Trading and Mirant Mid-Atlantic and its subsidiaries, (ii) untilsuch time such entities emerge from Chapter 11 proceedings, Mirant New York,Mirant Bowline, Mirant Lovett, Mirant NY-Gen and Hudson Valley Gas Corporation,and (iii) any of its subsidiaries designated as unrestricted subsidiariesfrom time to time ((ii) and (iii) together, the “unrestrictedsubsidiaries”). The guarantee obligations of these subsidiary guarantors aresecured by first priority security interests on substantially all the assets ofsuch subsidiary guarantors, subject to certain permitted liens and certainexceptions.

All loans under the senior secured credit facilitiesare senior, secured indebtedness of Mirant North America secured by firstpriority security interests in substantially all of the assets of Mirant NorthAmerica subject to permitted liens under the senior secured credit facilitiesand certain exceptions. The obligations of the subsidiaries of Mirant NorthAmerica that are providing guarantees under the senior secured creditfacilities are secured by first priority security interests in substantiallyall of the assets of each such subsidiary, subject to certain permitted liensunder the senior secured credit facilities and certain exceptions.

*Commitment/facilityfees and default interest.**  *A commitment fee calculated on thedaily average unused portion of the commitments under the senior securedrevolving credit facility is payable quarterly in arrears at an annual rate of0.375%. The commitment fee is subject to a possible reduction of 0.125% basedon the achievement and maintenance of certain leverage ratios by Mirant NorthAmerica.

A fee on outstanding letters of credit under thesenior secured revolving credit facility is paid to the Lenders quarterly inarrears on a pro rata basis. The letter of credit fee is calculated on theaverage daily aggregate available amount under all letters of credit under thesenior secured revolving credit facility at a rate per annum equal to theapplicable margin for Eurodollar rate loans under the senior secured revolvingcredit facility less the amount of the fronting fee of the issuing banks underthe senior secured revolving credit facility. A fronting fee at the rate of0.125% per annum calculated on the face amount of each letter of credit underthe senior secured revolving credit facility and each letter of credit that iscash collateralized with a portion of the senior secured term loan proceedswill be paid quarterly in arrears to the relevant issuing bank.

In the event of a default in the payment of principalor interest under the senior secured credit facilities or in the payment of anyfees or other amounts due and payable under the related loan 

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documents, interestaccrues on the overdue amount at the applicable rate plus an additional 2%until such amount is paid in full.

*Certain covenants.**  *Thesenior secured credit facilities contain covenants that:

·       requireMirant North America to maintain at the end of each fiscal quarter: (i) aratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”)to interest expense of at least 2:1, and (ii) a ratio of net debt toEBITDA of not more than 6:1, in each case calculated on a rolling four fiscalquarter basis ending on the last day of such fiscal quarter;

·       restrictthe ability of Mirant North America and its restricted subsidiaries to incurdebt other than certain permitted debt unless, the ratio of net debt to EBITDAis less than 4:1, calculated on a rolling four fiscal quarter basis ending onthe last day of such fiscal quarter and after giving pro forma effect to theincurrence of the debt; and

·       restrictthe ability of Mirant North America and its restricted subsidiaries to makecertain restricted payments, including, without limitation, (i) anydividend payments or distribution of cash or property, (ii) payments,redemption or repurchase of affiliate subordinated debt or (iii) purchaseor redemption of its or its restricted subsidiaries’ capital stock subject tocertain exceptions, including the ability to make payments to us to be appliedto interest payments due on our senior notes maturing in 2011, 2021 and 2031,as long as there is no default or event of default and none would resulttherefrom.

In addition, thesenior secured credit facilities contain customary covenants that restrict theability of Mirant North America and its restricted subsidiaries to:

·       engagein mergers, acquisitions and asset sales;

·       incurliens and engage in sale-leaseback transactions;

·       makeinvestments and capital expenditures;

·       transactwith affiliates; and

·       changeits fiscal year.

*Events of default.**  *The seniorsecured credit facilities contain customary events of default, including,without limitation, payment defaults, material breach of representations andwarranties, covenant defaults, cross-defaults, cross-accelerations, materialjudgments and certain events of bankruptcy or insolvency. In addition, thesenior secured credit facilities contain the following events of default:

·       Exceptwith the written consent of a majority of the Lenders, the series A and B preferredshares issued by Mirant Americas should cease to be enforceable or rights ofthe holders thereof are amended or waived; and

·       MirantNorth America should cease to be controlled, directly or indirectly, by MirantCorporation.

If an event of default occurs, the Lenders areentitled to accelerate the amounts owing under the senior secured creditfacilities and to take all other actions permitted to be taken by a securedcreditor.

*Mandatory prepayments.*   MirantNorth America is required to prepay the amounts outstanding under the seniorsecured term loan and to permanently reduce the commitments under the seniorsecured revolving credit facility with proceeds received from certaintransactions, as follows:

·       100%of any net cash proceeds in excess of $50 million received from any asset salethat is not committed within 365 days thereof to acquire or repair assetsuseful in the business or is not so applied within 180 days thereafter; and

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·       100%of any net cash proceeds from any insurance or other recovery payment in excessof $20 million received that is not committed within 365 days of the recoveryevent to acquire or repair assets useful in the business or is not so appliedwithin 24 months thereafter.

In addition, Mirant NorthAmerica is further required to prepay the senior secured term loan with 50% offree cash flow (less amounts paid to us for the purpose of paying interest onour senior notes) for each fiscal year (commencing with the 2006 fiscal year),provided, that the foregoing percentage shall be reduced to 25% based on theachievement and maintenance of a ratio of net debt to EBITDA of 2:1 or lower.

*Senior Notes*

The notes were issued by Mirant North America Escrow,LLC (“Mirant North America Escrow”) and its wholly-owned subsidiary, MNAFinance Corp. Mirant North America Escrow was a wholly-owned subsidiary ofMirant North America. Upon emergence, Mirant North America Escrow was mergedwith and into Mirant North America with Mirant North America as the survivingentity. Upon the consummation of the merger, Mirant North America assumed allof the obligations of Mirant North America Escrow and MNA Finance Corp. becamea direct, wholly-owned subsidiary of Mirant North America. MNA Finance Corp.was formed and exists solely for the purpose of serving as a co-issuer of thenotes and as a guarantor of the senior secured credit facilities.

*InterestRate; Maturity Date; Redemption Rights.**  *The notes, which were issued in an aggregateprincipal amount of $850 million and bear interest at 7.375%, mature on December 31,2013. Interest on the notes is payable on each June 30 and December 31,commencing June 30, 2006.

The notes are redeemable at the option of Mirant NorthAmerica, in whole or in part, at any time prior to December 31, 2009, at aprice 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, MirantNorth America may redeem the notes at specified redemption prices, togetherwith accrued and unpaid interest, if any, to the date of redemption. At anytime 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 certainequity offerings at a redemption price of 107.375% of the principal amount ofthe notes, together with accrued and unpaid interest, if any, to the date ofredemption. Under the terms of the notes, the occurrence of a change of controlwill be a triggering event requiring Mirant North America to offer to purchaseall or a portion of the notes at a price equal to 101% of their principalamount, together with accrued and unpaid interest, if any, to the date of purchase.In addition, certain asset dispositions or casualty events will be triggeringevents which may require Mirant North America to use the proceeds from thoseasset dispositions or casualty events to make an offer to purchase the notes at100% of their principal amount, together with accrued and unpaid interest, ifany, to the date of purchase if such proceeds are not otherwise used, orcommitted to be used, within certain time periods, to repay senior securedindebtedness, to repay indebtedness under the senior secured credit facilities(with a corresponding reduction in commitments) or to invest in capital assetsrelated to its business.

*Guarantees and ranking.*   Thenotes are guaranteed on a senior unsecured basis by certain subsidiaries ofMirant North America, each of which also guarantees the obligations under thesenior secured credit facilities. Any subsidiaries that in the future guaranteeany of the indebtedness of Mirant North America, including indebtedness underits senior secured credit facilities, or indebtedness of any subsidiaryguarantor, will also guarantee the notes. The notes are:

·       generalunsecured obligations of Mirant North America and the subsidiary guarantors;

·       effectivelyjunior in right of payment to the secured debt of Mirant North America and thesubsidiary guarantors to the extent of the value of the assets securing suchdebt;

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·       rankequally in right of payment with all of the existing and future unsecuredunsubordinated debt of Mirant North America and the subsidiary guarantors;

·       seniorin right of payment to all of the existing and future senior subordinated andsubordinated debt of Mirant North America and the subsidiary guarantors;

·       structurallysubordinated to all of the existing and future liabilities (including tradepayables) of each of our subsidiaries that do not guarantee the notes; and

·       structurallysenior to all of the existing and future liabilities (including trade payables)of Mirant Corporation and Mirant Americas Generation to the extent of the valueof the Mirant North America and its subsidiaries, including MirantMid-Atlantic.

*Certain covenants.**  *The notes are issued under an indenture withLaw Debenture Trust Company of New York, as trustee (the “Trustee”). Theindenture limits the ability of Mirant North America and its restrictedsubsidiaries to:

·       incur,assume or guarantee additional indebtedness;

·       issueredeemable stock and preferred stock;

·       repurchasecapital stock;

·       makeother restricted payments including, without limitation, paying dividends andmaking investments;

·       createliens;

·       redeemdebt that is junior in right of payment to the notes;

·       sellor otherwise dispose of assets, including capital stock of subsidiaries;

·       enterinto agreements that restrict dividends from subsidiaries;

·       merge,consolidate or sell or otherwise dispose of all or substantially all of ourassets;

·       enterinto transactions with affiliates;

·       guaranteeindebtedness;

·       enterinto sale/leaseback transactions; and

·       enterinto new lines of business.

These covenants aresubject to a number of important exceptions and qualifications and certaincovenants may be suspended in the event Mirant North America achieves andmaintains an investment grade credit rating.

***Mirant Mid-Atlantic Operating Leases***

Mirant Mid-Atlantic leases the Morgantown andDickerson baseload units and associated property through 2034 and 2029,respectively, and has an option to extend the leases. Any extensions of therespective leases would be limited to 75% of the economic useful life of thefacility, as measured from the beginning of the original lease term through theend of the proposed remaining lease term. We are accounting for these leases asoperating leases. Rent expenses associated with the Morgantown and Dickersonoperating leases totaled approximately $99 million, $103 million and $96million for the years ended December 31, 2005, 2004 and 2003,respectively. While there is variability in the scheduled payment amounts overthe lease term, the Company recognizes rental expense for these leases on astraight-line basis. The rental expense based on the original scheduled rentpayments is $96 million per year. The additional expense recorded in 2004 and2005 was payable under the terms of the leases and was commensurate with the0.5% increase in interest on the lessor notes that was payable by the lessorsfor the period in which Mirant Mid-Atlantic was not a reporting entity underthe Securities Exchange Act of 1934. As of December 31, 2005 and 2004,Mirant Mid-Atlantic had paid approximately $292 million and $285 million,respectively, of actual operating lease payments in accordance with the leaseagreements in excess 

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of rent expenserecognized. In addition to the regularly scheduled rent payments, MirantMid-Atlantic paid an additional $11 million in 2004, as required by the leaseagreements. A further $12 million of scheduled rent due on June 30, 2005,was funded through a draw made by the lease trustee on letters of creditarranged by the Company. In September 2005, the lease trustee made anadditional draw of $49 million prior to the expiration of the letters of creditin September 2005. This amount is recorded in funds on deposit in thecombined and consolidated balance sheets. On January 3, 2006, as part ofthe settlement and emergence from bankruptcy, Mirant North America posted a $75million letter of credit for the benefit of Mirant Mid-Atlantic to cover thedebt service reserve obligation on the leases. Upon posting of the letter ofcredit, the trustee returned $56 million of cash collateral held to MirantMid-Atlantic.

As of December 31, 2005, the total notionalminimum lease payments for the remaining term of the leases aggregatedapproximately $2.4 billion and the aggregate termination value for the leaseswas approximately $1.4 billion and generally decreases over time. MirantMid-Atlantic leases the Morgantown and the Dickerson baseload units from thirdparty owner lessors that purchased the baseload units from PEPCO. These ownerlessors each own the undivided interests in the baseload generating facilities.The subsidiaries of the institutional investors who hold the membershipinterests in the owner lessors are called owner participants. Equity funding bythe owner participants plus transaction expenses paid by the owner participantstotaled $299 million. The issuance and sale of pass through certificates raisedthe remaining $1.2 billion needed for the owner/lessors to acquire theundivided interests.

The pass through certificates are not directobligations of Mirant Mid-Atlantic. Each pass through certificate represents afractional undivided interest in one of three pass through trusts formedpursuant to three separate pass through trust agreements between MirantMid-Atlantic and State Street Bank and Trust Company of Connecticut, NationalAssociation, as pass through trustee. The property of the pass through trustsconsists of lessor notes. The lessor notes issued by an owner lessor aresecured by that owner lessor’s undivided interest in the leased facilities andits rights under the related lease and other financing documents.

*Certaincovenants.**  *Theoperative documents relating to the Mirant Mid-Atlantic leveraged leasescontain certain restrictive covenants, including the following:

*Limitations on restrictedpayments.*   Mirant Mid-Atlantic cannot make any ofthe following restricted payments (subject to certain narrow, specificallyidentified exceptions):

·       distributionsin respect of equity interests in Mirant Mid-Atlantic (in cash, property,securities or obligations other than additional equity interests of the sametype);

·       paymentsor distributions on account of payments of interest, the setting apart of moneyfor a sinking or analogous fund for, or the purchase or redemption, retirementor other acquisition of any portion of any equity interest in Mirant Mid-Atlanticor of any warrants, options or other rights to acquire any such equity interest(or make payments to any person such as phantom stock payments, where theamount of the payment is calculated with reference to fair market or equityvalue of Mirant Mid-Atlantic); or

·       paymentson or with respect to the purchase, redemption, defeasance or other acquisitionor retirement for value of any subordinated indebtedness;

unless, at the time of and after giving effect to therestricted payment, no significant lease default or lease event of default hasoccurred and is continuing and Mirant Mid-Atlantic: (1) can satisfy afixed charge coverage ratio on a historical basis for the last period of fourfull fiscal quarters; and (2) is projected to satisfy a fixed chargecoverage ratio for the next two periods of four full fiscal quarters.

Mirant Mid-Atlantic assumed the leveraged leasespursuant to, and in accordance with, the treatment of such leases in the Plan.With respect to the assumption of the leveraged leases, the Plan provisions 

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included: (i) anagreement not to issue additional lessor notes unless Mirant Mid-Atlantic israted BBB-/Baa3 or it has a fixed charge coverageratio of at least 2.5:1 and the owner lessors consent; (ii) thecontribution of Mirant Peaker and Mirant Potomac River to Mirant Chalk Point,LLC. (“Mirant Chalk Point”); (iii) the issuance of the Mirant Americas Series APreferred Shares to Mirant Mid-Atlantic; and (iv) certain payments to theparties to the leveraged leases, including $6.5 million to the holders of thepass through trust certificates, $6.5 million to the owner lessors, $2.9million as restoration payments under the leases, and approximately $22 millionof professional fees of the lease parties. The $6.5 million paid to theIndenture Trustee for the benefit of the holders of the pass throughcertificates was paid in January 2006. The other payments were made in December 2005.

In addition, the Plan provided that certaininterpretations of, and amendments to, the Mirant Mid-Atlantic leveraged leasedocumentation are binding upon the parties to the leveraged leases. Theinterpretations and amendments, which are focused primarily on the calculationof the fixed charge coverage ratio for purposes of the restricted paymentstest, clarify (i) under which circumstances Mirant Mid-Atlantic mayeliminate from the calculation of the fixed charge coverage ratio capitalexpenditures made, or projected to be made, with respect to the leasedfacilities, (ii) that Mirant Mid-Atlantic may, in calculating the coverageratio for the periods prior to emergence from Chapter 11, treat capitalexpenditures financed with cash previously generated and retained during anearlier period as being made in such earlier period and, thus, eliminated inthe calculation for the period being measured, (iii) that MirantMid-Atlantic may eliminate from the calculation of the fixed charge coverageratio capital expenditures made, or projected to be made, with the proceeds ofthe Mirant Americas Series A Preferred Shares and similar arrangements,subject to certain conditions, and (iv) that, in determining ‘‘ConsolidatedEBITDA’’ (as defined in the leveraged lease documentation), all adjustments toreconcile net income to net cash provided by (used in) operating activities,excluding changes in operating assets and liabilities, as disclosed in (orprojected to be included in) the cash flow statement of Mirant Mid-Atlantic areto be excluded. As of December 31, 2005, and incorporating theinterpretations and amendments referred to above, Mirant Mid-Atlantic wouldhave met the restricted payments test.

*Limitation in incurrenceof indebtedness.*   Neither Mirant Mid-Atlantic norany of its subsidiaries (other than Mirant Potomac River and Mirant ChalkPoint, each of which are defined as a “Designated Subsidiary”) may incur orassume any indebtedness other than “Permitted Indebtedness,” nor may MirantMid-Atlantic permit any Designated Subsidiary to incur or assume any debt otherthan Designated Subsidiary Permitted Indebtedness. Based on those prohibitions,generally, (1) the only indebtedness Mirant Mid-Atlantic and itssubsidiaries (other than the Designated Subsidiaries) may incur is as follows:

·       anyindebtedness, if, after taking into account the incurrence of suchindebtedness, both S&P and Moody’s confirm their respective ratings of thepass through certificates outstanding prior to incurring the indebtedness, andthere is no event of default outstanding under the leases;

·       indebtednessincurred for working capital purposes;

·       indebtednessrelating to letters of credit, surety bonds or performance bonds or guaranteesissued in the ordinary course of business;

·       indebtednessmeeting the definition of ‘‘Subordinated Indebtedness’’;

·       indebtednessnot to exceed $100 million in the aggregate for principal, less the aggregateprincipal amount of indebtedness incurred as set forth in operative documents;

·       indebtednessrepresented by ‘‘Interest Rate Hedging Transactions’’ entered into in theordinary course of business;

·       indebtednesssecured by a pre-existing lien on any assets acquired by Mirant Mid-Atlantic,so long as the indebtedness is recourse only to those assets and not to thegeneral credit of Mirant Mid-Atlantic;

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·       withregard to subsidiaries other than the Designated Subsidiaries, the indebtednessis Non-Recourse Indebtedness (as defined in the operative documents);

·       anyintercompany loans;

·       indebtednessincurred to finance capital expenditures made to comply with law or to finance ‘‘RequiredImprovements’’ as defined in the Facility Lease Agreements;

·       indebtednessincurred to refinance permitted existing indebtedness, provided that period ofrepayment is not shorter than the original debt and the principal of the newdebt does not exceed the refinanced debt except for a reasonable premium as thecost of the refinancing; or

·       indebtednessguaranteed by Mirant or one or more direct or indirect parents of MirantMid-Atlantic, provided that each of such guarantors has a sufficiently highcredit rating as set forth in the operative documents;

and (2) the only indebtedness that the DesignatedSubsidiaries may incur is essentially the same types of indebtedness as MirantMid-Atlantic is permitted to incur except that the tests are applied withregard to the applicable Designated Subsidiary, and that each DesignatedSubsidiary is limited by a sub-cap of $50 million in connection with theoverall permission given to Mirant Mid-Atlantic and its subsidiaries to incur$100 million of debt in the aggregate, and the Designated Subsidiaries do nothave a separate category of Designated Subsidiary Permitted Indebtedness forworking capital purposes, for ‘‘Subordinated Indebtedness,’’ or indebtednessrepresented by ‘‘Interest Rate Hedging Transactions,’’ for indebtednessincurred to refinance permitted existing indebtedness, nor for indebtednessguaranteed by Mirant or one or more direct or indirect parents of MirantMid-Atlantic.

*Limitationon merger and consolidation or sale of substantially all assets.*   MirantMid-Atlantic is not permitted to, nor may it permit the Designated Subsidiariesto, consolidate or merge with or into any other entity, or sell, lease orotherwise dispose of all or substantially all of its properties or assets toany person or entity except that, if, after giving effect thereto, no leaseevent of default occurs, (a) any Designated Subsidiary may merge intoMirant Mid-Atlantic or into any other Designated Subsidiary, and (b) MirantMid-Atlantic or any Designated Subsidiary may merge into another entity or maysell its assets to another entity if the surviving entity (if it is an entityother than Mirant Mid-Atlantic or a Designated Subsidiary) meets certaincriteria and expressly assumes all of the obligations of Mirant Mid-Atlantic orthe applicable Designated Subsidiary, as the case may be, under the applicabledocuments.

*Limitationson sale of assets.*   Mirant Mid-Atlantic is not permitted to, nor may itpermit any Designated Subsidiary to, sell any assets other than those that fallwithin the definition of ‘‘Permitted Asset Sales’’ set forth in the operativedocuments.

*Restrictionson liens.**  *MirantMid-Atlantic is not permitted to, nor may it permit any Designated Subsidiaryto, create, incur, assume or otherwise suffer to exist any liens on itsrespective assets, other than those that fall within the definition of ‘‘PermittedEncumbrances’’ set forth in the operative documents.

*Assignment and sublease.**  *Without the consent of otherparties to the operative documents, Mirant Mid-Atlantic cannot assign orsublease its interest under a facility lease unless certain requirements aremet.

***Uses of Funds***

Our requirements for liquidity and capital resources,other than for the day-to-day operation of our generation facilities, aresignificantly influenced by two activities: (i) the hedging andproprietary trading activities of Mirant Energy Trading and (ii) capitalexpenditures required to keep our power generation facilities in operation.

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*Collateralrequirements.**  *Theasset hedging and, to a lesser extent, proprietary trading activities of MirantEnergy Trading, represent a significant need for liquidity and capitalresources. These liquidity requirements are primarily driven by margin andcollateral posting requirements with counterparties and disbursement andreceipt timing (*i.e.*, buying fuelbefore receiving energy revenues). As of December 31, 2005, we hadapproximately $685 million of posted cash collateral and $56 million ofletters of credit outstanding primarily to support our asset hedging activitiesand debt service reserve requirements. Our liquidity requirements are highlydependent on the level of our hedging activity, forward prices for energy,emissions allowances and fuel, commodity market volatility and credit termswith third parties. We do not assume that we will be provided with unsecuredcredit from third parties when budgeting our working capital requirements.

*CapitalExpenditures.**  *Capitalexpenditures were $100 million, $89 million and $151 million forthe years ended December 31, 2005, 2004 and 2003, respectively. Ourcapital expenditures for 2006 are expected to be approximately $300 million.For a more detailed discussion of environmental expenditures we expect to incurin the future, see “Item 1. Business”.

*Debt service.**  *At December 31, 2005, we had approximately $2.6 billion oflong-term debt and had an additional $700 million as of March 3, 2006. Ourexpected annual interest expense is approximately $212 million. Under theterms of its senior secured term facility, Mirant North America is required touse 50% of its free cash flow for each fiscal year (less amounts paid to us forthe purpose of paying interest on our senior notes) to pay down its seniorsecured term loan, in addition to our scheduled amortization of approximately$7 million per year. The percentage of free cash flow that Mirant NorthAmerica is required to use to pay down its senior secured term loan may bereduced to 25% upon the achievement by it of a net debt to EBITDA ratio of lessthan 2:1.

***Debtor-in-Possession Financing for New YorkSubsidiaries***

We entered into anagreement (the ‘‘New York DIP Agreement’’) to make secured debtor-in-possessionfinancing in an amount of (i) $20 million, plus (ii) an amountequal 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 collateralizedwith cash or cash equivalents by the New York DIP Borrowers. The facility isavailable 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 toMirant Energy Trading, with Mirant Energy Trading to succeed to all rights andassume all obligations of Mirant Americas Energy Marketing under the New YorkDIP Agreement. The financing under the New York DIP Agreement can be utilizedthrough borrowings by the New York DIP Borrowers, the issuance of letters ofcredit for the account of any of the New York DIP Borrowers or in support ofcommercial transactions entered into by Mirant Energy Trading for the benefitof the New York DIP Borrowers, the posting of cash in respect of obligationsincurred for the benefit of any of the New York DIP Borrowers, including themaking of prepayments for fuel and other commodities for the benefit of any ofthe New York DIP Borrowers. Under the New York DIP Agreement, the amount whichrepresents the excess on the effective date of the Plan of (x) credit supportposted for the benefit of the New York DIP Borrowers by the lenders in respectof transactions entered into on their behalf over (y) the amount of cashcollateral posted by the New York DIP Borrowers to the lenders is deemed to bea loan made to the New York DIP Borrowers on such date. The New York DIPBorrowers have posted $16.1 million cash collateral with Mirant Energy Tradingin accordance with the February 28,2006, collateral allocation performed ingood faith by Mirant Energy Trading. To the extent that the required level ofcredit support provided to the New York DIP Borrowers is reduced, the amount ofsuch reduction is required to be returned to the New York DIP Borrowers. Thefinancing under the New York DIP Agreement has a stated maturity of 180 days,subject to renewal or extension, and is available until the earlier of (x) theexpiration of such period or (y) with respect to each of the New York DIPBorrowers, the 

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effectivedate of a confirmed plan of reorganization for such New York DIP Borrower inits Chapter 11 case. Subject to the authorization of the Bankruptcy Court,the obligations of the New York DIP Borrowers under the New York DIP Agreement,pursuant to Section 364(c) of the Bankruptcy Code, (i) constitutesa claim having priority over any or all administrative expenses of the kindspecified in sections 503(b) or 507(b) of the Bankruptcy Code, (ii) issecured by a lien on property of the estates of the New York DIP Borrowers thatis not otherwise subject to a lien and (iii) is secured by a junior lienon property of the estates of the New York DIP Borrowers that is subject to alien. The financing bears interest at a rate to be determined and to be subjectto Bankruptcy Court approval. The New York DIP Agreement contains certain eventsof default, and the ability of the New York DIP Borrowers to borrow thereunderis subject to certain conditions precedent. In addition, the New York DIPAgreement contains covenants that, among other things, restrict the ability ofthe New York DIP Borrowers to engage in mergers, acquisitions and asset sales,to make investments and to incur indebtedness.

***Cash Flows***

Cash used in operatingactivities increased $41 million for the year ended December 31,2005, compared to the same period in 2004. Our cash used in operatingactivities is volatile as a result of seasonality, changes in energy prices andfluctuations in our working capital requirements. Most notably, when we enterinto transactions to economically hedge our expected generation output or fuel requirementsand those positions move out-of-the money, we are required to post cashcollateral due to our credit rating.

2005 Cash Flow

*OperatingActivities*

Net cash providedby operating activities excluding the changes in operating assets andliabilities was $61 million for the year ended December 31, 2005. This wasprimarily due to the following:

·       Ourgross margin in 2005 excluding unrealized gains and losses and the non-cashrevenue related to the TPA amortization was $893. This amount was substantiallyoffset by operating and maintenance expenses of $590 million and $99 million ofrent expense  for our leased generationfacilities.

·       In2005 we had cash expenses related to the bankruptcy of $103 million

See “Results of Operations” section of Item 7. Management’sDiscussion and Analysis for further discussion.

In 2005, changes inoperating assets and liabilities required $253 million in cash. We posted an additional $278 million of cashcollateral with counterparties and brokers in 2005. Other changes in operatingassets and liabilities were a net source of $25 million in 2005. Of thisamount, approximately $25 million related to property taxes recognized but notpaid in the year.

*InvestingActivities*

In 2005, we had capitalexpenditures of $100 million primarily related to our Mid-Atlantic facilitiesand received $48 million from the sale of our investment in a company thatprovides an electronic commerce platform for the purchase and sale of energycommodities and $4 million related to the 2004 sale of the Bowlineturbines.

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*FinancingActivities*

*In 2005,financing activities provided $18 million in cash as a result of proceeds fromthe issuance of debt of $21 million less $3 million in cash to repay debtrelated to our capital lease obligations at the Peaker and Zeeland generating facilities.*

2004 Cash Flow

*OperatingActivities*

Net cash used byoperating activities excluding the changes in operating assets and liabilitieswas $98 million for the year ended December 31, 2004. This was primarilydue to the following:

·       Ourgross margin in 2004 excluding unrealized gains and losses and the non-cashrevenue related to the TPA amortization was $617 million. This amount was morethan offset by operating and maintenance expenses of $681 million excluding abad debt recovery of $10 million.

·       In2004 we had cash expenses related to the cost of bankruptcy of $60 million andpaid interest on Mirant Debtor debts of $13 million. The lower interestpayments in 2004 compared to 2003 are due to the bankruptcy filing in July 2003.

In 2004, workingcapital changes, which are reflected as changes in operating assets andliabilities, required $53 million in cash. This was primarily due to thefollowing:

·       Netcollateral uses to support commercial operations in 2004 were $77 million. Thisis favorable compared to 2003 due to the decrease in asset related fuelpurchases in 2004 and favorable market movements in power and economic fuelhedging in 2004 compared to 2003, and

·       Otherworking capital sources were $24 million in 2004. Other working capital sourceswere primarily due to decreases in accounts receivables from energy contractssettled early by counterparties as a result of our Chapter 11 filings of $54million and increases in accounts payable to affiliate of $117 million. Theincrease in accounts payable to affiliate was primarily due to letters ofcredit being drawn upon by counterparties and banks for the energy tradingbusiness through Mirant partially offset by settlements related to Mirant’sdiscontinued Canadian trading operations. Other working capital requirementsfor 2004 relate primarily to increases in inventories of $63 million due torising commodity prices, primarily SO2 allowances used in our Mid-Atlanticpower plants and decreases in accounts payable of $104 million related tocontract settlements.

*Investingactivities:**  *Net cashprovided by investing activities totaled $280 million in 2004. In 2004 Mirantrepaid Mirant Americas Energy Marketing $326 million in notes receivable. In2004, the proceeds from the sale of the Bowline unit 3 turbines were $42million offset by capital expenditures of $89 million.

*Financing activities:*   Netcash provided by financing activities was $4 million in 2004. We received $7million from Mirant Americas under the make-whole contract. In 2004, we repaidlong-term debt of $3 million related to our capital lease obligation at thePeaker and Zeeland generation facilities.

2003 Cash Flow

*OperatingActivities.**  *Netcash used in operating activities, excluding the effects of working capital,was $39 million in 2003. This was primarily due to the following:

·       Ourgross margin in 2003 excluding unrealized gains and losses and the non-cashrevenue related to the TPA amortization was $814 million. This amount was offsetby operating and maintenance expenses of $616 million excluding a bad debtexpense of $32 million.

·       In2003 we paid interest on Mirant Debtor debts of $159 million.

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In 2003, workingcapital changes, which are reflected as changes in operating assets andliabilities, required $99 million in cash. This was primarily due to thefollowing:

·       Net collateral uses to support commercialoperations in 2003 were $149 million. The posted additional cash collateralwith counterparties primarily related to energy contract positions, and

·       Otherworking capital sources of $50 million in 2003. Other working capital sourceswere primarily due to decreases in accounts receivables from energy contractssettled early by counterparties as a result of our Chapter 11 filings of $317million and increases in accounts payable to affiliate of $31 million. The $31million increase in accounts payable to affiliate was primarily due to lettersof credit being drawn upon by counterparties and banks for the energy tradingbusiness through Mirant partially offset by payments to Mirant Services. Otherworking capital requirements for 2003 relate primarily to the decreases inaccounts payable of $170 million, decreases in other liabilities of $65 millionprimarily related to the Enron bankruptcy proceedings and increases in prepaidrent of $68 million related to lease payments on Dickerson and Morgantownfacilities.

*Investingactivities:**  *Net cash used ininvesting activities totaled $189 million in 2003. In 2003, we had an increasein notes receivable from affiliate of $376 million and $151 million of capitalexpenditures primarily related to our Mid-Atlantic, New York and Zeelandfacilities. We received cash from the repayment of notes receivable of $58million and received proceeds from the sale of our Neenah plant in Wisconsin of$109 million and the sale of Mirant Americas Energy Capital assets of $161 million.

*Financing activities:*   Netcash provided by financing activities was $528 million in 2003. In 2003 capitalcontributions received were $439 million and dividends paid were $347 million.We received $315 million and paid $29 million in return of capital from MirantAmericas under the make-whole contract. Additionally, we received $285 millionfrom issuance of notes payable to affiliate in 2003. We had proceeds fromissuance of debt related to our energy marketing business of $7 million andrepaid long-term debt of $100 million related to Mirant Americas EnergyCapital, $29 million related to Mirant Americas Development Capital and$13 million related to our capital lease obligations at the Peaker andZeeland generation facilities.

***Debt Obligations, Off-Balance Sheet Arrangements andContractual Obligations***

At December 31,2005, our debt obligations, off-balance sheet arrangements and contractualobligations were as follows (in millions):

| ** **                                         | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **>5 years** | ** ** | **Total** | ** ** |
|----------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------------|------------|-----------|------------|
| Operating leases                                   |       | $        | 109        |     | $          | 116      |       | $        | 124        |     | $          | 145                  |       | $         | 143        |   |   | $ | 1,745 |   |   | $ | 2,382 |   |
| Long-term debt                                     |       | 215      |       | 215      |       | 215      |       | 215      |       | 215      |       |                 | 3,944      |      |       | 5,019 |   |
| Purchase commitments:                              |       |     |       |     |       |     |       |     |       |     |       |                 |       |      |       |   |   |
| Fuel and transportation commitments                |       | 296      |       | 217      |       | —   |       | —   |       | —   |       |                 | —     |      |       | 513 |   |
| Long-term service agreements                       |       | 4        |       | 12       |       | 10       |       | 13       |       | 27       |       |                 | 205        |      |       | 271 |   |
| Other purchase commitments                         |       | 142      |       | —   |       | —   |       | —   |       | —   |       |                 | —     |      |       | 142 |   |
| Total excluding  liabilities subject to compromise |       | 766      |       | 560      |       | 349      |       | 373      |       | 385      |       |                 | 5,894      |      |       | 8,327 |   |
| Liabilities  subject to compromise                 |       |     |       |     |       |     |       |     |       |     |       |                 |       |      |       | 34 |   |
| **Total**                                          |       |     |       |     |       |     |       |     |       |     |       |                 |       |      |       | $ | 8,361 |   |
|                                                    |            |          |            |          |            |          |            |          |            |          |            |                      |            |           |            |  |  |  |  |  |  |  |  |  |

 

Operating leases are off-balance sheet arrangementsprimarily related to our minimum lease payments associated with our lease ofthe Morgantown and Dickerson baseload units. See Note 16 to our combined andconsolidated financial statements contained elsewhere in this report.

Long-term debt includes the current portion oflong-term debt and long-term debt on the combined and consolidated balancesheets. Long-term debt also includes interest assuming no refinancing. In 

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addition to the amountsshown above, on January 3, 2006, Mirant North America entered into an $800million senior secured revolving credit facility and a $700 million seniorsecured term loan. The annual scheduled maturities and interest accrued on the$700 million senior secured term loan are: $53 million for 2006, $52 millionfor 2007, $52 million for 2008, $51 million for 2009, $51 million for 2010 and$752 million for 2011 and thereafter. The draws on the $800 million seniorsecured revolving credit facility were repaid in January and February 2006.See Note 11 to our combined and consolidated financial statements for furtherdiscussion.

Long-term service agreements represent our totalestimated commitments under our long-term service agreements associated withturbines installed or in storage. See Note 16 to our combined and consolidatedfinancial statements for further discussion.

Fuel and transportation commitments relate primarilyto a long-term synthetic fuel purchase agreement, coal purchase commitments forour Mid-Atlantic facilities and a fuel supply agreement with an independentthird party to provide approximately 90% of the estimated coal to be burned atone of the New York facilities through 2005. In the first quarter of 2006, weentered into additional significant coal commitments. See Note 16 to ourcombined and consolidated financial statements for further discussion.

The company had total minimum commitments under thefuel and transportation agreements of $513 million at December 31, 2005.

Other purchase commitments represent the open purchaseorders less invoices received related to open purchase orders for generalprocurement of products and services purchased in the ordinary course ofbusiness. These include construction, maintenance and labor activities at ourgeneration facilities. We entered into an agreement on June 24, 2005 foran SCR System at the Morgantown generating station. The system will befurnished and installed to comply with a State of Maryland environmentalconsent decree to reduce the emissions of NOx. The contract value of thiscapital expenditure is approximately $94 million. Payments are made monthlyupon acceptance of project milestones with the final payment scheduled for June of2008. Mirant Services entered into an agreement on February 10, 2006 foran equipment agreement at the Potomac River Generating station. The equipmentshall be furnished and supplied to disperse emissions which will exceed Stateof Virginia environmental requirements. The contract value of this capitalexpenditure is approximately $6 million. Payments shall be made upon acceptanceof project milestones with the final payment scheduled for December of2006.

At December 31, 2005,liabilities subject to compromise relate only to our New York subsidiaries thatremain in bankruptcy. See Note 3 to our combined and consolidated financialstatements for further discussion.

**CriticalAccounting Policies and Estimates**

The accounting policiesdescribed below are considered critical to obtaining an understanding of ourcombined and consolidated financial statements because their applicationrequires significant estimates and judgments by management in preparing ourcombined and consolidated financial statements. Management’s estimates andjudgments are inherently uncertain and may differ significantly from actualresults achieved. It is our view that the following critical accountingpolicies and the underlying estimates and judgments involve a higher degree ofcomplexity than others do. We discussed the selection of and application ofthese accounting policies with our Board of Managers and our independentauditors.

***Fresh Start Applicability***

In connection with our emergence from bankruptcy, we would be requiredunder Statement of Position 90-7, “*FinancialReporting by Entities in Reorganization under the Bankruptcy Code”*(“SOP90-7”) to adopt fresh start reporting under certain conditions. Freshstart reporting requires the debtor to use 

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currentfair values in its balance sheet for both assets and liabilities and toeliminate all prior earnings or deficits. The two requirements to fresh startreporting are:

·       thereorganization value of the company’s assets immediately before the date ofconfirmation of the plan of reorganization is less than the total of all post-petitionliabilities and allowed claims; and

·       theholders of existing voting shares immediately before confirmation receive lessthan 50% of the voting shares upon emergence.

We refer to these requirements as the “fresh startapplicability test.” For purposes of applying the fresh start applicabilitytest, reorganization value is defined in the glossary of SOP 90-7 as “thevalue attributed to the reconstituted entity, as well as the expected netrealizable value of those assets that will be disposed before reconstitutionoccurs. Therefore, this value is viewed as the fair value of the entity beforeconsidering liabilities and approximates the amount a willing buyer would payfor the assets of the entity immediately after the restructuring.”

In most bankruptcy proceedings, the reorganizationvalue is determined through the court process; it is either negotiated by theparties or ordered by the court if the parties cannot agree to a value. In thebankruptcy proceedings of the Mirant Debtors, no Mirant reorganization valuewas determined by the Bankruptcy Court or agreed upon by the parties.

In order to determine thereorganization value of Mirant for purposes of the fresh start applicabilitytest, Mirant employed a market-based approach that incorporates the tradingvalue of the Mirant Debtors’ publicly traded debt and equity securities in thedays preceding the confirmation date of the Plan. Mirant deemed that thisapproach is appropriate as it is an objective and timely measurement of thefair value of Mirant. Mirant disclosed this intended approach in Exhibit “D”of the Disclosure Statement, which was approved by the Bankruptcy Court andused to solicit votes on the Plan.

The calculation of thereorganization value included the averaging of the trading value of Mirant’spublicly traded debt and equity securities for the three days preceding theconfirmation of the Plan on December 9, 2005. The trading values of debtwere obtained through independent broker quotes for both Mirant and MirantAmericas Generation. These prices were used to determine an impliedvalue for their respective claim classes, as both public and private claimswithin each claim class receive identical treatment under the Plan. Then, themarket value of Mirant’s trust preferred securities and its common equity wereadded to the calculation.

In order to obtain an indication of total value ofMirant’s debt and equity, debt of non-bankrupt subsidiaries was included, as well as adjustments for items representingdebt obligations that were not otherwise included in Mirant’s claims.Finally, the total reorganization value of Mirant’s assets was derived byadding non-interest bearing liabilities to the fair value of Mirant’s debt andequity securities described above.

The result of the calculationindicated that Mirant and the Company, were not allowed to adopt fresh startreporting because the reorganization value of Mirant immediately prior to theconfirmation date exceeded the total of post-petition liabilities and allowedclaims. As a result, Mirant’s, and the Company’s assets and liabilities werenot adjusted to fair value; but rather liabilities compromised by the Plan werestated at present values of amounts to be paid and forgiveness of debt wasreported as an extinguishment of debt in accordance with SFAS No. 145, “*Rescission of FASB Statements No. 4, 44 and 64; Amendment of FASBStatement 13; and Technical Corrections,”*(“SFAS No. 145”).

The applicability test of freshstart reporting was sensitive to changes in the price of the securities, and adecrease of approximately 2% in the average price of the securities for theperiod measured would have resulted in the requirement for Mirant and theCompany to adopt fresh start reporting. The adoption of fresh start reportingwould have had a material impact on our balance sheet at December 31,2005, as well as succeeding statements of operations. Under fresh startreporting, our assets and liabilities would be stated at fair value, includingour power generation facilities and identifiable intangible assets such as 

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emissionsallowances and energy contracts. The depreciation and amortization associatedwith these assets would also differ materially from our historical combined andconsolidated financial statements. In addition, our accumulated deficit wouldhave been eliminated. Therefore, the successor Company under fresh startreporting would not have been comparable to the predecessor Company prior tothe application of fresh start reporting.

See Note 3 to our combinedand consolidated financial statements for further information on our accountingwhile in bankruptcy.

***Accounting for Energy Trading and Marketing Activities***

Our business uses derivatives and other energycontracts to economically hedge our electricity generation and to engage inproprietary trading activities. We use a variety of derivative contracts, suchas futures, swaps, forwards and option contracts, in the management of ourbusiness. Such derivative contracts have varying terms and durations, ortenors, which range from a few days to a number of years, depending on theinstrument.

Pursuant to SFAS No. 133, derivative contractsare reflected in our financial statements at fair value, with changes in fairvalue recognized currently in earnings unless they qualify for a scopeexception. The fair value of such contracts is included in price riskmanagement assets and liabilities—affiliate and price risk management assetsand liabilities—nonaffiliate in our combined and consolidated balance sheets. Alimited number of transactions do not meet the definition of a derivative orare considered normal purchases or normal sales, a permissible scope exceptionunder SFAS No. 133. Thus, such transactions qualify for the use of accrualaccounting.

Determining the fair value of derivatives involves significantestimates based largely on the mid-point of quoted market prices. The mid-pointmay vary significantly from the bid or ask price for some delivery points. Ifno active market exists, we estimate the fair value of certain derivativecontracts using quantitative pricing models. Our modeling techniques includeassumptions for market prices, correlation and volatility, such as using theprices of one delivery point to calculate the price of the contract’s deliverypoint. The degree of complexity of our pricing models increases for longerduration contracts, contracts with multiple pricing features, option contractsand off-hub delivery points.

The fair value of price risk management assets andliabilities—affiliate and price risk management assets and liabilities—nonaffiliatein our combined and consolidated balance sheets are also impacted by ourassumptions such as interest rate, counterparty credit risk and liquidity risk.The nominal value of the contracts is discounted using a forward interest rate curvebased on the LIBOR. In addition, the fair value of our derivative contracts isreduced to reflect the estimated risk of default of counterparties on theircontractual obligations to us.

The amounts recorded as revenues—affiliate andnonaffiliate and as cost of fuel, electricity and other products—affiliate andnonaffiliate change as estimates are revised to reflect actual results andchanges in market conditions or other factors, many of which are beyond ourcontrol. Because we use derivative financial instruments and have not electedcash flow or fair value hedge accounting under SFAS No. 133, our financialstatements—including gross margin, operating income and balance sheet ratios—are,at times, volatile and subject to fluctuations in value primarily due tochanges in energy and fuel prices.

Due to the complexity of the models used to value thederivative instruments, a significant change in estimate could have a materialimpact on our results of operations.

See Note 7 to our combinedand consolidated financial statements for further information on financialinstruments related to energy trading and marketing activities.

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***Income Taxes***

We are a limited liability company treated as a branchfor income tax purposes. As a result, Mirant Americas, Inc. (“MirantAmericas”) and Mirant have direct liability for the majority of the federal andstate income taxes relating to the Company’s operations. We have allocatedcurrent and deferred income taxes to each regarded corporate member entity ofour consolidated group as if each regarded corporate entity member were asingle taxpayer utilizing the asset and liability method to account for incometaxes except with respect to recognizing certain current period tax benefits.Specifically, we have not recorded current period tax benefits on each regardedcorporate entity’s  ability to carry backits separate company current year net operating loss as realization of suchlosses were dependent on reimbursements from Mirant, at Mirant’s discretionunder the tax sharing agreement. Deferred tax assets and liabilities arerecognized for future tax consequences attributable to differences between thefinancial statement carrying amounts of existing assets and liabilities andtheir respective tax bases and net tax operating losses and tax credit carryforwards.Deferred tax assets and liabilities are measured using enacted tax ratesexpected to apply to taxable income in the years in which those temporarydifferences are****expected to be recovered or settled. The effect ondeferred tax assets and liabilities of a change in tax rates were recognized inincome in the period that included the enacted change.

Several significant changes to our tax postureoccurred as a result of the Plan. Implementation of the Plan included the conversionof certain of our regarded corporate entities to limited liability companiescoupled with the liquidation and/or merger of these regarded corporate entitiesinto other disregarded corporate entities for income tax purposes. As a result, certain subsidiariespreviously treated as regarded corporate entities for income tax purposes haveeither been liquidated or converted into disregarded entities for income taxpurposes pursuant to the Plan. Additionally, certain partnerships owned by theregarded corporate entities were also liquidated, and now form part of thesedisregarded entities for income tax purposes. The result of the above Planeffects was to eliminate our recording of tax expense and benefit prospectivelywith respect to the liquidated regarded corporate entities. Furthermore, withrespect to those liquidated regarded corporate entities, all previouslyexisting deferred tax assets and liabilities have been eliminated as of December 31,2005. Certain of our other subsidiaries continue to exist as regarded corporateentities for income tax purposes, including Mirant New York, Inc., HudsonValley Gas Corporation, Mirant Kendall, LLC and Mirant Special Procurement, Inc.

In December 2005,pursuant to the Plan, Mirant rejected and thereby eliminated the tax sharingagreement with its direct and indirect wholly owned regarded corporateentities. As a result, Mirant’s direct and indirect wholly owned regardedcorporate entities are no longer responsible for reimbursing Mirant for theirintercompany tax obligations attributable to their operations. Accordingly, ourincome tax receivables and payables with Mirant or Mirant Americas wereresolved pursuant to a global settlement under the Plan whereby intercompanyreceivables and payables received no distribution, with the exception of incometax payables and receivables related to Mirant New York, Inc. whichcontinues to remain in bankruptcy at December 31, 2005.

***Asset Impairments***

We evaluate our long-lived assets (property, plant andequipment) and definite-lived intangibles for impairment wheneverindicators of impairment exist or when we commit to sell the asset. SFAS No. 144,*“Accounting for the Impairment or Disposal ofLong-Lived Assets,”*(SFAS No. 144”) requires management torecognize an impairment charge if the sum of the undiscounted expected futurecash flows from a long-lived asset or definite-lived intangible is lessthan the carrying value of that asset. The amount of an impairment charge iscalculated as the excess of the asset’s carrying value over its fair value,which generally represents the discounted expected future cash flows from thatasset or in the case of assets we expect to sell, at fair value less costs tosell.

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The determination of impairment requires management toapply judgment in estimating future energy prices, environmental and othermaintenance expenditures and other cash flows. Our estimates of the fair valueof the assets include significant assumptions about the timing of future cashflows, remaining useful lives and selecting a discount rate that reflects therisk inherent in future cash flows.

These estimates andassumptions are subject to a high degree of uncertainty. If actual results arenot consistent with the assumptions used in estimating future cash flows andasset fair values, we may be exposed to additional losses that could bematerial to our results of operations.

***Asset Retirement Obligations***

We account for asset retirement obligations under SFASNo. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”) andunder FASB Interpretation No. 47, “Accounting for Conditional AssetRetirement Obligations, an interpretation of FASB Statement No. 143” (“FIN47”). SFAS No. 143 requires an entity to recognize the fair value of a liabilityfor an asset retirement obligation in the period in which it is incurred. FIN47 expanded on SFAS 143 to include conditional asset retirement obligationsthat should be recorded when estimable. Upon initial recognition of a liabilityfor an asset retirement obligation, the Company capitalizes an asset retirementcost by increasing the carrying amount of the related long-lived asset by thesame amount as the liability. The liability is accreted to its present valueand the capitalized cost is depreciated over the useful life of the relatedasset. Asset retirement obligations associated with long-lived assets includedwithin the scope of SFAS No. 143 and FIN 47 are those obligations forwhich a requirement exists under enacted laws, statutes and written or oralcontractions, including obligations arising under the doctrine of promissoryestoppel.

We have identified certain asset retirementobligations within our power generation operations. These asset retirement obligations are primarily relatedto asbestos abatement at some of our generating facilities, equipment on leasedproperty and other environmental obligations related to the closing of ashdisposal sites.

Liabilities associatedwith asset retirement obligations are estimated by applying a present valuecalculation to current engineering cost estimates of satisfying theobligations. Significant inputs to the present value calculation includecurrent cost estimates, estimated asset retirement dates and appropriatediscount rates. Where appropriate, multiple cost and/or retirement scenarioshave been weighted. We update liabilities associated with asset retirementobligations as significant assumptions change or as relevant new informationbecomes available. However, actual future costs to satisfy asset retirementobligations could differ materially from the current recorded liabilities.

***Estimated Useful Lives***

The estimated useful lives of our long-lived assetsare used to compute depreciation expense, future asset retirement obligations,and are also used in impairment testing. Estimated useful lives are based, inpart, on the assumption that we provide an appropriate level of capitalexpenditures while the assets are still in operation. Without these continuedcapital expenditures, the useful lives of these assets could decreasesignificantly. Estimated lives could be impacted by such factors as futureenergy prices, environmental regulations,various legal factors and competition. If the useful lives were found to beshorterthan originally estimated,depreciation expense may increase, liabilities for future asset retirementobligations may be insufficient and impairments in the carrying value oftangible and intangible assets may result.

See Note 8 to our combinedand consolidated financial statements for further information on long-livedassets.

***Goodwilland Indefinite-lived Intangible Assets***

Weevaluate our goodwill and indefinite-lived intangible assets forimpairment at least annually and periodicallyif indicators of impairment are present. An impairment occurs when the fairvalue of a reportingunit is lessthan its carrying value including goodwill. For this test our businessconstitutes a single reporting

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unit. The amount of the impairment charge, if animpairment exists, is calculated as the difference between the fair value ofthe reporting unit goodwill and its carrying value. We perform our annualassessment of goodwill at October 31 and whenever contrary evidence existsas to the recoverability of goodwill.

Theaccounting estimates related to determining the fair value of goodwill requiremanagement to make assumptions about cost of capital, future revenues,operating costs and forward commodity prices over the life of the assets. Ourassumptions about future revenues, costs and forward prices require significant judgment because such factors havefluctuated in the past and will continue to do so in the future.

Theresults of our 2003 analysis indicated that goodwill was impaired and werecorded an impairment charge of $1,625 million, representing the entirebalance of goodwill. Our fair value was determined using discounted cash flow techniques and assumptionsas to business prospects using the best information available.

Thecritical assumptions used in our impairment analysis included the following:assumptions as to the future electricity and fuel prices, future levels ofgross domestic product growth, levels of supply and demand, future operatingexpenditures and capital expenditure requirements, and estimates of ourweighted average cost of capital.

Theabove assumptions were critical to the Company’s determination of the fairvalue of its goodwill. The combined subjectivity and sensitivity of ourassumptions and estimates used in our goodwill impairment analysis could resultin a reasonable person concluding differently regarding those criticalassumptions and estimates.

See Note 9 to our combined and consolidated financialstatements for further information on goodwill and other intangible assets.

***Litigation***

Weare currently involved in certain legal proceedings. We estimate the range ofliability through discussions with applicable legal counsel and analysis ofcase law and legal precedents. We record our best estimate of a loss, or thelow end of our range if no estimate is better than another estimate within arange of estimates, when the loss is considered probable. As additionalinformation becomes available, we reassess the potential liability related toour pending litigation and revise our estimates. Revisions in our estimates ofthe potential liability could materially impact our results of operations, andthe ultimate resolution may be materially different from the estimates that wemake.

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

**Item 7A.**                *Quantitative and Qualitative Disclosures about Market Risk*

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

**CommodityPrice Risk**

Inconnection with our power generating business, we are exposed to energycommodity price risk associated with the acquisition of fuel needed to generateelectricity, as well as the electricity produced and sold. A portion of ourfuel requirements is purchased in the spot market and a portion of theelectricity we produce is sold in the spot market. In addition, the openpositions in our proprietary trading activities expose us to risks associatedwith the changes in energy commodity prices. As a result, our financialperformance varies depending on changes in the prices of energy andenergy-related commodities. See “Critical Accounting Policies and Estimates”for a discussion of the accounting treatment for proprietary trading and assetmanagement activities.

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The financial performance of our power generationbusiness is influenced by the difference between the variable cost ofconverting source fuel, such as natural gas, oil or coal, into electricity, andthe revenue we receive from the sale of that electricity. The differencebetween the cost of a specific fuel used to generate one megawatt hour ofelectricity and the market value of the electricity generated is commonlyreferred to as the “conversion spread.” Absent the impacts of our price riskmanagement activities, the operating margins that we realize are equal to thedifference between the aggregate conversion spread and the cost of operatingthe facilities that produce the electricity sold.

Conversion spreads are dependent on a variety offactors that influence the cost of fuel and the sales price of the electricitygenerated over the longer term, including conversion spreads of additionalfacility generation capacity in the regions in which we operate, facilityoutages, weather and general economic conditions. As a result of theseinfluences, the cost of fuel and electricity prices do not always change by thesame magnitude or direction, which results in conversion spreads for aparticular generation facility widening or narrowing (or becoming negative) overtime.

Through our asset management activities, we enter intoa variety of exchange-traded and over-the-counter energy and energy-relatedderivative contracts, such as forward contracts, futures contracts, optioncontracts and financial swap agreements to manage our exposure to commodityprice risk and changes in conversion spreads. These derivatives have varyingterms and durations, or tenors, which range from a few days to a number ofyears, depending on the instrument. Our proprietary trading activities alsoutilize similar contracts in markets where we have a physical presence toattempt to generate incremental gross margin.

Derivative energy contracts required to be reflectedat fair value are presented as price risk management assets and liabilities-affiliateand price risk management assets and liabilities-nonaffiliate in theaccompanying combined and consolidated balance sheets. The net changes in theirmarket values are recognized in income in the period of change. Thedetermination of fair value considers various factors, including closingexchange or over-the-counter market price quotations, time value, creditquality, liquidity and volatility factors underlying options and contracts.

The volumetric weighted average maturity, or weightedaverage tenor, of the price risk management portfolio at December 31,2005, was seven months. The net notional amount, or net short position, of theprice risk management assets and liabilities-affiliate and price riskmanagement assets and liabilities-nonaffiliate at December 31, 2005 wasapproximately 8 million equivalent MWh. These amounts do not include theimpact of the financial swap transactions entered into by Mirant Mid-Atlanticin January 2006.

Thefair values of our price risk management assets and liabilities-affiliate andprice risk management assets and liabilities-nonaffiliate, net of creditreserves, as of December 31, 2005, are included in the following table (inmillions):

| ** **     | ** ** | **Assets  Current** | ** ** | **Assets  Noncurrent** | ** ** | **Liabilities  Current** | ** ** | **Liabilities  Noncurrent** | ** ** | **Net Fair Value at  December 31,  2005** | ** ** |
|----------------|------------|---------------------|------------|------------------------|------------|--------------------------|------------|-----------------------------|------------|---------------------------------------------------------------|------------|
| Electricity    |       |                | $          | 450                    |       |                     |       | $                           | 51         |                                                          |       |   | $ | (676 | ) |   |   | $ | (6 | ) |   |   | $ | (181 | ) |   |
| Natural gas    |       |                | 113        |                   |       |                     | 19         |                        |       |                                                          | (112       | ) |   |   | (20 | ) |   |   | — |   |   |
| Oil            |       |                | 20         |                   |       |                     | —     |                        |       |                                                          | (5         | ) |   |   | — |   |   |   | 15 |   |   |
| Residual/other |       |                | 21         |                   |       |                     | 35         |                        |       |                                                          | (3         | ) |   |   | (1 | ) |   |   | 52 |   |   |
| Total          |       |                | $          | 604                    |       |                     |       | $                           | 105        |                                                          |       |   | $ | (796 | ) |   |   | $ | (27 | ) |   |   | $ | (114 | ) |   |

 

**Value at Risk**

Effective November 5,2003, our Risk Management Policy prohibits the trading of certain products(e.g., natural gas liquids and pulp and paper) and contains limits related toour asset management and 

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proprietarytrading activities. Our Risk Management Policy establishes a value-at-risk (“VaR”)limit with respect to our proprietary trading activities of $7.5 million.There is no VaR limit with respect to our asset management activities, as theseactivities are only allowable if they reduce the commodity price exposure ofour generation assets. We manage the market risks associated with our assetmanagement activities in conjunction with the physical generation assets thatthey are designed to economically hedge. As a result, our asset managementportfolio is not included for purposes of compliance with our Risk ManagementPolicy.

*Interest Rate Risk*

We have two loans that providefor a variable rate of interest. Interest expense on such borrowings is sensitiveto changes in the market rate of interest.

MirantNorth America’s $800 million senior secured revolving credit facility and $700million senior secured term loan provide for a variable rate of interest. Ifboth facilities were fully drawn, a 1% per annum increase in the average marketrate would result in an increase in our annual interest expense ofapproximately $8 million and $7 million, respectively.

*Market RiskManagement*

We manage the price riskassociated with price risk management activities through a variety of methods.To ensure that hedge positions are risk reducing in nature, we measure theimpact of each price risk management transaction executed relative to ouroverall asset position, including previously executed hedge transactions thatsuch price risk management transaction is designed to hedge. See “Item 7.Critical Accounting Policies and Estimates” for accounting treatment for pricerisk management activities.

*Credit Risk*

Credit risk represents theloss that we would incur if a counterparty failed to perform under itscontractual obligations. We have established controls and procedures in ourRisk Management Policy to determine and monitor the creditworthiness ofcustomers and counterparties. Our credit policies are established and monitoredby the Risk Oversight Committee. We measure credit risk as the loss we wouldrecord if our customers failed to perform pursuant to the terms of theircontractual obligations less the value of collateral held by us, if any, tocover such losses. We use published ratings of customers, as well as ourinternal analysis, to guide us in the process of setting credit levels, risklimits and contractual arrangements including master netting agreements. Whereexternal ratings are not available, we rely on our internal assessments ofcustomers.

*Collection Risk*

Once we bill a customerfor the commodity delivered or have financially settled the credit risk, we aresubject to collection risk. Collection risk is similar to credit risk andcollection 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 riskdiscussed above.

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**Item 8.**                        *Financial Statements and Supplementary Data*

 

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**Report ofIndependent Registered Public Accounting Firm**

The MemberMirant Americas Generation, LLC:

We have audited the accompanying consolidated balancesheet of Mirant Americas Generation, LLC (a wholly-owned indirect subsidiary ofMirant Corporation) and subsidiaries (the “Company”) as of December 31,2005, and the combined balance sheet of the Company as of December 31,2004, and the related combined statements of operations, equity (deficit) andcomprehensive loss and cash flows for each of the years in the three-yearperiod ended December 31, 2005. These combined and consolidated financialstatements are the responsibility of the Company’s management. Our responsibilityis to express an opinion on these combined and consolidated financialstatements based on our audits.

We conducted our audits in accordance with thestandards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation.We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined and consolidated financialstatements referred to above present fairly, in all material respects, thefinancial position of Mirant Americas Generation, LLC and subsidiaries as of December 31,2005 and 2004, and the results of their operations and their cash flows foreach of the years in the three-year period ended December 31, 2005, inconformity with U.S. generally accepted accounting principles.

As discussed in Notes 1, 2, 3 and 4 to the combined andconsolidated financial statements, on December 9, 2005, the United StatesBankruptcy Court for the Northern District of Texas, Fort Worth Divisionconfirmed Mirant Corporation’s Plan of Reorganization (the “Plan”). The Planbecame effective on January 3, 2006 and the Company emerged from Chapter11 of Title 11 of the U.S. Bankruptcy Code. In connection with the provisionsof the Plan, Mirant Corporation contributed certain net assets to the Company,with effect from December 31, 2005, resulting in a change in reportingentity under Accounting Principles Board Opinion No. 20, *Accounting Changes*; accordingly, the Company has restatedthe financial statements for all prior periods to reflect the financialinformation of the new reporting entity. The Company recorded the effects ofthe Plan as of December 31, 2005. 

As discussed in Note 2 tothe combined and consolidated financial statements, the Company adoptedFinancial Accounting Standards Board Interpretation No. 47, *Accounting for Conditional Asset Retirement Obligations: AnInterpretation of FASB Statement No. 143*, in 2005.

/s/ KPMG LLP

Atlanta, GeorgiaMarch 31, 2006

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**MIRANTAMERICAS GENERATION, LLC AND SUBSIDIARIES**

**(Wholly-OwnedIndirect Subsidiary of Mirant Corporation)**

**CombinedStatements of Operations**

| ** **                                                                                                           | ** ** | **For the Years ended December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                                                           | ** ** | **2005**                                                      | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                                                           | ** ** | **(in millions)**                                        | ** ** |
| **Operating Revenues:**                                                                                              |       |                                                          |       |   |   |   |   |
| Generation revenue—affiliate                                                                                    | ** ** | **$**                                                         | **168**    |   | $ | 465 |   | $ | 417 |   |
| Generation revenue—nonaffiliate                                                                                 | ** ** | **2,922**                                                     |       | 3,076 |   | 3,644 |   |
| Total generation revenues                                                                                            | ** ** | **3,090**                                                     |       | 3,541 |   | 4,061 |   |
| Net trading revenue—affiliate                                                                                   | ** ** | **(1**                                                        | **)**      | (9 | ) | (584 | ) |
| Net trading revenue—nonaffiliate                                                                                | ** ** | **(40**                                                       | **)**      | 36 |   | 580 |   |
| Total net trading revenues                                                                                           | ** ** | **(41**                                                       | **)**      | 27 |   | (4 | ) |
| Total operating revenues                                                                                             | ** ** | **3,049**                                                     |       | 3,568 |   | 4,057 |   |
| Cost of fuel, electricity, and other  products—affiliate                                                        | ** ** | **187**                                                       |       | 131 |   | 51 |   |
| Cost of fuel, electricity, and other  products—nonaffiliate                                                     | ** ** | **1,981**                                                     |       | 2,309 |   | 2,909 |   |
| Total cost of fuel, electricity, and other products                                                                  | ** ** | **2,168**                                                     |       | 2,440 |   | 2,960 |   |
| **Gross Margin**                                                                                                     | ** ** | **881**                                                       |       | 1,128 |   | 1,097 |   |
| **Operating Expenses:**                                                                                              |       |                                                          |       |   |   |   |   |
| Generation facilities rent                                                                                           | ** ** | **99**                                                        |       | 103 |   | 96 |   |
| Depreciation and amortization                                                                                        | ** ** | **132**                                                       |       | 129 |   | 167 |   |
| Operations and maintenance—affiliate, including  restructuring charges of $3 in 2005, $5 in 2004 and $9 in 2003 | ** ** | **301**                                                       |       | 338 |   | 254 |   |
| Operations and maintenance—nonaffiliate, including  restructuring charges of $4 in 2003                         | ** ** | **289**                                                       |       | 250 |   | 298 |   |
| Loss (gain) on sales of assets, net                                                                                  | ** ** | **1**                                                         |       | 65 |   | (18 | ) |
| Impairment losses                                                                                                    | ** ** | **—**                                                    |       | 2 |   | 3,030 |   |
| Total operating expenses                                                                                             | ** ** | **822**                                                       |       | 887 |   | 3,827 |   |
| **Operating  Income (Loss)**                                                                                         | ** ** | **59**                                                        |       | 241 |   | (2,730 | ) |
| **Other Income (Expense), net:**                                                                                     |       |                                                          |       |   |   |   |   |
| Gain on sale of investment, net                                                                                      | ** ** | **44**                                                        |       | — |   | — |   |
| Interest income—affiliate                                                                                       | ** ** | **—**                                                    |       | — |   | 8 |   |
| Interest income—nonaffiliate                                                                                    | ** ** | **6**                                                         |       | 2 |   | 6 |   |
| Interest expense—affiliate                                                                                      | ** ** | **(23**                                                       | **)**      | (8 | ) | (3 | ) |
| Interest expense—nonaffiliate                                                                                   | ** ** | **(760**                                                      | **)**      | (5 | ) | (246 | ) |
| Other, net                                                                                                           | ** ** | **3**                                                         |       | 10 |   | 13 |   |
| Total other (expense) income, net                                                                                    | ** ** | **(730**                                                      | **)**      | (1 | ) | (222 | ) |
| **(Loss)  Income from Continuing Operations before Reorganization Items and Income  Taxes**                          | ** ** | **(671**                                                      | **)**      | 240 |   | (2,952 | ) |
| Reorganization  items, net                                                                                           | ** ** | **87**                                                        |       | 149 |   | 115 |   |
| Provision  (benefit) for income taxes                                                                                | ** ** | **5**                                                         |       | (15 | ) | 111 |   |
| **(Loss)  Income from Continuing Operations**                                                                        | ** ** | **(763**                                                      | **)**      | 106 |   | (3,178 | ) |
| **Loss  from Discontinued Operations, net of tax provision of $1 for 2003**                                          | ** ** | **—**                                                    |       | — |   | (21 | ) |
| **(Loss)  Income before Cumulative Effect of Change in Accounting Principles**                                       | ** ** | **(763**                                                      | **)**      | 106 |   | (3,199 | ) |
| **Cumulative  effect of change in accounting principles, net of taxes**                                              | ** ** | **(16**                                                       | **)**      | — |   | (10 | ) |
| **Net (Loss) Income**                                                                                                | ** ** | **$**                                                         | **(779**   | **)** | $ | 106 |   | $ | (3,209 | ) |

 

See accompanying notes to combined and consolidated financial statements.

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**MIRANTAMERICAS GENERATION, LLC AND SUBSIDIARIES**

**(Wholly-OwnedIndirect Subsidiary of Mirant Corporation)**

**December 31,2005 Consolidated Balance SheetandDecember 31, 2004 Combined Balance Sheet**

| ** **                                                                                            | ** ** | **2005**               | ** ** | **2004** | ** ** |
|-------------------------------------------------------------------------------------------------------|------------|------------------------|------------|----------|------------|
| ** **                                                                                            | ** ** | **(in millions)** | ** ** |
| **Assets**                                                                                            |       |                   |       |     |       |
| **Current Assets:**                                                                                   |       |                   |       |     |       |
| Cash and cash equivalents                                                                             | ** ** | **$**                  | **424**    |     | $          | 636 |   |
| Funds on deposit                                                                                      | ** ** | **1,540**              |       | 319      |       |
| Receivables:                                                                                          |       |                   |       |     |       |
| Affiliate                                                                                             | ** ** | **21**                 |       | 330      |       |
| Customer accounts, less  allowance for uncollectibles of $3 and $403 for 2005 and 2004, respectively  | ** ** | **577**                |       | 518      |       |
| Notes receivable—affiliate                                                                       | ** ** | **—**             |       | 50       |       |
| Price risk management  assets—nonaffiliate                                                       | ** ** | **604**                |       | 216      |       |
| Prepaid rent and other  payments                                                                      | ** ** | **147**                |       | 167      |       |
| Inventory                                                                                             | ** ** | **278**                |       | 261      |       |
| Assets held for sale                                                                                  | ** ** | **7**                  |       | 7        |       |
| Other current assets                                                                                  | ** ** | **36**                 |       | 6        |       |
| Total Current Assets                                                                                  | ** ** | **3,634**              |       | 2,510    |       |
| **Property, Plant and Equipment,  net**                                                               | ** ** | **2,808**              |       | 2,827    |       |
| **Noncurrent Assets:**                                                                                |       |                   |       |     |       |
| Other intangible assets,  net                                                                         | ** ** | **221**                |       | 208      |       |
| Investments                                                                                           | ** ** | **—**             |       | 6        |       |
| Notes receivable from  affiliate                                                                      | ** ** | **—**             |       | 255      |       |
| Price risk management  assets—nonaffiliate                                                       | ** ** | **105**                |       | 112      |       |
| Prepaid rent                                                                                          | ** ** | **208**                |       | 197      |       |
| Funds on deposit                                                                                      | ** ** | **5**                  |       | 5        |       |
| Accounts receivable, less  allowance for uncollectibles of $3 and $65 for 2005 and 2004, respectively | ** ** | **2**                  |       | 27       |       |
| Debt issuance costs, net                                                                              | ** ** | **37**                 |       | —   |       |
| Other noncurrent assets                                                                               | ** ** | **—**             |       | 10       |       |
| Total Noncurrent Assets                                                                               | ** ** | **578**                |       | 820      |       |
| **Total  Assets**                                                                                     | ** ** | **$**                  | **7,020**  |     | $          | 6,157 |   |
| **Liabilities and Equity  (Deficit)**                                                                 |       |                   |       |     |       |
| **Current Liabilities:**                                                                              |       |                   |       |     |       |
| Notes payable-affiliate                                                                               | ** ** | **$**                  | **21**     |     | $          | — |   |
| Current portion of  long-term debt                                                                    | ** ** | **3**                  |       | 4        |       |
| Claims payable and  estimated claims accrual                                                          | ** ** | **1,831**              |       | —   |       |
| Accounts payable and  accrued liabilities                                                             | ** ** | **486**                |       | 412      |       |
| Payable to affiliate                                                                                  | ** ** | **305**                |       | 58       |       |
| Price risk management  liabilities—affiliate                                                     | ** ** | **5**                  |       | 5        |       |
| Price risk management  liabilities—nonaffiliate                                                  | ** ** | **791**                |       | 286      |       |
| Revenue subject to refund                                                                             | ** ** | **—**             |       | 5        |       |
| Transition power  agreements and other obligations                                                    | ** ** | **—**             |       | 9        |       |
| Accrued taxes—affiliate                                                                          | ** ** | **—**             |       | 54       |       |
| Accrued property  taxes—nonaffiliate                                                             | ** ** | **186**                |       | 123      |       |
| Other current liabilities                                                                             | ** ** | **—**             |       | 8        |       |
| Total Current Liabilities                                                                             | ** ** | **3,628**              |       | 964      |       |
| **Noncurrent Liabilities:**                                                                           |       |                   |       |     |       |
| Long-term debt                                                                                        | ** ** | **2,590**              |       | 46       |       |
| Price risk management  liabilities—affiliate                                                     | ** ** | **—**             |       | 3        |       |
| Price risk management  liabilities—nonaffiliate                                                  | ** ** | **27**                 |       | 62       |       |
| Deferred income taxes                                                                                 | ** ** | **—**             |       | 18       |       |
| Asset retirement  obligations                                                                         | ** ** | **33**                 |       | 10       |       |
| Other noncurrent  liabilities                                                                         | ** ** | **5**                  |       | 14       |       |
| Total Noncurrent  Liabilities                                                                         | ** ** | **2,655**              |       | 153      |       |
| **Liabilities Subject to  Compromise**                                                                | ** ** | **34**                 |       | 5,366    |       |
| **Commitments and Contingencies**                                                                     |       |                   |       |     |       |
| **Equity (Deficit):**                                                                                 |       |                   |       |     |       |
| Deficit Investment By  Mirant                                                                         |       | —                 |       | (326     | )          |
| Member’s interest                                                                                | ** ** | **995**                |       | —   |       |
| Preferred stock in  affiliate                                                                         | ** ** | **(319**               | **)**      | —   |       |
| Accumulated other  comprehensive income                                                               | ** ** | **27**                 |       | —   |       |
| Total equity (deficit)                                                                                | ** ** | **703**                |       | (326     | )          |
| **Total Liabilities and Equity (Deficit)**                                                            | ** ** | **$**                  | **7,020**  |     | $          | 6,157 |   |

 

See accompanying notes to combined and consolidated financial statements.

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**MIRANT AMERICASGENERATION, LLC AND SUBSIDIARIES(Wholly-Owned Indirect Subsidiary of Mirant Corporation)Combined Statements of Equity (Deficit) and Comprehensive LossFor the Years ended December 31, 2005, 2004 and 2003(in millions)**

| ** **                                                                                     | ** ** | ** **        | ** ** | ** **        | ** ** | ** **         | ** ** | **Accumulated**        | ** ** | ** **        | ** ** |
|------------------------------------------------------------------------------------------------|------------|-------------------|------------|-------------------|------------|--------------------|------------|------------------------|------------|-------------------|------------|
| ** **                                                                                     | ** ** | ** **        | ** ** | **Preferred**     | ** ** | ** **         | ** ** | **Other**              | ** ** | **Comprehensive** | ** ** |
| ** **                                                                                     | ** ** | **Member’s** | ** ** | **Stock in** | ** ** | **Investment**     | ** ** | **Comprehensive**      | ** ** | **Income**        | ** ** |
| ** **                                                                                     | ** ** | **Interest**      | ** ** | **Affiliate**     | ** ** | **by Mirant** | ** ** | **(Loss) Income** | ** ** | **(Loss)**        | ** ** |
| Balance,  December 31, 2002                                                               |       |              | $          | —            |       |               |       | $                      | —     |              |       |   | $ | 2,392 |   |   |   | $ | (55 | ) |   |   |   |   |   |
| Net  loss                                                                                      |       |              | —     |              |       |               | —     |                   |       |              | (3,209     | ) |   |   | — |   |   |   | (3,209 | ) |   |
| Other  comprehensive income                                                                    |       |              | —     |              |       |               | —     |                   |       |              | —     |   |   |   | 55 |   |   |   | 55 |   |   |
| Comprehensive  loss                                                                            |       |              |       |              |       |               |       |                   |       |              |       |   |   |   |   |   |   |   | $ | (3,154 | ) |   |
| Capital  contributions—payments received from Mirant Americas under make-whole  agreement |       |              | —     |              |       |               | —     |                   |       |              | 315        |   |   |   | — |   |   |   |   |   |   |
| Capital  distributions—payments made to termination of ECSA agreement                     |       |              | —     |              |       |               | —     |                   |       |              | (29        | ) |   |   | — |   |   |   |   |   |   |
| Dividends  to Mirant Americas                                                                  |       |              | —     |              |       |               | —     |                   |       |              | (347       | ) |   |   | — |   |   |   |   |   |   |
| Capital  contributions—cash from Mirant Americas and Mirant                               |       |              | —     |              |       |               | —     |                   |       |              | 439        |   |   |   | — |   |   |   |   |   |   |
| Balance,  December 31, 2003                                                               |       |              | —     |              |       |               | —     |                   |       |              | (439       | ) |   |   | — |   |   |   |   |   |   |
| Net  income                                                                                    |       |              | —     |              |       |               | —     |                   |       |              | 106        |   |   |   | — |   |   |   |   |   |   |
| Capital  contributions—payments received from Mirant Americas under make-whole  agreement |       |              | —     |              |       |               | —     |                   |       |              | 7          |   |   |   | — |   |   |   |   |   |   |
| Comprehensive  Income                                                                          |       |              |       |              |       |               |       |                   |       |              |       |   |   |   |   |   |   |   |   |   |   |
| Balance,  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                                                                            |       |              |       |              |       |               |       |                   |       |              |       |   |   |   |   |   | ** ** | ** ** | **$** | **(752** | **)** | ** ** |
| Change  in member pursuant to the Plan                                                         | ** ** | ** **        | **995**    |              | ** ** | ** **         | **(319**   | **)**                  | ** ** | ** **        | **(676**   | **)** | ** ** | ** ** | **—** |   |   |   |   |   |   |
| **Balance, December 31, 2005**                                                            | ** ** | ** **        | **$**      | **995**           |       | ** **         | ** ** | **$**                  | **(319**   | **)**             | ** ** | ** ** | **$** | **—** | ** ** | ** ** | ** ** | **$** | **27** |   |   |   |   |   |   |

 

See accompanying notes to combined and consolidated financial statements.

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**MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES(Wholly-Owned Indirect Subsidiary of Mirant Corporation)Combined Statements of Cash Flows**

| ** **                                                                            | ** ** | **For the Years ended  December 31,** | ** ** |
|---------------------------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                                            | ** ** | **2005**                                                  | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                            | ** ** | **(in millions)**                                    | ** ** |
| Cash flows from operating activities:                                                 |       |                                                      |       |   |   |   |   |
| Net (loss) income                                                                     | ** ** | **$**                                                     | **(779**   | **)** | $ | 106 |   | $ | (3,209 | ) |
| Adjustments to reconcile  net (loss) income to net cash used in operating activities: |       |                                                      |       |   |   |   |   |
| Equity in income  of affiliates, net of dividends                                     | ** ** | **—**                                                |       | 1 |   | — |   |
| Depreciation and  amortization                                                        | ** ** | **132**                                                   |       | 129 |   | 170 |   |
| Amortization of  transition power agreements and other obligations                    | ** ** | **(9**                                                    | **)**      | (344 | ) | (424 | ) |
| Amortization of  losses on interest rate swaps                                        | ** ** | **—**                                                |       | — |   | 81 |   |
| Amortization of  debt issuance costs, net                                             | ** ** | **5**                                                     |       | — |   | — |   |
| Unrealized (gains)  losses on price risk management assets and liabilities            | ** ** | **21**                                                    |       | (167 | ) | 141 |   |
| Deferred income  taxes                                                                | ** ** | **(11**                                                   | **)**      | 1 |   | 55 |   |
| Impairment losses                                                                     | ** ** | **—**                                                |       | 2 |   | 3,033 |   |
| Cumulative effect  of changes in accounting principles                                | ** ** | **16**                                                    |       | — |   | 10 |   |
| Non-cash charges  for reorganization items                                            | ** ** | **10**                                                    |       | 110 |   | 97 |   |
| Effects of the  Plan of Reorganization                                                | ** ** | **(30**                                                   | **)**      | — |   | — |   |
| (Gain) loss on  sales of assets and investments                                       | ** ** | **(42**                                                   | **)**      | 65 |   | 3 |   |
| Post-petition  interest                                                               | ** ** | **746**                                                   |       | — |   | — |   |
| Other, net                                                                            | ** ** | **2**                                                     |       | (1 | ) | 4 |   |
| Changes in certain assets  and liabilities:                                           |       |                                                      |       |   |   |   |   |
| Affiliate accounts  receivable                                                        | ** ** | **(296**                                                  | **)**      | (17 | ) | 14 |   |
| Customer accounts  receivable                                                         | ** ** | **(117**                                                  | **)**      | 110 |   | 180 |   |
| Prepaid rent                                                                          | ** ** | **(9**                                                    | **)**      | (23 | ) | (68 | ) |
| Inventory                                                                             | ** ** | **(16**                                                   | **)**      | (63 | ) | (10 | ) |
| Other assets                                                                          | ** ** | **(375**                                                  | **)**      | (93 | ) | 18 |   |
| Accounts payable  and accrued liabilities                                             | ** ** | **126**                                                   |       | (119 | ) | (204 | ) |
| Payable to  affiliate                                                                 | ** ** | **405**                                                   |       | 117 |   | 31 |   |
| Accrued taxes,  affiliate                                                             | ** ** | **—**                                                |       | (15 | ) | (59 | ) |
| Accrued property  taxes, nonaffiliate                                                 | ** ** | **25**                                                    |       | 48 |   | 64 |   |
| Other liabilities                                                                     | ** ** | **4**                                                     |       | 2 |   | (65 | ) |
| Total adjustments                                                                     | ** ** | **587**                                                   |       | (257 | ) | 3,071 |   |
| Net cash used in  operating activities                                                | ** ** | **(192**                                                  | **)**      | (151 | ) | (138 | ) |
| Cash flows from investing activities:                                                 |       |                                                      |       |   |   |   |   |
| Capital  expenditures                                                                 | ** ** | **(100**                                                  | **)**      | (89 | ) | (151 | ) |
| Issuance of notes  receivables from affiliate                                         | ** ** | **10**                                                    |       | — |   | (376 | ) |
| Repayments on  notes receivables-nonaffiliate                                         | ** ** | **—**                                                |       | 1 |   | 58 |   |
| Repayments on  notes receivable from affiliate                                        | ** ** | **—**                                                |       | 326 |   | — |   |
| Proceeds received  from the sales of assets, net                                      | ** ** | **52**                                                    |       | 42 |   | 276 |   |
| Insurance proceeds  received                                                          | ** ** | **—**                                                |       | — |   | 4 |   |
| Net cash (used in)  provided by investing activities                                  | ** ** | **(38**                                                   | **)**      | 280 |   | (189 | ) |
| Cash flows from financing activities:                                                 |       |                                                      |       |   |   |   |   |
| Proceeds from  issuance of notes payable-affiliate                                    | ** ** | **21**                                                    |       | — |   | 7 |   |
| Repayment of debt                                                                     | ** ** | **(3**                                                    | **)**      | (3 | ) | (142 | ) |
| Proceeds from  issuance of notes payable to affiliate                                 | ** ** | **—**                                                |       | — |   | 285 |   |
| Payments received  from Mirant Americas under make-whole agreement                    | ** ** | **—**                                                |       | 7 |   | 315 |   |
| Payments made to  Mirant Americas under make-whole agreement                          | ** ** | **—**                                                |       | — |   | (29 | ) |
| Capital  contributions from Mirant Americas and Mirant                                | ** ** | **—**                                                |       | — |   | 439 |   |
| Payment of  dividends to Mirant Americas                                              | ** ** | **—**                                                |       | — |   | (347 | ) |
| Net cash provided  by financing activities                                            | ** ** | **18**                                                    |       | 4 |   | 528 |   |
| Net (decrease)  increase in cash and cash equivalents                                 | ** ** | **(212**                                                  | **)**      | 133 |   | 201 |   |
| Cash and cash  equivalents, beginning of year                                         | ** ** | **636**                                                   |       | 503 |   | 302 |   |
| Cash and cash  equivalents, end of year                                               | ** ** | **$**                                                     | **424**    |   | $ | 636 |   | $ | 503 |   |
| Supplemental cash flow disclosures:                                                   |       |                                                      |       |   |   |   |   |
| Cash paid for  interest, net of amounts capitalized                                   | ** ** | **$**                                                     | **29**     |   | $ | 13 |   | $ | 159 |   |
| Refunds received  for income taxes                                                    | ** ** | **$**                                                     | **—** |   | $ | (2 | ) | $ | — |   |
| Cash paid for  reorganization items                                                   | ** ** | **$**                                                     | **103**    |   | $ | 60 |   | $ | — |   |

 

See accompanying notes to combined and consolidated financial statements.

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**MIRANTAMERICAS GENERATION AND SUBSIDIARIESNOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2005, 2004 and 2003**

**1.**                 Backgroundand Description of Business

Mirant Americas Generation, LLC, including itssubsidiaries (collectively, the “Company” or “Mirant Americas Generation”), isa national independent power provider and an indirect wholly-owned subsidiaryof Mirant Corporation (“Mirant”). The Company produces and sells substantiallyall of the output from its generating facilities in the forward and spotmarkets and the remainder under contracts with third parties. The Company usesderivative financial instruments, such as commodity forwards, futures, optionsand swaps to manage its exposure to fluctuations in electric energy and fuelprices. The Company is a Delaware limited liability company and owns or leasesapproximately 12,035 megawatts (“MW”) of electric generation capacity in theUnited States. The Company operates 72 generating units at 21 plantsserving customers located near major metropolitan load centers in Maryland, California,New York, Massachusetts and Texas.

Pursuant to the Plan ofReorganization (the “Plan”), in December 2005 Mirant contributed itsinterest in Mirant Potomac River, LLC (“Mirant Potomac River”) and MirantPeaker, LLC (“Mirant Peaker”) to our indirect wholly owned subsidiary MirantMid-Atlantic, LLC (“Mirant Mid-Atlantic”) and its interest in Mirant Zeeland,LLC (“Mirant Zeeland”) and  MirantAmericas Energy Marketing, LP (“Mirant Americas Energy Marketing”), MirantAmericas Development, Inc., Mirant Americas Production Company, MirantAmericas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC,Mirant Americas Development Capital, LLC, Mirant Americas Retail EnergyMarketing, L.P., and Mirant Americas Gas Marketing, LLC, (collectively, the “TradingDebtors”) to Mirant North America, LLC (“Mirant North America”), a newlyorganized holding company subsidiary. All of the contributed subsidiaries wereunder the common control of Mirant and are collectively referred to as the “ContributedSubsidiaries.” Mirant’s contribution of the Contributed Subsidiaries resultedin a change in the Mirant Americas Generation reporting entity under AccountingPrinciples Board Opinion No. 20, *“Accounting Changes”*,and accordingly the Company has restated the financial statements for all priorperiods to reflect the financial information of the new reporting entity. SeeNote 4 for further discussion. On January 31, 2006, the trading andmarketing business of the Trading Debtors was transferred to Mirant EnergyTrading, LLC (“Mirant Energy Trading”), a wholly-owned subsidiary of MirantNorth America.

The Company has a numberof service agreements for labor and administrative services with Mirant andMirant Services, LLC (“Mirant Services”). In addition, Mirant Energy Trading, andpreviously Mirant Americas Energy Marketing, provides services to other Mirantaffiliates related to the sale of electric power and the procurement of fueland emissions allowances. These agreements are discussed further in Note 6.

**2.**                 Accountingand Reporting Policies

***Basis of Presentation***

The accompanying combined and consolidated financialstatements of Mirant Americas Generation have been prepared in accordance withaccounting principles generally accepted in the United States of America (“GAAP”).

The accompanying combinedand consolidated financial statements include the accounts of Mirant AmericasGeneration and its wholly-owned subsidiaries and the Contributed Subsidiariesas discussed in Note 1 and have been prepared from the historical recordsmaintained by Mirant Americas Generation, its 

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subsidiariesand the Contributed Subsidiaries. All significant intercompany accounts andtransactions have been eliminated.

For the period subsequentto July 14, 2003 (the “Petition Date”), and various dates thereafter, theaccompanying combined and consolidated financial statements have been preparedin accordance with Statement of Position 90-7, “*FinancialReporting by Entities in Reorganization under the Bankruptcy Code*” (“SOP90-7”). Accordingly, all pre-petition liabilities subject to compromisehave been segregated in the combined and consolidated balance sheets for theyears ended December 31, 2005 and 2004, and classified as liabilitiessubject to compromise at the estimated amounts of allowable claims. The UnitedStates Bankruptcy Court for the Northern District of Texas, Fort Worth Division(the “Bankruptcy Court”) confirmed the Plan pursuant to an order dated December 9,2005 (the “Confirmation Order”), and waived the stay of the Confirmation Order.Accordingly, immediately upon the entry of the Confirmation Order, the terms ofthe Plan and Confirmation Order were deemed binding upon Mirant and 83 of itsdirect and indirect subsidiaries in the United States (collectively, the “MirantDebtors”) and all other parties affected by the Plan. The Plan became effectiveon January 3, 2006. For financial reporting purposes, Mirant recorded theeffects of the Plan on December 31, 2005. Estimated claims related to theCompany’s New York operations consisting of approximately 1,672 MW includingMirant Lovett, LLC (“Mirant Lovett”), Mirant Bowline, LLC (“Mirant Bowline”)and Mirant NY-Gen, LLC (“Mirant NY-Gen”), which remain inbankruptcy, total $34 million as of December 31, 2005, and are included inliabilities subject to compromise in the consolidated balance sheet.

The implementation of the Plan resulted in, amongother things, a new Mirant capital structure, the discharge of debt of the MirantDebtors , the satisfaction or disposition of various types of claims againstthe Mirant Debtors, the assumption or rejection of certain contracts and theestablishment of a new Mirant Board of Directors. In accordance with SOP 90-7,if the Mirant reorganization value of the assets of the emerging entityimmediately before the date of confirmation is less than the total of allpost-petition liabilities and allowed claims, and if the holders of existingvoting shares immediately before confirmation receive less than 50 percent ofthe voting shares of the emerging entity, the entity must adopt fresh startreporting upon its emergence from Chapter 11. The calculation of the Mirantreorganization value included the trading value of Mirant’s debt and equitysecurities for the three days preceding the confirmation of the Plan on December 9,2005.

The result of thecalculation indicated that Mirant and its subsidiaries would not be allowed toadopt fresh start reporting because the Mirant reorganization value immediatelyprior to the confirmation date exceeded the total post-petition liabilities andallowed claims. For further discussion of fresh start reporting see “CriticalAccounting Policies and Estimates”

***Use of Estimates***

The preparation ofthe combined and consolidated financial statements in conformity with GAAPrequires management to make a number of estimates and assumptions that affectthe reported amounts of assets and liabilities and disclosures of contingentassets and liabilities at the date of the combined and consolidated financialstatements and the reported amounts of revenues and expenses during the period.Actual results could differ from those estimates. The Company’s significantestimates include:

·       determining the fair valueof certain derivative contracts;

·       estimatingliabilities resulting from the bankruptcy;

·       estimatingfuture cash flows in determining impairments of long-lived assets, goodwill andindefinite-lived intangible assets;

·       estimatinglosses to be recorded for contingent liabilities; and

·       estimating obligationsrelated to asset retirements.

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***Recently Adopted Accounting Standards***

In March 2005, the Financial Accounting StandardsBoard (“FASB”) issued FASB Interpretation No. 47, “*Accountingfor Conditional Asset Retirement Obligations: an interpretation of FASBStatement No. 143,”*(“FIN 47”),**whichexpands the scope of asset retirement obligations to be recognized underStatement of Financial Accounting Standards (“SFAS”) No. 143 “*Accounting for Asset Retirement Obligations*” (“SFAS No. 143”),to include asset retirement obligations that may be uncertain as to the natureor timing of settlement. Upon initial recognition of a liability for an assetretirement obligation, the Company capitalizes an asset retirement cost byincreasing the carrying amount of the related long-lived asset by the sameamount as the liability. Over time, the liability is accreted to its presentfair value and the capitalized cost is depreciated over the remaining usefullife of the related asset. Asset retirement obligations associated withlong-lived assets included within the scope of SFAS No. 143 and FIN 47 arethose conditional and unconditional obligations for which a requirement existsunder enacted laws, statutes and written or oral contractions, includingobligations arising under the doctrine of promissory estoppel. For furtherdiscussion see “Cumulative Effect of Changes in Accounting Principles” below.

FIN 47 was effective for financial statements endingafter December 15, 2005. At December 31, 2005, the Company recordedconditional asset retirement obligations related to the retirement of itsgenerating facilities of $27 million. The cumulative effect of adopting FIN 47was $16 million.

In December 2004,the FASB issued SFAS No. 153, “*Exchanges of ProductiveAssets: an Amendment of APB Opinion No. 29,”* (“SFAS No. 153”)*.*SFAS No. 153 addresses the measurement of exchangesof certain nonmonetary assets. It amends APB Opinion No. 29, “*Accounting for Nonmonetary Exchanges,”* and requires thatnonmonetary exchanges (except for certain exchanges of products or propertyheld for sale in the ordinary course of business) be accounted for at the fairvalue of the assets exchanged, with gains or losses being recognized, if thefair value is determinable within reasonable limits and the transaction has commercialsubstance. The provisions of SFAS No. 153 are effective for transactionsinvolving nonmonetary exchanges that occur in fiscal periods beginning after June 15,2005. The Company has determined that certain exchanges of emissions allowancesthat the Company may periodically transact would qualify as nonmonetaryexchanges under SFAS No. 153. For the year ended December 31, 2005,the Company identified certain transactions involving exchanges of emissionsallowances of one vintage year for a different year. The adoption of SFAS No. 153had no material impact on the Company’s combined and consolidated results ofoperations, cash flows or financial position as of December 31, 2005.

***Revenue Recognition***

The Company recognizesaffiliate and nonaffiliate revenue when electric power is delivered, capacityis made available or ancillary services are provided to an affiliate orcustomer pursuant to contractual commitments that specify volume, price anddelivery requirements, and collection of such revenue is probable. Some salesof energy are based on economic dispatch, or “as-ordered” by thePennsylvania-New Jersey-Maryland Interconnection, LLC (“PJM”), based onmember participation agreements, but without an underlying contractualcommitment. Independent system operator (“ISO”) revenues and revenues for salesof energy based on economic-dispatch, are recorded on the basis of megawatthour (“MWh”) delivered, at the relevant day-ahead or real-time prices. TheCompany also recognizes affiliate and nonaffiliate revenue when ancillaryservices have been performed and collection of such revenue is probable.

***Derivative Financial Instruments***

Derivative financial instruments are recorded in theaccompanying combined and consolidated balance sheets at fair value as eitherprice risk management assets or liabilities-affiliate or price risk managementassets or liabilities-nonaffiliate, and changes in fair value are recognizedcurrently in earnings, unless specific hedge accounting criteria are met. Ifthe derivative is designated as a fair value 

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hedge, the changes in thefair value of the derivative and of the hedged item attributable to the hedgedrisk are recognized currently in earnings. If the derivative is designated as acash flow hedge, the changes in the fair value of the derivative are recordedin other comprehensive income (“OCI”) and the realized gains and losses relatedto these derivatives are recognized in earnings in the same period as thesettlement of the underlying hedged transaction. Any ineffectiveness related tocash flow hedges is recognized currently in earnings. The assets andliabilities related to derivative instruments that have not been designated ashedges for accounting purposes are included in price risk management assets andliabilities-affiliate and price risk management assets andliabilities-nonaffiliate. For the years ended December 31, 2005, 2004 and2003, the Company did not have any commodity derivative instruments that it haddesignated as fair value or cash flow hedges for accounting purposes. TheCompany’s derivative financial instruments are categorized by one of threetypes, based on the business objective the instrument is expected to achieve:asset management, legacy and proprietary trading. All asset management, legacyand proprietary trading derivative activities are recorded at fair value,except for a limited number of transactions that qualify for the normalpurchases or normal sales exclusion from SFAS No. 133, “*Accounting for Derivative Instruments and Hedging Activities,”*(“SFAS No.133”) and therefore qualify for use of accrual accounting.

As the Company’s commodityderivative financial instruments have not been designated as hedges foraccounting purposes, changes in such instruments’ fair values are recognizedcurrently in earnings. For asset management activities, changes in fair valueof electricity derivative financial instruments are reflected in generationrevenue-affiliate and nonaffiliate and changes in fair value of fuel derivativecontracts are reflected in cost of fuel, electricity and otherproducts-affiliate and nonaffiliate in the accompanying combined statements ofoperations. Changes in the fair value and settlements of contracts forproprietary trading activities are recorded as net trading  revenue affiliate and nonaffiliate inaccompanying combined statements of operations.

***Concentration of Revenues***

In 2005, 2004 and 2003,the Company earned a significant portion of its operating revenue and grossmargin from the PJM energy market, where the Company’s Mirant Mid-Atlanticgeneration facilities are located.

***Concentration of Labor Subject to CollectiveBargaining Agreements***

At December 31, 2005,approximately 68% of the Company’s employees that have been employed throughcontracts with Mirant Services, LLC (“Mirant Services”) are subject tocollective bargaining agreements. Approximately 9% of the employees are coveredby collective bargaining agreements that will expire within one year.

***Cash and Cash Equivalents***

Mirant Americas Generationconsiders all short-term investments with an original maturity of threemonths or less to be cash equivalents.

***Restricted Cash***

Restricted cash isincluded in current and noncurrent assets as funds on deposit in theaccompanying combined and consolidated balance sheets and amounted to $1.5billion and $324 million at December 31, 2005 and 2004, respectively. For2005, current and noncurrent funds on deposit were $1.5 billion and $5 million,respectively. For 2004, current and noncurrent funds on deposit were $319million and $5 million, respectively. Restricted cash includes deposits withbrokers and cash collateral posted with third parties to support the Company’scommodity positions. In addition, as of December 31, 2005, restricted cashincluded $853 million in escrow related to the senior notes offering in December 2005.This amount was released from escrow on January 3, 2006.

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***Inventory***

Inventory consistsprimarily of oil, coal, purchased emissions allowances and materials andsupplies. Inventory, including commodity trading inventory, is generally statedat the lower of cost or market value at December 31, 2005 and 2004. Fuelstock is removed from inventory as it is used in the production of electricity.Materials and supplies are removed from inventory when they are used forrepairs, maintenance or capital projects.

***Emissions Allowances***

Purchased emissionsallowances are recorded in inventory at the lower of cost or market. Cost iscomputed on an average cost basis. Purchased emissions allowances for sulfurdioxide (“SO2”) and nitrogen oxide (“NOx”) are removed from inventory andcharged to cost of fuel, electricity and other products in the accompanyingcombined statements of operations as they are utilized against emissionsvolumes that exceed the allowances granted to the Company by the EnvironmentalProtection Agency (“EPA”).

Emissions allowances granted by the EPA related togeneration facilities owned by the Company are recorded at fair value at thedate of the acquisition of the facility and are included in property, plant andequipment. These emissions allowances are depreciated on a straight-line basisover the estimated useful life of the respective generation facility, whichranges from 12 to 42 years, and are charged to depreciation and amortizationexpense in the accompanying combined statements of operations.

Emissions allowances granted by the EPA related togeneration facilities leased by the Company are recorded at fair value at thecommencement of the lease in other intangible assets. These emissions allowancesare amortized on a straight-line basis over the term of the lease, and arecharged to depreciation and amortization expense in the accompanying combinedstatements of operations.

The Company has determinedthat certain exchanges of emissions allowances that the Company mayperiodically transact would qualify as nonmonetary exchanges under SFAS No. 153.

***Property, Plant and Equipment***

Property, plant andequipment are recorded at cost, which includes materials, labor and associatedpayroll-related and overhead costs and the cost of financing construction. Thecost of routine maintenance and repairs, such as inspections and corrosionremoval and the replacement of minor items of property are charged to expenseas incurred. Certain expenditures incurred during a major maintenance outage ofa generating plant are capitalized, including the replacement of majorcomponent parts and labor and overhead incurred to install the parts.Depreciation of the recorded cost of depreciable property, plant and equipment isrecognized on a straight-line basis over the estimated useful life of theasset. Upon the retirement or sale of property, plant and equipment, the costof such assets and the related accumulated depreciation are removed from thecombined and consolidated balance sheets. No gain or loss is recognized forordinary retirements in the normal course of business since the compositedepreciation rates used by the Company take into account the effect of interimretirements.

***Capitalization of Interest Cost***

The Companycapitalizes interest on projects during the advanced stages of development andduring the construction period. The Company determines which debt instrumentsrepresent a reasonable measure of the cost of financing construction assets interms of interest cost incurred that otherwise could have been avoided. Thesedebt instruments and associated interest costs are included in the calculationof the weighted average interest rate used for determining the capitalizationrate. Upon commencement of commercial operations of the plant or project,capitalized interest, as a component of the total cost of the plant, isamortized over the estimated useful life of the plant or the life of thecooperation period of the 

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various energy conversion agreements. The Companyincurred the following interest costs on debt to nonaffiliates(in millions):

| ** **                                                           | ** ** | **For the Years  Ended December 31,** | ** ** |
|----------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                           | ** ** | **2005**                                                  | ** ** | **2004** | ** ** | **2003** | ** ** |
| Total interest  costs:                                               |       | $                                                         | 760        |   |   | $ | 5 |   |   | $ | 248 |   |
| Interest  capitalized and included in construction work in progress: |       | —                                                    |       |   | — |   |   | (2 | ) |
| Total Interest  expense—nonaffiliate:                           |       | $                                                         | 760        |   |   | $ | 5 |   |   | $ | 246 |   |

 

In the third quarter of2005, the Company determined that it was probable that contractual interest onliabilities subject to compromise from the Petition Date would be incurred forcertain claims expected to be allowed under the Plan and, accordingly, recordedinterest expense of approximately $749 million in 2005 on liabilities subjectto compromise. This amount represents interest from the Petition Date throughthe effective date of the Plan.

***Goodwill and Intangible Assets***

Goodwill represents theexcess of costs over the fair value of assets of businesses acquired. Goodwilland intangible assets acquired in a purchase business combination that aredetermined to have an indefinite useful life are not amortized, but insteadtested for impairment at least annually. Intangible assets with definite usefullives are amortized on a straight-line basis over their respective useful livesranging up to 40 years to their estimated residual values. An impairmentoccurs when the fair value of a reporting unit is less than its carrying valueincluding goodwill. The Company has determined that its operations constitute asingle reporting unit. The fair value of the reporting unit is calculated usingdiscounted cash flow techniques and assumptions as to business prospects usingthe best information available. The Company recognized a full impairment ofgoodwill in 2003. See Note 9 for additional information.

***Environmental Remediation Costs***

Mirant Americas Generationaccrues for costs associated with environmental remediation obligations whensuch costs are probable and can be reasonably estimated. Accruals for estimatedlosses from environmental remediation obligations generally are recognized nolater than completion of the remedial feasibility study. Such accruals areadjusted as further information develops or circumstances change. The cost offuture expenditures for environmental remediation obligations are discounted totheir present value.

***Debt Issuance Costs***

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

***Income Taxes***

The Company is a limited liability company treated asa branch for income tax purposes. As a result, Mirant Americas, Inc. (“MirantAmericas”) and Mirant have direct liability for the majority of the federal andstate income taxes relating to the Company’s operations. The Company hasallocated current and deferred income taxes to each regarded corporate entityof its consolidated group as if each regarded corporate entity were a singletaxpayer utilizing the asset and liability method to account for income taxesexcept with respect to recognizing certain current period tax benefits.Specifically, the Company has not recorded current period tax benefits on eachregarded corporate entity’s ability to carry back its separate company currentyear net operating loss (NOL)as realization of such losses is dependent on 

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reimbursements fromMirant, at Mirant’s discretion under the tax sharing agreement. Deferred taxassets and liabilities are recognized for future tax consequences attributableto differences between the financial statement carrying amounts of existingassets and liabilities and their respective tax bases and NOL carryforwards.Deferred tax assets and liabilities are measured using enacted tax ratesexpected to apply to taxable income in the years in which those temporarydifferences are****expected to be recovered orsettled. The effect on deferred tax assets and liabilities of a change in taxrates are recognized in income in the period that included the enacted change.

Several changes to the Company’s tax posture occurredas a result of the Plan. Implementation of the Plan included the conversion ofcertain of the Company’s regarded corporate entities to limited liabilitycompanies coupled with the liquidation and/or merger of certain regardedcorporate entities into other disregarded corporate entities for income taxpurposes. As a result, certain subsidiaries previously treated as regardedcorporate entities for income tax purposes have either been liquidated orconverted into disregarded entities for income tax purposes pursuant to thePlan. Additionally, certain partnerships owned by regarded corporate entitieswere also liquidated, and now form part of disregarded entities for income taxpurposes. The result of the above Plan effects was to eliminate the Company’srecording of tax expense and benefit prospectively with respect to theliquidated regarded corporate entities. Furthermore, with respect to thoseliquidated regarded corporate entities, all previously existing deferred taxassets and liabilities were eliminated as of December 31, 2005. Certain ofthe Company’s other subsidiaries continue to exist as regarded corporateentities for income tax purposes, including Mirant New York, Inc., HudsonValley Gas Corporation, Mirant Kendall, LLC and Mirant Special Procurement, Inc.

In December 2005, pursuant to the Plan, Mirantrejected and thereby eliminated the tax sharing agreement with its direct andindirect wholly owned regarded corporate entities. As a result, Mirant’s directand indirect wholly owned regarded corporate entities are no longer responsiblefor reimbursing Mirant for their intercompany tax obligations attributable totheir operations. Accordingly, the Company’s income tax receivables andpayables with Mirant or Mirant Americas were resolved pursuant to a globalsettlement under the Plan whereby intercompany receivables and payablesreceived no distribution, with the exception of income tax payables andreceivables related to Mirant New York, Inc. which continues to remain inbankruptcy at December 31, 2005.

SFAS No. 109, “*Accountingfor Income Taxes”* (“SFAS No. 109”), requires that a valuationallowance be established when it is more likely than not that all or a portionof a deferred tax asset will not be realized. The ultimate realization ofdeferred tax assets is dependent upon the generation of future taxable incomeduring the periods in which those temporary differences are deductible. Inmaking this determination, management considers all available positive andnegative evidence affecting specific deferred tax assets, including theCompany’s past and anticipated future performance, the reversal of deferred taxliabilities, the implementation of tax planning strategies and management’sexpectations of future reimbursements of NOL carryforwards from Mirant.

Objective positive evidence is necessary to support aconclusion that a valuation allowance is not needed for all or a portion ofdeferred tax assets when significant negative evidence exists. Cumulativelosses in recent years are the most compelling form of negative evidenceconsidered by management in this determination. Additionally, managementconsidered the fact that Mirant has not reimbursed the Company for currentperiod NOLs since the Petition Date and the uncertainty regarding futurereimbursements from Mirant. In 2005, 2004 and 2003, the Company recognizedchanges in its valuation allowance of $(534) million, $(4) million and$658 million, respectively, related to its net deferred tax assets.

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***Impairment of Long-Lived Assets***

The Company evaluateslong-lived assets, such as property, plant and equipment, and purchasedintangible assets subject to amortization, for impairment whenever events orchanges in circumstances indicate that the carrying amount of the asset may notbe recoverable. Such evaluations are performed in accordance with SFAS No. 144,“*Accounting for the Impairment or Disposal ofLong-Lived Assets*.” Recoverability of assets to be held and used ismeasured by a comparison of the carrying amount of an asset to the estimatedundiscounted future cash flows expected to be generated by the asset. If thecarrying amount of an asset exceeds its estimated undiscounted future cashflows, an impairment charge is recognized as the amount by which the carryingamount of the asset exceeds the discounted future cash flows of the asset.Assets to be disposed of are separately presented in the accompanying combinedand consolidated balance sheets and are reported at the lower of the carryingamount or fair value less costs to sell, and are not depreciated. The assetsand liabilities of a disposal group classified as held for sale are presentedseparately in the appropriate asset and liability sections of the accompanyingcombined and consolidated balance sheets.

***Cumulative Effect of Changes in Accounting Principles***

*2005*

The Company adopted FIN 47effective December 31, 2005, related to the costs associated withconditional legal obligations to retire tangible long-lived assets. Conditionalasset retirement obligations are recorded at the fair value in the period inwhich they are incurred by increasing the carrying amount of the relatedlong-lived asset. In each subsequent period, the liability is accreted to itsfair value and the capitalized costs are depreciated over the useful life ofthe related asset. At December 31, 2005, the Company recorded a cumulativeeffect of a change in accounting principle of approximately $16 million, net oftax, related to the adoption of this accounting standard.

*2003*

In October 2002, the Emerging Issues Task Force (“EITF”)reached a consensus on EITF Issue 02-03, *IssuesRelated to Accounting for Contracts Involved in Energy Trading and RiskManagement Activities*, to rescind EITF Issue 98-10, *Accounting for Contracts Involved in Energy Trading and Risk ManagementActivities*. Accordingly, energy-related contracts that are notaccounted for pursuant to SFAS No. 133, such as transportation contracts,storage contracts, and tolling agreements, are required to be accounted for asexecutory contracts using the accrual method of accounting and not fair value.Energy-related contracts that meet the definition of a derivative pursuant toSFAS No. 133 continue to be carried at fair value. In addition, the EITFobserved that accounting for energy-related inventory at fair value by analogyto the consensus on EITF Issue 98-10 is not appropriate and that suchinventory is not to be recognized at fair value. As a result of the consensuson EITF Issue 02-03, all nonderivative energy trading contracts on thecombined balance sheet as of January 1, 2003 that existed on October 25,2002 and energy-related inventories that were recorded at fair value have beenadjusted to historical cost resulting in a cumulative effect adjustment of$7 million, net of taxes, which was recorded in the first quarter of 2003.

The Company adopted SFAS No. 143effective January 1, 2003, related to costs associated with legalobligations to retire tangible long-lived assets. Asset retirement obligationsare recorded at fair value in the period in which they are incurred byincreasing the carrying amount of the related long-lived asset. In eachsubsequent period, the liability is accreted to its fair value and thecapitalized costs are depreciated over the useful life of the related asset. Inthe first quarter of 2003, the Company recorded a charge as a cumulative effectof a change in accounting principle of approximately $3 million, net oftax, related to the adoption of this accounting standard.

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***Investments***

As of December 31,2004, the Company had a $6 million investment in a company that providesan electronic commerce platform for the purchase and sale of energycommodities. The Company accounted for this investment using the cost method in2004 and the investment was included in investments in the accompanyingcombined balance sheet. In the fourth quarter of 2005, the investee completedan initial public offering and the Company’s investment was exchanged forapproximately 2.8 million shares of common stock of the investee. The Companysold a portion of its investment for $48 million. The Company recorded again on saleof investments of $44 million related to this sale. The fair value of theCompany’s remaining investment in the investee of approximately $30 millionis classified as securities available for sale and is included in other currentassets on the consolidated balance sheet as of December 31, 2005. TheCompany has recorded an unrealized gain in accumulated other comprehensiveincome of $27 million in the consolidated balance sheet at December 31,2005 related to this investment.

***Fair Value of Financial Instruments***

SFAS No. 107, “*Disclosuresabout Fair Value of Financial Instruments,”* requires the disclosureof the fair value of all financial instruments that are not otherwise recordedat fair value in the financial statements. At December 31, 2005 and 2004,financial instruments recorded at contractual amounts that approximate marketor fair value include cash and cash equivalents, funds on deposit, receivablesfrom affiliate, excluding pre-petition amounts discussed below, and customeraccounts receivable, notes receivable-affiliate, accounts payable and accruedliabilities, payable to affiliate and notes payable-affiliate. The marketvalues of such items are not materially sensitive to shifts in market interestrates because of the short term to maturity of these instruments. At December 31,2005 and 2004, the fair value of the Company’s long-term accounts receivable of $2 million and $27 million,respectively, are not readily determinable due to uncertainty regarding theamount and timing of collection from the Company’s customers.

The fair value of the Company’s long-term debt isestimated using quoted market prices when available. At December 31, 2005,the carrying value of the Company’s long-term debt approximated fair value.

At December 31, 2004,the Company’s receivables from affiliate included $295 million of pre-petitionamounts and current notes receivable from affiliate included $40 million ofpre-petition amounts for which fair value was not readily determinable becauseof their intercompany nature and the status of the bankruptcy cases. At December 31,2004, the Company’s long-term notes receivable from affiliate had a carryingvalue of $255 million. The fair value of Mirant Americas Generation’slong-term notes receivable from affiliate was not readily determinable becauseof their intercompany nature and the status of the bankruptcy cases. Under thePlan, the pre-petition receivables from affiliate and pre-petition notesreceivable from affiliate were resolved pursuant to a global settlement wherebyintercompany claims did not receive any distribution.

***Rent Expense***

Rent expense related tothe Company’s operating leases is recognized on a straight-line basisover the terms of the leases. Rent expense for generation facilities isreported separately as generation facilities rent in the accompanying combinedstatements of operations. Payments made under the terms of the lease agreementin excess of the amount of lease expense recognized are recorded as prepaidrent in the accompanying combined and consolidated balance sheets. Prepaid rentattributable to periods beyond one year is included in noncurrent assets.

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**3.**                 BankruptcyRelated Disclosures

On January 19, 2005, theMirant Debtors filed a Plan and DisclosureStatement (the “Disclosure Statement”) with the Bankruptcy Court. TheBankruptcy Court confirmed the Plan pursuant to the Confirmation Order.Accordingly, the terms of the Plan and Confirmation Order were deemed bindingupon the Mirant Debtors and all other parties affected by the Plan. ThePlan became effective on January 3, 2006. For financial statementpresentation purposes, Mirant and the Company recorded the effects of the Planon December 31, 2005. Mirant AmericasGeneration’s New York subsidiaries remain in bankruptcy.

ThePlan included the following key elements:

·       The business of the Mirant Debtors continued tooperate in its current form, subject to certain internal structural changesincluding the organization of a new parent entity (“New Mirant”).

·       In addition to amounts borrowed under Mirant NorthAmerica’s senior secured revolving credit facility, Mirant had approximately$4.4 billion of debt after emergence.

·       Thepre-petition intercompany claims between andamong the Mirant Debtors were resolved as part of a global settlement.

·       The holders of unsecured claims against theConsolidated Mirant Debtors received a pro rata share of:

·        96.25% of theshares of New Mirant common stock issued under the Plan, excluding: (i) 2.3%of shares of New Mirant common stock issued to certain holders of claimsagainst the Mirant Americas Generation Debtors, and (ii) the sharesreserved for issuance pursuant to the New Mirant employee stock programs; and

·        the right to receive cash payments equal to 50% ofthe cash recoveries, if any, from certain designated avoidance actions.In connection with the Plan, MC Asset Recovery, LLC (“MC Asset Recovery”) wasformed as a wholly-owned subsidiary of Mirant on December 30, 2005, toprosecute, settle and/or liquidate certain avoidance actions.

The holders of certain subordinated obligations had theright to receive 3.5% of the shares of New Mirant common stock (which sharesare included in the 96.25% referred to above), to receive warrants to purchasean additional 5% of the shares of New Mirant common stock, and to participatepari passu with the holders of Mirant unsecured claims in the recoveries underthe designated avoidance actions.

·       The outstanding common stock in Mirant was cancelledand the holders thereof received:

·        3.75% of theshares of New Mirant common stock (subject to the exclusions noted above forMirant’s general unsecured creditors, as applicable);

·        warrants topurchase up to an additional 10% of the shares of New Mirant common stock; and

·        the right toreceive cash payments equal to 50% of the recoveries, if any, from certaindesignated avoidance actions.

·       The claims against the Consolidated Mirant AmericasGeneration Debtors were paid in full through:

·        thereinstatement of the Mirant Americas Generation senior notes maturing in 2011,2021 and 2031, and the payment of $452 million of accrued interest; and

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·        the issuance toall other holders of secured and unsecured claims against the ConsolidatedMirant Americas Generation Debtors of (a) approximately $1.35 billion incash and (b) 2.3% of the shares of New Mirant common stock, subject tocertain exclusions.

·       Mirant contributed (or caused to be contributed) additionalvalue to Mirant Americas Generation, including:

·        the transfer ofthe Trading Debtors to Mirant North America in return for $250 million of cash;

·        commitments tomake capital contributions: (a) through the issuance by Mirant Americas ofup to $265 million of redeemable Series A Preferred Shares redeemable byMirant Mid-Atlantic to fund environmental capital expenditures, and (b) throughthe issuance by Mirant Americas of $150 million of Series B PreferredShares, redeemable by Mirant Americas Generation, to support the refinancing ofits notes due 2011;

·        the transfer ofMirant Potomac River to Mirant Chalk Point, LLC (“Mirant Chalk Point”) awholly-owned subsidiary of Mirant Mid-Atlantic, and the transfer of MirantPeaker to Mirant Mid-Atlantic and the subsequent merger of Mirant Peaker intoMirant Chalk Point; and

·        the transfer ofMirant Zeeland to Mirant North America.

·       Mirant Mid-Atlantic assumed the Mirant Mid-Atlanticleveraged leases in accordance with the terms of the Plan and subject to theorder of the Bankruptcy Court with respect to the interpretation of certainprovisions of the leveraged lease documentation.

On January 3, 2006,substantially all of the assets of Mirant were transferred to New Mirant, whichhas no successor liability for any unassumed obligations of Mirant.Additionally, Mirant Energy Trading has no successor liability for anyunassumed obligations of the Trading Debtors. After these transfers took place,old Mirant and the Trading Debtors were transferred to a trust created underthe Plan.

***Interest Expense***

In the third quarter of2005, the Company determined that it was probable that contractual interest onliabilities subject to compromise from the Petition Date would be incurred forcertain claims expected to be allowed under the Plan. As a result, the Companyrecorded interest expense of approximately $749 million in 2005 on liabilitiessubject to compromise. This amount represents interest from the Petition Datethrough the effective date of the Plan. The interest amount was calculatedbased on the provisions of the Plan. The $749 million expense amount includedapproximately $452 million related to Mirant Americas Generation senior notesmaturing in 2011, 2021 and 2031, which were reinstated under the Plan.

***Liabilities Subject to Compromise***

At December 31, 2005, amounts related to allowedclaims and estimated unresolved claims that are to be settled in cash are$1.8 billion and are recorded in claims payable and estimated claimsaccrual on the accompanying combined and consolidated balance sheets. Due tothe confirmation of the Plan on December 9, 2005, the Company’sliabilities subject to compromise balances at December 31, 2005, relateonly to those of its New York subsidiaries that remain in bankruptcy.

At December 31, 2004, liabilities subject tocompromise included certain liabilities incurred prior to the Petition Date.The amounts of the various categories of liabilities that were subject tocompromise are set forth below. Such amounts represented the Company’sestimates of known potential claims that were likely to be resolved inconnection with the bankruptcy filings.

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The amounts subjectto compromise at December 31, 2005, and 2004 consisted of the followingitems (in millions):

| ** **                                                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Items, absent the bankruptcy filings, that would  have been considered current at:    |       |     |       |     |       |   |   |
| Accounts payable and  accrued liabilities—affiliate                              |       |     | $          | 16       |       |   | $ | 740 |   |
| Accounts payable and  accrued liabilities—nonaffiliate                           |       |     | 18         |     |       | 868 |   |
| Current portion of  long-term debt                                                    |       |     | —     |     |       | 730 |   |
| Price risk management  liabilities                                                    |       |     | —     |     |       | 80 |   |
| Items, absent the bankruptcy filings, that would  have been considered noncurrent at: |       |     |       |     |       |   |   |
| Price risk management  liabilities                                                    |       |     | —     |     |       | 460 |   |
| Long-term debt                                                                        |       |     | —     |     |       | 2,470 |   |
| Other noncurrent  liabilities                                                         |       |     | —     |     |       | 18 |   |
| Liabilities subject to compromise                                                     |       |     | $          | 34       |       |   | $ | 5,366 |   |

 

***Reorganization Items***

Reorganizationitems, net represents expense or income and gain or loss amounts that wererecorded in the combined statements of operations as a result of the bankruptcyproceedings. The following were the significant items within this category (inmillions): 

| ** **                                                     | ** ** | **Years Ended December 31,** | ** ** |
|----------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                     | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| Estimated claims and  losses on rejected and amended contracts |       | $                                           | 57         |   | $ | 112 |   | $ | 97 |   |
| Professional fees and  administrative expenses                 |       | 82                                          |       | 47 |   | 21 |   |
| Interest income, net                                           |       | (22                                         | )          | (10 | ) | (3 | ) |
| Gain on implementation  of the Plan                            |       | (30                                         | )          | — |   | — |   |
| Total                                                          |       | $                                           | 87         |   | $ | 149 |   | $ | 115 |   |

 

***New York Subsidiaries***

Condensed consolidated balance sheet data as of December 31,2005 is set forth below for the Company’s New York subsidiaries that remain inbankruptcy.

| ** **                                           | ** ** | **December 31,  2005** | ** ** |
|------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                           | ** ** | **(in millions)**      | ** ** |
| Current Assets                                       |       |                        | $          | 32 |   |   |
| Accounts receivable—affiliate                   |       |                        | 41         |   |   |
| Notes receivable—affiliate                      |       |                        | 106        |   |   |
| Property, Plant and  Equipment, net                  |       |                        | 502        |   |   |
| Other                                                |       |                        | 5          |   |   |
| Total Assets                                         |       |                        | $          | 686 |   |   |
| Liabilities not subject  to compromise               |       |                        |       |   |   |
| Short-term debt                                      |       |                        | $          | 12 |   |   |
| Accounts payable and  accrued liabilities            |       |                        | 31         |   |   |
| Payable to affiliate                                 |       |                        | 6          |   |   |
| Accrued property  taxes—nonaffiliate            |       |                        | 136        |   |   |
| Price risk management  liabilities—affiliate    |       |                        | 19         |   |   |
| Other noncurrent  liabilities                        |       |                        | 9          |   |   |
| Liabilities Subject to  Compromise—affiliate    |       |                        | 62         |   |   |
| Liabilities Subject to  Compromise—nonaffiliate |       |                        | 18         |   |   |
| Equity                                               |       |                        | 393        |   |   |
| Total Liabilities and Equity                         |       |                        | $          | 686 |   |   |

 

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**4.**                 Changein Reporting Entity

As discussed in Note 1, pursuant to the Plan Mirantcontributed its interest in the Contributed Subsidiaries to the Companyresulting in a change in the Mirant Americas Generation reporting entity.

Thefollowing tables and discussion summarize the effects of the ContributedSubsidiaries on the previously reported Mirant Americas Generation’sconsolidated statements of operations for 2004 and 2003 (in millions):

| ** **                                                             | ** ** | **For the Year Ended December 31, 2004** | ** ** |
|------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                             | ** ** | **As Previously  Reported**                                       | ** ** | **Adjustments** | ** ** | **Combined** | ** ** |
| Operating Revenues:                                                    |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Affiliate                                                              |       |                                                                   | $          | 1,795 |   |   |   | $ | (1,330 | ) |   |   | $ | 465 |   |   |
| Nonaffiliate                                                           |       |                                                                   | 319        |   |   |   | 2,757 |   |   |   | 3,076 |   |   |
| Total operating revenues                                               |       |                                                                   | 2,114      |   |   |   | 1,427 |   |   |   | 3,541 |   |   |
| Net trading revenue                                                    |       |                                                                   | —     |   |   |   | 27 |   |   |   | 27 |   |   |
| Total operating revenues                                               |       |                                                                   | 2,114      |   |   |   | 1,454 |   |   |   | 3,568 |   |   |
| Cost of fuel, electricity and other  products—affiliate           |       |                                                                   | 1,094      |   |   |   | (963 | ) |   |   | 131 |   |   |
| Cost of fuel, electricity and other  products—nonaffiliate        |       |                                                                   | 195        |   |   |   | 2,114 |   |   |   | 2,309 |   |   |
| Total cost of fuel, electricity and other products                     |       |                                                                   | 1,289      |   |   |   | 1,151 |   |   |   | 2,440 |   |   |
| Gross Margin                                                           |       |                                                                   | 825        |   |   |   | 303 |   |   |   | 1,128 |   |   |
| Operating Expenses:                                                    |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Generation facilities rent                                             |       |                                                                   | 103        |   |   |   | — |   |   |   | 103 |   |   |
| Depreciation and amortization                                          |       |                                                                   | 89         |   |   |   | 40 |   |   |   | 129 |   |   |
| Operations and maintenance—affiliate                              |       |                                                                   | 260        |   |   |   | 78 |   |   |   | 338 |   |   |
| Operations and maintenance—nonaffiliate, including  restructuring |       |                                                                   | 218        |   |   |   | 32 |   |   |   | 250 |   |   |
| Other                                                                  |       |                                                                   | 65         |   |   |   | 2 |   |   |   | 67 |   |   |
| Total operating expenses                                               |       |                                                                   | 735        |   |   |   | 152 |   |   |   | 887 |   |   |
| Operating Income                                                       |       |                                                                   | 90         |   |   |   | 151 |   |   |   | 241 |   |   |
| Other Income  (Expense), net                                           |       |                                                                   | 2          |   |   |   | (3 | ) |   |   | (1 | ) |   |
| Income before  Reorganization Items and Income Taxes                   |       |                                                                   | 92         |   |   |   | 148 |   |   |   | 240 |   |   |
| Reorganization  items, net                                             |       |                                                                   | 89         |   |   |   | 60 |   |   |   | 149 |   |   |
| (Benefit)  provision for income taxes                                  |       |                                                                   | (19        | ) |   |   | 4 |   |   |   | (15 | ) |   |
| Net income                                                             |       |                                                                   | $          | 22 |   |   |   | $ | 84 |   |   |   | $ | 106 |   |   |

 

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| ** **                                                                    | ** ** | **For the Year Ended December 31, 2003** | ** ** |
|-------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                                    | ** ** | **As Previously  Reported**                                       | ** ** | **Adjustments** | ** ** | **Combined** | ** ** |
| Operating Revenues:                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Affiliate                                                                     |       |                                                                   | $          | 1,681 |   |   |   | $ | (1,264 | ) |   |   | $ | 417 |   |   |
| Nonaffiliate                                                                  |       |                                                                   | 334        |   |   |   | 3,310 |   |   |   | 3,644 |   |   |
| Total operating revenues                                                      |       |                                                                   | 2,015      |   |   |   | 2,046 |   |   |   | 4,061 |   |   |
| Net trading revenue                                                           |       |                                                                   | —     |   |   |   | (4 | ) |   |   | (4 | ) |   |
| Total operating revenue                                                       |       |                                                                   | 2,015      |   |   |   | 2,042 |   |   |   | 4,057 |   |   |
| Cost of fuel, electricity and other  products—affiliate                  |       |                                                                   | 1,174      |   |   |   | (1,123 | ) |   |   | 51 |   |   |
| Cost of fuel, electricity and other  products—nonaffiliate               |       |                                                                   | 164        |   |   |   | 2,745 |   |   |   | 2,909 |   |   |
| Total cost of fuel, electricity and other products                            |       |                                                                   | 1,338      |   |   |   | 1,622 |   |   |   | 2,960 |   |   |
| Gross Margin                                                                  |       |                                                                   | 677        |   |   |   | 420 |   |   |   | 1,097 |   |   |
| Operating Expenses:                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Generation facilities rent                                                    |       |                                                                   | 96         |   |   |   | — |   |   |   | 96 |   |   |
| Depreciation and amortization                                                 |       |                                                                   | 121        |   |   |   | 46 |   |   |   | 167 |   |   |
| Operations and maintenance—affiliate                                     |       |                                                                   | 194        |   |   |   | 60 |   |   |   | 254 |   |   |
| Operations and maintenance—nonaffiliate                                  |       |                                                                   | 236        |   |   |   | 62 |   |   |   | 298 |   |   |
| Gain on sales of assets, net                                                  |       |                                                                   | (3         | ) |   |   | (15 | ) |   |   | (18 | ) |   |
| Impairment losses                                                             |       |                                                                   | 2,715      |   |   |   | 315 |   |   |   | 3,030 |   |   |
| Total operating expenses                                                      |       |                                                                   | 3,359      |   |   |   | 468 |   |   |   | 3,827 |   |   |
| Operating loss                                                                |       |                                                                   | (2,682     | ) |   |   | (48 | ) |   |   | (2,730 | ) |   |
| Other Income (Expense),  net:                                                 |       |                                                                   |       |   |   |   |   |   |   |   |   |   |   |
| Other (expense)  income, net                                                  |       |                                                                   | (173       | ) |   |   | (49 | ) |   |   | (222 | ) |   |
| Loss from  Continuing Operations before Reorganization Items and Income Taxes |       |                                                                   | (2,855     | ) |   |   | (97 | ) |   |   | (2,952 | ) |   |
| Reorganization  items, net                                                    |       |                                                                   | 25         |   |   |   | 90 |   |   |   | 115 |   |   |
| Provision  (benefit) for income taxes                                         |       |                                                                   | 113        |   |   |   | (2 | ) |   |   | 111 |   |   |
| Loss from  Continuing Operations                                              |       |                                                                   | (2,993     | ) |   |   | (185 | ) |   |   | (3,178 | ) |   |
| Income (loss)  from Discontinued Operations, net of tax provision        |       |                                                                   | 7          |   |   |   | (28 | ) |   |   | (21 | ) |   |
| Loss before  Cumulative Effect of Change in Accounting Principles        |       |                                                                   | (2,986     | ) |   |   | (213 | ) |   |   | (3,199 | ) |   |
| Cumulative Effect  of Change in Accounting Principles, net of taxes      |       |                                                                   | (3         | ) |   |   | (7 | ) |   |   | (10 | ) |   |
| Net Loss                                                                      |       |                                                                   | $          | (2,989 | ) |   |   | $ | (220 | ) |   |   | $ | (3,209 | ) |   |

 

Historically, the Company’s operating subsidiarieswere party to services agreements with Mirant Americas Energy Marketing. MirantAmericas Energy Marketing was responsible for marketing the output of theCompany’s facilities and procurement of fuel for the Company’s facilities, aswell as for executing contracts, including economic hedges, to reduce pricerisk. Transactions between the operating subsidiaries and Mirant AmericasEnergy Marketing were included in operating revenues—affiliate and cost offuel, electricity, and other products—affiliate, in the previously reportedMirant Americas Generation statements of operations. Because Mirant AmericasEnergy Marketing is part of the combined Mirant Americas Generation financialstatements, these affiliate transactions are now eliminated. In addition,Mirant Americas Energy Marketing’s sales and purchase transactions withnonaffiliates are now reflected in Mirant Americas Generation combinedstatements of operations.

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Thefollowing table and discussion summarizes the effects of the ContributedSubsidiaries on the previously reported Mirant Americas Generation consolidatedbalance sheet at December 31, 2004 (in millions):

| ** **                                           | ** ** | **December 31, 2004**  | ** ** |
|------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                           | ** ** | **As Previously  Reported** | ** ** | **Adjustments** | ** ** | **Combined** | ** ** |
| **Assets**                                           | ** ** |                             | ** ** | ** ** |   |   | ** ** | ** ** |   |   | ** ** | ** ** |   |
| Current Assets:                                      | ** ** |                             | ** ** | ** ** |   |   | ** ** | ** ** |   |   | ** ** | ** ** |   |
| Cash and cash  equivalents                           |       |                             | $          | 414 |   |   |   | $ | 222 |   |   |   | $ | 636 |   |   |
| Funds on deposit                                     |       |                             | —     |   |   |   | 319 | **(1)** |   |   | 319 |   |   |
| Receivables:                                         |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Affiliate, less  allowance for uncollectibles        |       |                             | 246        |   |   |   | 84 | **(3)** |   |   | 330 |   |   |
| Customer accounts                                    |       |                             | 11         |   |   |   | 507 | **(4)** |   |   | 518 |   |   |
| Notes receivable—affiliate                      |       |                             | —     |   |   |   | 50 |   |   |   | 50 |   |   |
| Price risk  management assets—affiliate         |       |                             | 11         |   |   |   | (11 | )**(2)** |   |   | — |   |   |
| Price risk  management assets—nonaffiliate      |       |                             | —     |   |   |   | 216 | **(2)** |   |   | 216 |   |   |
| Prepaid rent and  other payments                     |       |                             | 133        |   |   |   | 34 |   |   |   | 167 |   |   |
| Inventory                                            |       |                             | 162        |   |   |   | 99 |   |   |   | 261 |   |   |
| Assets held for  sale                                |       |                             | 7          |   |   |   | — |   |   |   | 7 |   |   |
| Other current  assets                                |       |                             | 35         |   |   |   | (29 | ) |   |   | 6 |   |   |
| Total current  assets                                |       |                             | 1,019      |   |   |   | 1,491 |   |   |   | 2,510 |   |   |
| Property, Plant,  and Equipment, net                 |       |                             | 2,102      |   |   |   | 725 |   |   |   | 2,827 |   |   |
| Noncurrent Assets:                                   |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Other intangible  assets, net                        |       |                             | 207        |   |   |   | 1 |   |   |   | 208 |   |   |
| Investments                                          |       |                             | —     |   |   |   | 6 |   |   |   | 6 |   |   |
| Notes receivable  from affiliate                     |       |                             | 478        |   |   |   | (223 | )**(5)** |   |   | 255 |   |   |
| Price risk  management assets—affiliate         |       |                             | 1          |   |   |   | (1 | )**(2)** |   |   | — |   |   |
| Price risk  management assets—nonaffiliate      |       |                             | —     |   |   |   | 112 | **(2)** |   |   | 112 |   |   |
| Prepaid rent                                         |       |                             | 197        |   |   |   | — |   |   |   | 197 |   |   |
| Funds on deposit                                     |       |                             | 5          |   |   |   | — |   |   |   | 5 |   |   |
| Accounts  receivable less allowance                  |       |                             | —     |   |   |   | 27 |   |   |   | 27 |   |   |
| Other, less  allowance for uncollectibles of $49     |       |                             | 21         |   |   |   | (11 | ) |   |   | 10 |   |   |
| Total noncurrent  assets                             |       |                             | 909        |   |   |   | (89 | ) |   |   | 820 |   |   |
| Total Assets                                         |       |                             | $          | 4,030 |   |   |   | $ | 2,127 |   |   |   | $ | 6,157 |   |   |
| **Liabilities and Equity  (Deficit)**                |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Current Liabilities:                                 |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Current portion of  long-term debt                   |       |                             | —     |   |   |   | 4 |   |   |   | 4 |   |   |
| Accounts payable and  accrued liabilities            |       |                             | 51         |   |   |   | 361 | **(4)** |   |   | 412 |   |   |
| Payable to  affiliate                                |       |                             | 52         |   |   |   | 6 |   |   |   | 58 |   |   |
| Price risk  management liabilities—affiliate    |       |                             | 62         |   |   |   | (57 | )**(2)** |   |   | 5 |   |   |
| Price risk  management liabilities—nonaffiliate |       |                             | —     |   |   |   | 286 | **(2)** |   |   | 286 |   |   |
| Revenue subject to  refund                           |       |                             | 5          |   |   |   | — |   |   |   | 5 |   |   |
| Transition power  agreement and other obligations    |       |                             | —     |   |   |   | 9 |   |   |   | 9 |   |   |
| Accrued taxes—affiliate                         |       |                             | 51         |   |   |   | 3 |   |   |   | 54 |   |   |
| Accrued taxes                                        |       |                             | 122        |   |   |   | 1 |   |   |   | 123 |   |   |
| Other current  liabilities                           |       |                             | 8          |   |   |   | — |   |   |   | 8 |   |   |
| Total current  liabilities                           |       |                             | 351        |   |   |   | 613 |   |   |   | 964 |   |   |
| Noncurrent Liabilities:                              |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Long-term debt                                       |       |                             | —     |   |   |   | 46 |   |   |   | 46 |   |   |
| Price risk  management liabilities—affiliate    |       |                             | 1          |   |   |   | 2 | **(2)** |   |   | 3 |   |   |
| Price risk  management liabilities—nonaffiliate |       |                             | —     |   |   |   | 62 | **(2)** |   |   | 62 |   |   |
| Deferred income  taxes                               |       |                             | —     |   |   |   | 18 |   |   |   | 18 |   |   |
| Other noncurrent  liabilities                        |       |                             | 46         |   |   |   | (22 | ) |   |   | 24 |   |   |
| Total noncurrent  liabilities                        |       |                             | 47         |   |   |   | 106 |   |   |   | 153 |   |   |
| Liabilities  Subject to Compromise                   |       |                             | 3,438      |   |   |   | 1,928 | **(5)** |   |   | 5,366 |   |   |
| Commitments and Contingencies                        |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Equity (Deficit):                                    |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Deficit Investment  by Mirant                        |       |                             | —     |   |   |   | (326 | ) |   |   | (326 | ) |   |
| Member’s interest                               |       |                             | 3,853      |   |   |   | (3,853 | ) |   |   | — |   |   |
| Accumulated  deficit                                 |       |                             | (3,659     | ) |   |   | 3,659 |   |   |   | — |   |   |
| Total equity                                         |       |                             | 194        |   |   |   | (520 | ) |   |   | (326 | ) |   |
| Total Liabilities  and Equity (Deficit)              |       |                             | $          | 4,030 |   |   |   | $ | 2,127 |   |   |   | $ | 6,157 |   |   |

----

**(1)****           **Funds on deposit represents collateral ofMirant Americas Energy Marketing on deposit with brokers and counterparties.

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**(2)****           **Historically, the Company’s operatingsubsidiaries were party to services agreements with Mirant Americas EnergyMarketing. Mirant Americas Energy Marketing was responsible for executingcontracts, including economic hedges, to reduce price risk. The fair value ofenergy contracts between the operating subsidiaries and Mirant Americas EnergyMarketing were included in the respective price risk management—affiliateaccounts, in the previously reported Mirant Americas Generation balance sheets.Because Mirant Americas Energy Marketing is part of the combined MirantAmericas Generation financial statements, these transactions are noweliminated. In addition, the fair value of energy contracts between MirantAmericas Energy Marketing and nonaffiliates are now reflected in the MirantAmericas Generation combined balance sheet in the respective price risk management—nonaffiliateaccounts.

**(3)****           **Receivables—affiliate increased from thepreviously reported amount as a result of $288 million of receivables due to the Contributed Subsidiaries fromMirant affiliates not included in these combined and consolidated financialstatements. This amount was partially offset by the elimination of receivablesdue to the Company’s operating subsidiaries from Mirant Americas EnergyMarketing.

**(4)****           **Receivables—nonaffiliate and accountspayable and accrued liabilities increased significantly due to the inclusion ofMirant Americas Energy Marketing in the combined balance sheet. These accountsincluded the settled amounts of the energy contracts entered into by MirantAmericas Energy Marketing in the wholesale energy markets.

**(5)****           **Mirant Potomac River and Mirant Peakerowed Mirant Mid-Atlantic $152 million and $71 million, respectively, at December 31,2004. The inclusion of these subsidiaries in the combined Mirant AmericasGeneration balance sheet results in the elimination of the intercompanyamounts. The offsetting eliminating affiliate liability is included in theadjustment to liabilities subject to compromise.

**5.**                 Inventory

Inventoryat December 31, consisted of the following (in millions):

| ** **                      | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------|------------|----------|------------|----------|------------|
| Fuel                            |       | $        | 202        |     | $          | 135 |   |
| Purchased  emissions allowances |       | 15       |       | 58       |       |
| Materials and  supplies         |       | 61       |       | 68       |       |
| Total                           |       | $        | 278        |     | $          | 261 |   |

 

The increase in fuelinventory in 2005 is primarily due to rising commodity prices. The decrease inpurchased emissions allowances is due to utilization of allowances during 2005.

**6.**                 RelatedParty Arrangements and Transactions

***Management, Personnel and Services Agreement withMirant Services***

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

| ** **                                                   | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                   | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| Cost of fuel,  electricity and other products—affiliate |       | $                                           | 10         |   | $ | 10 |   | $ | 8 |   |
| Operations and  maintenance expense—affiliate           |       | 168                                         |       | 170 |   | 197 |   |
| Total                                                        |       | $                                           | 178        |   | $ | 180 |   | $ | 205 |   |

 

***Services and Risk Management Agreements withAffiliates***

The Company, through Mirant Energy Trading, andpreviously Mirant Americas Energy Marketing, provides energy marketing and fuelprocurement services to the following affiliates: Mirant Las Vegas, LLC, MirantSugar Creek, LLC and Mirant Wichita Falls, LP. Amounts due from each affiliateunder their respective service agreements are recorded as a net accountspayable—affiliate or accounts receivable—affiliate because of each subsidiary’slegal right to offset.

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Beginning January 1, 2004, Mirant changed itsallocation methodology related to its energy marketing overhead expenses. Underthe new methodology, substantially all energy marketing costs are now allocatedto Mirant’s operating subsidiaries. During the years ended December 31,2005, 2004 and 2003, the total energy marketing costs were $54 million,$83 million and $23 million, respectively. During the years ended December 31,2005, 2004 and 2003 the Company allocated approximately $8 million, $14 millionand $1 million, respectively, in costs under these agreements to affiliatesthat are not included in the Mirant Americas Generation combined statements ofoperations. These costs allocated to affiliates are included in generationrevenue—affiliate.

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

***AdministrationArrangements with Mirant Services***

In2003 Mirant Services utilized a fixed administration charge to varioussubsidiaries of Mirant, including the Company, which served to reimburse MirantServices for various indirect administrative services performed on the subsidiaries’behalf, including information technology services, regulatory support,consulting, legal and accounting and financial services. The fixed charge wasapproximately $4.7 million per month in 2003. Beginning January 1, 2004,Mirant changed its allocation methodology related to the allocation of itscorporate overhead expenses. Under the new methodology, substantially all ofMirant’s corporate overhead costs are now allocated to Mirant’s operatingsubsidiaries.

For the years ended December 31, 2005, 2004 and2003, the Company incurred approximately $133 million, $168 millionand $57 million, respectively, in costs under these arrangements, whichare included in operations and maintenance-affiliate in the accompanyingcombined statements of operations.

***Make-WholeReimbursement Agreement***

Under the asset purchase and sale agreement for thePotomac Electric Power Company (“PEPCO”) generating assets, Mirant assumed andrecorded net obligations of approximately $2.4 billion, representing theestimated fair value (at the date of acquisition) of out-of-market energydelivery and power purchase agreements (“PPAs”), which consisted of five PPAsand two TPAs. The estimated fair value of the contracts was derived usingforward prices obtained from brokers and other external sources in the marketplace, including brokers and trading platforms/exchanges such as New YorkMercantile Exchange (“NYMEX”) and estimated load information. Mirant AmericasEnergy Marketing assumed these obligations from Mirant pursuant to a liabilityassignment agreement.

Mirant Americas and Mirant Americas Energy Marketingentered into a Make-Whole Reimbursement Agreement (the “Make-Whole Agreement”),whereby Mirant Americas was obligated to reimburse Mirant Americas EnergyMarketing for losses arising from the TPAs, PPAs, and related hedges of theseagreements. In any month that Mirant Americas Energy Marketing realized netgains related to the TPAs, PPAs, and related hedges, it was required to paythese amounts to Mirant Americas. Amounts received were recorded as capitalcontributions and amounts paid were recorded as capital distributions in theaccompanying combined financial statements. Payments received from MirantAmericas under the Make-Whole Agreement in 2004 and 2003 were $7 millionand $315 million, respectively. Amounts paid to Mirant Americas under theMake-Whole Agreement were $29 million in 2003. Under the Plan, claimsarising out of the Make-Whole Agreement were resolved pursuant to a globalsettlement, whereby intercompany claims did not receive distributions.

***Salesto Mirant Energy Marketing Canada***

Historically, Mirant Americas Energy Marketingpurchased natural gas from Mirant Energy Marketing Canada, a subsidiary ofMirant. These purchases were reflected in net trading revenue—affiliate on thecombined statements of operations. The natural gas was sold to third parties;therefore, the revenue was reflected in net trading revenue—nonaffiliate in thecombined statements of operations. In 

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2003, Mirant sold asubstantial portion of the Canadian operation and decided to exit the remainingelements of their trading business in Canada. Gas purchases from Mirant EnergyMarketing Canada for the years ended December 31,2005, 2004 and 2003 were $3 million, $17 million and $718 million,respectively.

***Restructuring Charges***

During the years ended December 31, 2005, 2004and 2003, the Company recorded restructuring charges of $3 million,$5 million and $9 million, respectively, for severance costs andother charges, which are included in operations and maintenance—affiliate inthe accompanying combined statements of operations. During the year ended December 31,2003, the Company recorded restructuring charges of $4 million for severancecosts and costs related to suspending planned power plant developments, whichare included in operations and maintenance—nonaffiliate in the accompanyingcombined statements of operations. The severance costs and other employeetermination-related charges associated with the restructuring at theCompany’s locations were paid by Mirant Services and billed to the Company andare included in the amounts disclosed above for management, personnel andservices.

***TurbineLease Facility Arrangement***

At December 31, 2004, the Company had accountsreceivable from affiliate with Mirant Americas of $147 million and Mirant Americas Procurement, Inc. of$71 million. These amounts related to a warehouseoperating lease facility arrangement. Amounts dueto third parties under this arrangement were $214 million andamounts due to affiliates were $3 million. These amounts were included inliabilities subject to compromise at December 31, 2004. Pursuant to thePlan, the pre-petition receivables from affiliate were resolved pursuant to aglobal settlement, whereby intercompany claims did not receive anydistribution.

***NotesReceivable from Affiliate*** and Notes Payable to Affiliate

Duringthe pendency of the Chapter 11 proceedings, Mirant and certain of itssubsidiaries participated in an intercompany cash management program approvedby the Bankruptcy Court, pursuant to which cash balances at Mirant and theparticipating subsidiaries were transferred to central concentration accountsand, if necessary, lent to Mirant or any participating subsidiary to fundworking capital and other needs, subject to the intercompany borrowing limitsapproved by the Bankruptcy Court. At December 31, 2005, the Company hadcurrent note payable to affiliate of $21 million and at December 31, 2004,the Company had current notes receivable from affiliate of $44 millionrelated to the intercompany cash management program. The Company had currentnotes receivable from affiliate of $6 million at December 31, 2004related to the disposal of the Mirant Americas Energy Capital Assets.

At December 31, 2004, unsecured noncurrent notesreceivable from affiliate consisted of a $255 million note receivable fromMirant Americas, which was contributed to the Company effective January 1,2002, when Mirant Americas transferred its ownership interest in Mirant NewEngland to the Company. The note was payable on demand with 6% interest, whichwas payable monthly. Interest earned by the Company from Mirant Americas wasapproximately $8 million for the year ended December 31, 2003. TheCompany did not record any interest income on this note since the Petition Dateand due to the bankruptcy proceedings, the Company classified the notereceivable as long-term notes receivable from affiliate at December 31,2004. Interest earned would have been $15 million for each of the yearsended December 31, 2005 and 2004, if not for the bankruptcy proceeding.Pursuant to the Plan, this noncurrent note receivable from affiliate wasresolved pursuant to a global settlement, whereby intercompany claims did notreceive any distribution.

***Payableto Mirant Americas Pursuant to the Plan***

Under the Plan, the Company was required to pay $250million to Mirant Americas within five days of the effective date of the Planin return for Mirant’s contribution of the Trading Debtors. This amount isincluded in payable to affiliate at December 31, 2005 in the consolidatedbalance sheet and was paid in January 2006.

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***Mirant Guarantees***

In 2004 and 2003 MirantNew England, was required to sell electricity at fixed prices to CambridgeElectric Light Company (“Cambridge”) and Commonwealth Electric Company(“Commonwealth”) in order for them to meet their supply requirements to certainretail customers. In April 2002, Mirant issued a guarantee in the amountof $188 million for any obligations Mirant New England may incur under itsWholesale Transition Service Agreement with Cambridge and Commonwealth. Boththe guarantee and the agreement expired in February 2005.

Mirant posted pre-petitionletters of credit and a guarantee on behalf of Mirant Mid-Atlantic to providefor the rent payment reserve required in connection with Mirant Mid-Atlantic’slease obligations in the event that it is unable to pay its lease paymentobligations. In June 2005 and September 2005, the full amount of thepre-petition letters of credit was drawn in the amount of $61 million. OnJanuary 3, 2006, as part of the settlement and the Company’s emergence frombankruptcy, Mirant North America posted a $75 million letter of credit for thebenefit of Mirant Mid-Atlantic to cover debt service reserve obligations onMirant Mid-Atlantic’s leases. Upon the posting of the letter of credit, thetrustee returned $56 million of cash collateral to Mirant Mid-Atlantic.

Mirant posted apost-petition letter of credit in the amount of $5 million on behalf of MirantTexas as of December 31, 2004 related to a tolling agreement. Thispost-petition letter of credit was set to expire in January 2006. Uponemergence from bankruptcy, Mirant North America replaced this post-petitionletter of credit with a letter of credit issued under its senior secured creditfacilities. The letter of credit expires in June 2006.

Priorto 2005, Mirant entered into pre-petition letters of credit to support theCompany’s asset management activities. In September 2005, several of theseletters of credit were drawn in the amount of $39 million. InJanuary 2006, the remaining pre-petition letter of credit of $7 millionwas drawn in full. In addition, Mirant entered into post-petition letters ofcredit to support its asset hedging activities. In January 2006, lettersof credit from the Mirant North America senior secured credit facilitiesreplaced the eleven post-petition letters of credit outstanding atDecember 31, 2005.

***Preferred Stock In Mirant Americas***

ThePlan provided for Mirant Americas, the Company’s indirect parent to makecertain capital contributions to Mirant Americas Generation and Mirant Mid-Atlantic.These capital contributions were made in the form of mandatory redeemablepreferred stock in Mirant Americas.

***Series A Preferred Shares***

InDecember 2005, Mirant Americas issued preferred shares to MirantMid-Atlantic (the “Series A Preferred Shares”) for the purpose of fundingfuture environmental capital expenditures. The Series A Preferred Shareshave a mandatory redemption scheduled for June 30 of each year (“ScheduledRedemption Date”) at a price equal to the portion of the liquidation preference(“Specified Redemption Amount”) as follows (in millions):

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

 

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The redemption of any of the Series A PreferredShares on any Scheduled Redemption Date shall be deferred to the extent thatMirant Mid-Atlantic has not incurred prior to the Scheduled Redemption Date, ordoes not reasonably expect to incur within 180 days of such ScheduledRedemption Date, expenditures with respect to the installation of controltechnology related to environmental capital expenditures of facilities owned orleased by Mirant Mid-Atlantic. Any amounts so deferred shall be added to theamount of Series A Preferred Shares to be redeemed on the next ScheduledRedemption Date.

Mirant Mid-Atlantic has the right to put theSeries A Preferred Shares to Mirant at an amount equal to the SpecifiedRedemption Amount in the event that Mirant Americas fails to redeem theSeries A Preferred Shares on a Scheduled Redemption Date.

The Series APreferred Shares are recorded at a fair value of $208 million as a component ofequity in the Company’s consolidated balance sheet at December 31, 2005.The fair value was determined using a discounted cash flow method based on theSpecified Redemption Amounts using a 6.21% discount rate.

***Series B Preferred Shares***

In December 2005, Mirant Americas issuedpreferred shares to Mirant Americas Generation (the “Series B PreferredShares”) for the purpose of supporting the refinancing of $850 million ofMirant Americas Generation senior notes due in 2011. The Series BPreferred Shares have a mandatory redemption date of April 1, 2011, for the liquidationpreference amount of $150 million. At any time after June 30, 2010, MirantAmericas Generation has the right to put the Series B Preferred Shares toMirant at the liquidation preference amount.

The Series BPreferred Shares are recorded at a  fairvalue of $111 million as a component of equity in the Company’s consolidatedbalance sheet at December 31, 2005. The fair value was determined using adiscounted cash flow method based on the expected redemption date and theliquidation preference amount using a 6.21% discount rate.

**7.      Derivative Financial Instruments**

***Interest Rate Hedging***

Historically, the Company has entered into interestrate swaps in which it agreed to exchange, at specified intervals, thedifference between fixed and variable interest amounts calculated by referenceto agreed-upon notional amounts. These interest rate swaps weredesignated to hedge the variable interest rate risk in the underlying debtobligations. For swaps that qualify as cash flow hedges, the changes in thefair value of the swaps are deferred in other OCI, and reclassified from OCI asan adjustment to interest expense over the term of the hedged instruments.Gains and losses resulting from the termination of qualifying hedges prior totheir stated maturities were recognized ratably over the remaining term of thehedged instruments. At December 31, 2005, the Company was not a party toany interest rate swaps. Pursuant to the bankruptcy proceedings, interestpayments were suspended on the debt associated with the Company’s interest rateswaps accounted for as qualifying hedges that had previously been settled.Therefore, the remaining losses related to these interest rate hedges totaling$52 million after tax, were reclassified from OCI to earnings in 2003,effective with the Chapter 11 filing.

***Commodity Financial Instruments***

The Company manages the risks around fuel supply andpower to be generated from its physical asset positions (“asset management”),and attempts to achieve incremental returns by entering into additional energycontracts where it has specific market expertise or physical asset positions (“proprietarytrading”).

The Company enters into a variety of derivativefinancial and physical instruments to manage its exposure to the prices of thefuel it acquires for generating electricity, as well the electricity producedthat 

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it sells. These includecontractual agreements, such as forward purchase and sale agreements, futures,swaps and option contracts. Futures are traded on national exchanges and swapsare typically traded in over-the-counter financial markets. Option contractsare traded on both a national exchange and in over-the-counter financialmarkets. These contractual agreements have varying terms, notionals, anddurations, or tenors, which range from a few days to a number of years,depending on the instrument. As part of its proprietary trading activities, theCompany is exposed to certain market risks in an effort to generate gains fromchanges in market prices by entering into derivative instruments, includingexchange-traded and over-the-counter contracts, as well as othercontractual arrangements.

Derivative instruments are recorded at their estimatedfair value in the Company’s accompanying combined and consolidated balancesheets as price risk management assets and liabilities except for a limitednumber of transactions that qualify for the normal purchase or normal saleexception election that allows accrual accounting treatment. Changes in thefair value and settlements of electricity derivative financial instruments usedfor asset management purposes are reflected in generation revenue and changesin the fair value and settlements of fuel derivative contracts used for assetmanagement purposes are reflected in cost of fuel and other products in theaccompanying combined statements of operations. Changes in the fair value andsettlements of derivatives held for trading purposes are reflected in nettrading revenues in the accompanying combined statements of operations. As of December 31,2005, the Company does not have any derivative instruments for which hedgeaccounting has been elected.

Thefair values of Mirant Americas Generation’s price risk management assets andliabilities, net of credit reserves, as of December 31, 2005, are includedin the following table (in millions):

| ** **     | ** ** | ** **  | ** ** | ** **      | ** ** | ** **            | ** ** | ** **     | ** ** | **Net Fair Value at** | ** ** |
|----------------|------------|-------------|------------|-----------------|------------|-----------------------|------------|----------------|------------|--------------------------------------|------------|
| ** **     | ** ** | **Assets**  | ** ** | **Liabilities** | ** ** | **December 31,** | ** ** |
| ** **     | ** ** | **Current** | ** ** | **Noncurrent**  | ** ** | **Current**           | ** ** | **Noncurrent** | ** ** | **2005**                             | ** ** |
| Electricity    |       |        | $          | 450             |       |                  |       | $              | 51         |                                 |       |   | $ | (676 | ) |   |   | $ | (6 | ) |   |   | $ | (181 | ) |   |
| Natural gas    |       |        | 113        |            |       |                  | 19         |           |       |                                 | (112       | ) |   |   | (20 | ) |   |   | — |   |   |
| Oil            |       |        | 20         |            |       |                  | —     |           |       |                                 | (5         | ) |   |   | — |   |   |   | 15 |   |   |
| Residual/other |       |        | 21         |            |       |                  | 35         |           |       |                                 | (3         | ) |   |   | (1 | ) |   |   | 52 |   |   |
| Total          |       |        | $          | 604             |       |                  |       | $              | 105        |                                 |       |   | $ | (796 | ) |   |   | $ | (27 | ) |   |   | $ | (114 | ) |   |

 

The volumetric weighted average maturity, or weightedaverage tenor, of the price risk management portfolio at December 31,2005, was seven months. The net notional amount, or net short position, of theprice risk management assets and liabilities at December 31, 2005, wasapproximately 8 million equivalent MWh.

In January 2006, the Company entered intofinancial swap transactions with a third party, the effect of whicheconomically hedged the Company’s Mid-Atlantic expected on-peak coal fired generation by approximately80%, 50% and 50% for 2007, 2008 and 2009, respectively.

Thefair values of Mirant Americas Generation’s price risk management assets andliabilities, net of credit reserves, as of December 31, 2004, are includedin the following table (in millions):

| ** **     | ** ** | ** **  | ** ** | ** **      | ** ** | ** **            | ** ** | ** **     | ** ** | **Net Fair Value at** | ** ** |
|----------------|------------|-------------|------------|-----------------|------------|-----------------------|------------|----------------|------------|--------------------------------------|------------|
| ** **     | ** ** | **Assets**  | ** ** | **Liabilities** | ** ** | **December 31,** | ** ** |
| ** **     | ** ** | **Current** | ** ** | **Noncurrent**  | ** ** | **Current**           | ** ** | **Noncurrent** | ** ** | **2004**                             | ** ** |
| Electricity    |       |        | $          | 106             |       |                  |       | $              | 85         |                                 |       |   | $ | (201 | ) |   |   | $ | (45 | ) |   |   | $ | (55 | ) |   |
| Natural gas    |       |        | 59         |            |       |                  | 26         |           |       |                                 | (66        | ) |   |   | (19 | ) |   |   | — |   |   |
| Oil            |       |        | 46         |            |       |                  | 1          |           |       |                                 | (24        | ) |   |   | (1 | ) |   |   | 22 |   |   |
| Residual/other |       |        | 5          |            |       |                  | —     |           |       |                                 | —     |   |   |   | — |   |   |   | 5 |   |   |
| Total          |       |        | $          | 216             |       |                  |       | $              | 112        |                                 |       |   | $ | (291 | ) |   |   | $ | (65 | ) |   |   | $ | (28 | ) |   |

 

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**8.**   Property,Plant and Equipment

Property,plant and equipment consisted of the following at December 31, 2005 and2004 (in millions):

| ** **                                | ** ** | **2005** | ** ** | **2004** | ** ** | **Depreciable  Lives (years)** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|-------------------------------------|------------|
| Production                                |       | $        | 3,062      |     | $          | 3,016                               |       |   | 9 to  42 |   |   |
| Land                                      |       | 40       |       | 40       |       |                                | —     |   |   |
| Oil pipeline                              |       | 26       |       | 25       |       |                                | 25         |   |   |
| Construction work  in progress            |       | 74       |       | 70       |       |                                | —     |   |   |
| Other                                     |       | 3        |       | 6        |       |                                | 28         |   |   |
| Suspended  construction projects          |       | 174      |       | 174      |       |                                | —     |   |   |
| Less accumulated  depreciation            |       | (571     | )          | (504     | )          |                                |       |   |   |
| Total property,  plant and equipment, net |       | $        | 2,808      |     | $          | 2,827                               |       |   |   |   |   |

 

The Company does not expect to independently completeits suspended construction projects. The Company plans to either pursuepartnerships to complete one or more of the projects, sell the projects, orabandon the projects. In the year ended December 31, 2004, the Companycompleted the sale of turbines that had been part of a suspended constructionproject at its Bowline facility. These turbines had a book value of$107 million. The proceeds received in 2004 were $42 million and theCompany collected an additional $4 million in March 2005.

Depreciation of the recorded cost of depreciableproperty, plant and equipment is recognized on a straight-line basis over theestimated useful lives of the assets. The Company received emissions allowancesin the acquisition of the PEPCO assets for both SO2 and NOx emissions and theright to future allowances. The acquired allowances related to owned facilitiesare included in production assets above, and are depreciated over the averagelife of the related assets. Mirant Americas Generation does not depreciate itssuspended construction project costs.

Mirant Americas Generation evaluates its long-livedassets (property, plant and equipment) and definite-lived intangibles forimpairment whenever events or changes in circumstances indicate that theCompany may not be able to recover the carrying amount of the asset. An assetimpairment charge must be recognized if the sum of the undiscounted expectedfuture cash flows from a long-lived asset or definite-livedintangible is less than the carrying value of that asset. The amount of anyimpairment charge is calculated as the excess of the carrying value of theasset over its fair value. Fair value is estimated based on the discountedfuture cash flows from that asset or determined by other valuation techniques.In the case of assets the Company expects to sell, the impairment charge isbased on the estimated sales value less costs to sell.

Followingis a summary of long-lived asset impairment charges related to property,plant and equipment recorded for the year ended December 31, 2003(in millions):

| Property, plant  and equipment, in service |   | $   | 726    |   |
|--------------------------------------------|--------|-----|--------|--------|
| Suspended  construction projects           |   | 132 |   |
| Total                                      |   | $   | 858    |   |

 

For purposes of testingfor impairment losses, the Company groups long-lived assets and definite-livedintangibles at the lowest level at which separate cash flows can be identified,which generally was determined to be the individual generating assets orseveral generating assets operated as a group. The long-lived assetsevaluated for impairment consist of property, plant and equipment, constructionwork in progress, development rights, trading rights, acquired emissionsallowances and other definite-lived intangibles.

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**9.**   Goodwilland Other Intangible Assets

***Goodwill***

The Company evaluated goodwill and indefinite-livedintangible assets for impairment at least annually and periodically ifindicators of impairment were present. The results of the Company’s analysis in2003 indicated that goodwill was impaired and the Company recorded animpairment charge of $1.9 billion, representing the entire balance of goodwill,in the accompanying combined statement of operations for the year ended December 31,2003.

The critical assumptions used in the Company’simpairment analysis included the following: assumptions as to the futureelectricity and fuel prices; future levels of gross domestic product growth;levels of supply and demand; future operating and capital expenditures; andestimates of the Company’s weighted average cost of capital.

The above assumptions werecritical to the Company’s determination of the fair value of its goodwill. Thecombined subjectivity and sensitivity of the assumptions and estimates used inthe goodwill impairment analysis could result in a reasonable person concludingdifferently on those critical assumptions and estimates, possibly resulting inan impairment charge having been required for a lesser amount.

***Other Intangible Assets***

Followingis a summary of other intangible assets at December 31, 2005 and 2004(in millions):

| ** **                     | ** ** | ** **                  | ** ** | **2005**                | ** ** | **2004**         | ** ** |
|--------------------------------|------------|-----------------------------|------------|-------------------------|------------|------------------|------------|
| ** **                     | ** ** | **Weighted Average**   | ** ** | **Gross Carrying** | ** ** | **Accumulated**  | ** ** | **Gross Carrying** | ** ** | **Accumulated** | ** ** |
| ** **                     | ** ** | **Amortization Lives** | ** ** | **Amount**              | ** ** | **Amortization** | ** ** | **Amount** | ** ** | **Amortization** | ** ** |
| Trading rights                 |       |                        | 26 years   |                    |       |             | $          | 27 |   |   |   | $ | (2 | ) |   |   | $ | 27 |   |   |   | $ | (1 | ) |   |
| Development  rights            |       |                        | 40 years   |                    |       |             | 62         |   |   |   | (7 | ) |   |   | 62 |   |   |   | (7 | ) |   |
| Emissions  allowances          |       |                        | 32 years   |                    |       |             | 151        |   |   |   | (21 | ) |   |   | 131 |   |   |   | (15 | ) |   |
| Other intangibles              |       |                        | 30 years   |                    |       |             | 13         |   |   |   | (2 | ) |   |   | 13 |   |   |   | (2 | ) |   |
| Total other  intangible assets |       |                        |       |                    |       |             | $          | 253 |   |   |   | $ | (32 | ) |   |   | $ | 233 |   |   |   | $ | (25 | ) |   |

 

Trading rights represent intangible assets recognizedin connection with asset purchases that represent the Company’s ability togenerate additional cash flows by incorporating the Company’s proprietarytrading activities with the acquired generating facilities.

Development rights represent the right to expandcapacity at certain acquired generating facilities. The existinginfrastructure, including storage facilities, transmission interconnections,and fuel delivery systems, and contractual rights acquired by the Companyprovide the opportunity to expand or repower certain generation facilities.

Emissions allowances recorded in intangible assetsrelate to allowances granted for the leasehold baseload units at the Morgantownand Dickerson facilities, as well as the Company’s units in California.Allowances granted by the EPA for other owned assets are recorded withinproperty, plant and equipment, net on the combined and consolidated balancesheets.

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

Amortization expense was approximately $8 million, $8 millionand $17 million for the years ended December 31, 2005, 2004 and 2003,respectively. Assuming no future acquisitions, dispositions or impairments ofintangible assets, amortization expense is estimated to be $8 million foreach of the next five years.

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Followingis a summary of impairment charges related to intangible assets recorded forthe year ended December 31, 2003 (in millions):

| Trading rights        |   | $  | 145    |   |
|-----------------------|--------|----|--------|--------|
| Development  rights   |   | 81 |   |
| Emissions  allowances |   | 6  |   |
| Total                 |   | $  | 232    |   |

 

**10.**   Dispositionsand Assets Held for Sale

*Disposition ofAssets*

On September 13, 2005,Mirant Mid-Atlantic executed an agreement to sell its Mirant service centerbuilding and accompanying 68 acres located in Upper Marlboro, Maryland for $13million. Mirant expects to close on a sale of the building on or before December 31,2006.

During the fourth quarterof 2004, the Company entered into an agreement to dispose of three natural gasturbines related to a suspended construction project. The sale resulted in theCompany receiving $42 million in the fourth quarter of 2004 and $4 million inthe 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 isincluded in loss (gain) on sales of assets, net in the combined statements ofoperations. In 2003, the Company recognized a gain of $15 million on thesale of firm transportation agreements to Cargill, and a gain of$3 million on the sale of crude oil.

*DiscontinuedOperations*

In the first quarter of 2003, the Company completedthe sale of its Neenah generating facility for approximately $109 million.The asset was sold at approximately book value. In May and August 2003,Mirant Americas Energy Capital completed the sale of its two remaininginvestments for approximately $41 million and $3 million,respectively, which approximated book value.

Asummary of operating results for these discontinued operations prior to theirdisposal for the year ended December 31, 2003 follows (in millions):

| Operating revenues                                         |   | $   | 1      |   |
|------------------------------------------------------------|--------|-----|--------|--------|
| Operating  expenses, including other income (expense), net |   | (21 | )      |
| Loss before income taxes                                   |   | (20 | )      |
| Income taxes                                               |   | 1   |   |
| Net loss                                                   |   | $   | (21    | )      |

 

*Discontinuance ofActivities*

Certain of the Contributed Subsidiaries do not havesignificant ongoing operating activities. The historical nature of the entitiesis described below.

Mirant Americas Energy Capital was formed in 1999 toengage in the business of providing equity investment or secured financing toindependent oil and gas producers for the purpose of developing, acquiring, orrefinancing proved or producing oil and gas properties in the United States. MirantAmericas Energy Capital did in some instances use its affiliate, MirantAmericas Energy Marketing, to market the gas of the entities in which itinvested. Mirant Americas Energy Capital Assets was later formed as asubsidiary of Mirant Americas Energy Capital to engage in similar activities.Mirant Americas Production Company was formed in 2001 for the purpose ofacquiring non-operating, undivided interests in certain oil and gas producingproperties. Mirant disposed of the majority of the significant assets andoperations of 

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Mirant Americas EnergyCapital, Mirant Americas Energy Capital Assets, and Mirant Americas ProductionCompany in a series of transactions between December 2002 and August 2003.As of December 31, 2004, Mirant Americas Energy Capital had notesreceivable from affiliate of $6 million. Pursuant to the Plan, thepre-petition note receivable from affiliate was resolved pursuant to a globalsettlement, whereby intercompany claims did not receive any distribution.

Mirant Americas Developmentand Mirant Americas Development Capital were formed to support Mirant’sbusiness development activities. For example, permits or other contracts wouldbe entered into by Mirant Americas Development and later transferred to a newMirant subsidiary once formed. Mirant Americas Development Capital was theentity used to facilitate a turbine lease facility. The activities of theseentities related to greenfield development projects and substantially ceased in2003. As of December 31, 2004, Mirant Americas Development had receivablesfrom affiliate of $224 million. Pursuant to the Plan, the pre-petitionreceivables from affiliate were resolved pursuant to a global settlement,whereby intercompany claims did not receive any distribution.

*Assets Held forSale*

TheCompany reclassified $7 million related to the Mirant service center buildingfrom property, plant and equipment to assets held for sale as of December 31,2005 and 2004, in the accompanying combined and consolidated balance sheets.

**11.**   Long-Term Debt

Long-termdebt at December 31, 2005 was as follows (in millions):

| ** **                                                         | ** ** | **Interest Rate** | ** ** | **2005** | ** ** | **Secured/  Unsecured** | ** ** |
|--------------------------------------------------------------------|------------|------------------------|------------|----------|------------|-------------------------|------------|
| **Long Term Debt:**                                                |       |                   |       |     |       |                    |       |
| Mirant Americas  Generation, Senior Notes, due 2011, 2021 and 2031 |       | 8.3%,  8.5% and 9.125% |       | $        | 1,696      |                    | Unsecured  |   |
| Mirant North  America Notes, due 2013                              |       | 7.375%                 |       | 850      |       | Unsecured               |       |
| Capital Leases,  due 2012 through 2015                             |       | 8.19%  and 9.5%        |       | 47       |       | —                  |       |
| Total                                                              |       |                   |       | 2,593    |       |                    |       |
| Less: current  portion of long term debt                           |       |                   |       | 3        |       |                    |       |
| Total long term debt,  excluding current portion                   |       |                   |       | $        | 2,590      |                    |       |   |

 

Pursuant to the Plan,Mirant Americas Generation reinstated $1.7 billion of senior notes maturing in2011, 2021 and 2031, and agreed to pay $452 million of accrued interest.Pursuant to the Plan, the Company and its subsidiaries eliminated approximately$1.5 billion of debt.

***Senior Secured Credit Facilities***

The Mirant North America senior secured creditfacilities are comprised of an $800 million six-year senior securedrevolving credit facility and a $700 million seven-year senior securedterm loan. The full amount of the senior secured revolving credit facility isavailable for the issuance of letters of credit. The senior secured term loanwas made in a single drawing at closing and will amortize in nominal quarterlyinstallments aggregating 0.25% of the original principal of the term loan perquarter for the first 27 quarters, with the remainder payable on the finalmaturity date. In connection with the closing, $200 million of drawingsunder the senior secured term loan were deposited into a cash collateralaccount to support the issuance of up to $200 million of letters of creditissued under the senior secured term loan.

Loans under the senior secured credit facilities areavailable at either of the following rates: (i) a fluctuating rate ofinterest per annum equal to on any given day the greater of (a) theinterest rate per 

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annum publicly announcedby JPMorgan Chase Bank, N.A. as its prime rate in effect at its principaloffice in New York City on that day, and (b) the federal funds rate ineffect on that day plus 0.50%, plus the applicable margin described below (“baserate”), or (ii) a fixed rate determined for certain interest periodsselected equal to U.S. dollar London InterBank Offered Rate (“LIBOR”) plus theapplicable margin described below (“Eurodollar rate”).

The applicable margin withrespect to loans under the senior secured revolving credit facility is 1.25% inthe case of base rate loans, or 2.25% in the case of Eurodollar rate loans. Theapplicable margin will also be subject to a possible reduction of up to 0.50%based on the achievement and maintenance of certain leverage ratios by MirantNorth America. The applicable margin with respect to the senior secured termloan is 0.75% in the case of base rate loans, or 1.75% in the case ofEurodollar rate loans.

***Senior Notes***

Mirant North America Escrow, LLC (“Mirant NorthAmerica Escrow”) and its wholly-owned subsidiary, MNA Finance Corp. issuednotes in an aggregate principal amount of $850 million which bear interest at 7.375%,and mature on December 31, 2013 (the “Notes”). Interest on the Notes ispayable on each June 30 and December 31, commencing June 30,2006. Mirant North America Escrow was a wholly-owned subsidiary of Mirant NorthAmerica. Upon emergence, Mirant North America Escrow was merged with and intoMirant North America with Mirant North America as the surviving entity. Uponthe consummation of the merger, Mirant North America assumed all of theobligations of Mirant North America Escrow and MNA Finance Corp. became a direct,wholly-owned subsidiary of Mirant North America. MNA Finance Corp. was formedand exists solely for the purpose of serving as a co-issuer of the notes and asa guarantor of the senior secured credit facilities.

The Notes are redeemable at the option of Mirant NorthAmerica, in whole or in part, at any time prior to December 31, 2009, at aprice 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 upto 35% of the original principal amount of the Notes with the proceeds ofcertain equity offerings at a redemption price of 107.375% of the principalamount of the Notes, together with accrued and unpaid interest, if any, to thedate of redemption. Under the terms of the Notes, the occurrence of a change ofcontrol will be a triggering event requiring Mirant North America to offer topurchase all or a portion of the Notes at a price equal to 101% of theirprincipal amount, together with accrued and unpaid interest, if any, to thedate of purchase. In addition, certain asset dispositions or casualty eventswill be triggering events which may require Mirant North America to use theproceeds from those asset dispositions or casualty events to make an offer topurchase the notes at 100% of their principal amount, together with accrued andunpaid interest, if any, to the date of purchase if such proceeds are nototherwise used, or committed to be used, within certain time periods, to repaysenior secured indebtedness, to repay indebtedness under the senior securedcredit facilities (with a corresponding reduction in commitments) or to investin capital assets related to its business.

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At December 31,2005, the annual scheduled maturities of debt, during the next five years andthereafter were as follows (in millions):

| 2006       |   | $     | 3      |   |
|------------|--------|-------|--------|--------|
| 2007       |   | 3     |   |
| 2008       |   | 4     |   |
| 2009       |   | 4     |   |
| 2010       |   | 5     |   |
| Thereafter |   | 2,574 |   |
| Total      |   | $     | 2,593  |   |

 

Concurrentwith the emergence from bankruptcy of the Company and its subsidiaries, thefollowing senior unsecured indebtedness was terminated in conjunction withsettlement provisions of the Plan. The Company and its subsidiaries have nooutstanding obligations with respect to the following indebtedness (inmillions):

| **Mirant Americas Generation Debt:**         | ** ** | ** ** | ** ** | **Principal** | ** ** |
|-------------------------------------------------------------|------------|------------|------------|---------------|------------|
| Mirant Americas  Generation Bonds (7.625%, 2006)            |       |       | $          | 500           |       |   |
| Mirant Americas  Generation Bonds (7.20%, 2008)             |       |       | 300        |          |       |
| Mirant Americas  Generation Credit Facilities               |       |       | 300        |          |       |
| Mirant Americas  Energy Marketing Commodity Prepay          |       |       | 216        |          |       |
| Mirant Americas  Development Capital Turbine Lease Facility |       |       | 214        |          |       |
| Total                                                       |       |       | $          | 1,530         |       |   |

 

***Capital Leases***

Long-term debt includes the Company’s two capitalleases. At December 31, 2005 and 2004, the total amount outstanding underthe capital leases was $47 million and $50 million, respectively. At December 31,2005 and 2004, the current portion of the long-term debt under these capitalleases was $3 million and $4 million, respectively.

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The amount outstanding under the Mirant Peakerelectric power generation facility capital lease which matures in 2015 is $36million with an 8.19% annual interest rate. The annual principal payments underthis lease are approximately $3 million in 2006 through 2010 and $21 millionthereafter.

The amount outstanding under the Mirant Zeelandcapital lease which matures in 2012 is $11 million with a 9.5% annualinterest rate. This lease is of a pipeline to the Mirant Zeeland generationfacility. The annual principal payments under this lease are less than $1 millionin 2006 and 2007, approximately $1 million in 2008 and 2009, $2 millionin 2010 and $6 million thereafter.

Thefollowing is a summary of the assets under each respective capital lease,recorded in property, plant and equipment, net at December 31, 2005 and2004 (in millions):

| ** **     | ** ** | **December 31, 2005** | ** ** | **December 31, 2004** | ** ** |
|----------------|------------|---------------------------------|------------|---------------------------------|------------|
| ** **     | ** ** | **Gross  Amount**               | ** ** | **Accumulated  Depreciation**   | ** ** | **Gross  Amount** | ** ** | **Accumulated  Depreciation** | ** ** |
| Mirant Peaker  |       |                            | $          | 24                              |       |   |   | $ | (8 | ) |   |   | $ | 24 |   |   |   | $ | (7 | ) |   |
| Mirant Zeeland |       |                            | 12         |                            |       |   | (2 | ) |   |   | 12 |   |   |   | (1 | ) |   |
| Total          |       |                            | $          | 36                              |       |   |   | $ | (10 | ) |   |   | $ | 36 |   |   |   | $ | (8 | ) |   |

 

***Debtor-in-PossessionFinancing***

In 2005, the Company and its subsidiaries participatedin an intercompany cash management program for the Mirant Debtors approved bythe Bankruptcy Court and were parties to the debtor-in-possession creditfacility dated November 5, 2003 (the “DIP Facility”). The parties to theDIP Facility, including the Company, were in compliance with the DIP Facilitycovenants, or had received affirmative waivers of compliance where compliancewas not attained, as of December 31, 2005. In October 2005, theBankruptcy Court approved an extension of the DIP Facility through January 31,2006. The DIP Facility was terminated on the emergence of the Mirant Debtors onJanuary 3, 2006.

***Sourcesof Funds and Capital Structure***

Theprincipal sources of liquidity for the Company’s future operations and capitalexpenditures are expected to be: (i) existing cash on hand and cash flowsfrom the operations of the Company’s subsidiaries; (ii) borrowings underMirant North America’s $800 million six year senior secured revolvingcredit facility; and (iii) $200 million of letters of credit capacityunder Mirant North America’s $700 million term loan and (iv) proceedsfrom the preferred shares issued by Mirant Americas to Mirant Mid-Atlantic andthe Company to fund capital expenditures and support the refinancing of the Company’ssenior notes due in 2011.

TheCompany and certain of its subsidiaries, including Mirant North America, areholding companies and as a result, such subsidiaries are dependent upondividends, distributions and other payments from their respective subsidiariesto generate the funds necessary to meet their obligations. The ability ofcertain of the Company’s subsidiaries to pay dividends and distributions isrestricted under the terms of their debt or other agreements. The Company hasno operations and no subsidiaries with operations other than Mirant NorthAmerica and its subsidiaries, including Mirant Mid-Atlantic. Under itsleveraged leases, Mirant Mid-Atlantic is not permitted to make any dividends,distributions and other restricted payments unless (1) it satisfies thefixed charge coverage ratio on a historical basis for the last period of fourfiscal quarters, (2) it is projected to satisfy the fixed charge coverageratio for the next two periods of four fiscal quarters, and (3) nosignificant lease default or event of default has occurred and is continuing.In the event of a default under the leveraged leases or if the restrictedpayments test is not satisfied, the cash of Mirant Mid-Atlantic would not beable to be distributed. Based on the Company’s calculation of the fixed chargecoverage ratios under the leveraged leases as of December 31, 2005, MirantMid-Atlantic meets the required 1.7 to 1.0 ratio for restricted payments, bothon a historical and projected basis. During bankruptcy, cash movements amongthe Mirant Debtors were made pursuant to intercompany loans. During bankruptcy,the Mirant Debtors did not make dividends, distributions or capitalcontributions.

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The Mirant North America senior secured creditfacilities and notes include certain covenants typical in such creditfacilities and notes, including restrictions on dividends, distributions andother restricted payments. Further, the Mirant North America senior securedcredit facilities include financial covenants that will exclude from thecalculation of compliance with such covenants the financial results of anysubsidiary that is unable to make distributions or dividends at the time ofsuch calculation. Thus, the ability of Mirant Mid-Atlantic to makedistributions to Mirant North America under the leveraged lease transaction isexpected to have a material impact on the calculation of the financialcovenants under the Mirant North America senior secured credit facilities andother debt of Mirant North America and on its ability to make distributions tothe Company.

***Debtor-in-PossessionFinancing for New York Subsidiaries***

The Company, together with Mirant Americas EnergyMarketing, entered into an agreement (the ‘‘New York DIP Agreement’’) to makesecured debtor-in-possession financing in an amount of (i) $20 million,plus (ii) an amount equal to the amount of credit support provided onbehalf of (w) Mirant New York, Inc. (“Mirant New York”), (x) MirantBowline, (y) Mirant Lovett, and (z) Hudson Valley Gas Corporation(collectively, the “New York DIP Borrowers”), to the extent such amounts arecollateralized with cash or cash equivalents by the New York DIP Borrowers. Thefacility is available on a joint and several basis to the New York DIPBorrowers. On January 31, 2006, all the assets of Mirant Americas EnergyMarketing were transferred to Mirant Energy Trading, and Mirant Energy Tradingsucceeded to all rights and assumes all obligations of Mirant Americas EnergyMarketing under the New York DIP Agreement. The financing under the New YorkDIP 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 DIPBorrowers or in support of commercial transactions entered into by MirantEnergy Trading for the benefit of the New York DIP Borrowers, the posting ofcash in respect of obligations incurred for the benefit of any of the New YorkDIP Borrowers, including the making of prepayments for fuel and othercommodities for the benefit of any of the New York DIP Borrowers. Under the NewYork DIP Agreement, the amount which represents the excess on the effective dateof the Plan of (x) credit support posted for the benefit of the New YorkDIP Borrowers by the lenders in respect of transactions entered into on theirbehalf over (y) the amount of cash collateral posted by the New York DIPBorrowers to the lenders is deemed to be a loan made to the New York DIPBorrowers on such date. The New York DIP Borrowers have posted $16.1 millioncash collateral with Mirant Energy Trading in accordance with the February 28,2006, collateral allocation performed in good faith by Mirant Energy Trading.To the extent that the required level of credit support provided to the NewYork DIP Borrowers is reduced, the amount of such reduction is required to bereturned to the New York DIP Borrowers. The financing under the New York DIP Agreementhas a stated maturity of 180 days, subject to renewal or extension, and isavailable until the earlier of (x) the expiration of such period or (y) withrespect to each of the New York DIP Borrowers, the effective date of aconfirmed plan of reorganization for such New York DIP Borrower in its Chapter 11case. Subject to the authorization of the Bankruptcy Court, the obligations ofthe New York DIP Borrowers under the New York DIP Agreement, pursuant to Section 364(c) ofthe Chapter 11 of Title 11 of the United States Bankruptcy Code (“BankruptcyCode”), (i) constitute a claim having priority over any or alladministrative expenses of the kind specified in sections 503(b) or 507(b) ofthe Bankruptcy Code, (ii) are secured by a lien on property of the estatesof the New York DIP Borrowers that is not otherwise subject to a lien and (iii) aresecured by a junior lien on property of the estates of the New York DIPBorrowers that is subject to a lien. The financing is expected to bear interestat a rate to be determined and to be subject to Bankruptcy Court approval. TheNew York DIP Agreement contains certain events of default, and the ability ofthe New York DIP Borrowers to borrow thereunder is subject to certainconditions precedent. In addition, the New York DIP Agreement containscovenants that, among other things, restrict the ability of the New York DIPBorrowers to engage in mergers, acquisitions and asset sales, to makeinvestments and to incur indebtedness.

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**12.**          OtherComprehensive (Loss) Income

Other comprehensive (loss)income includes unrealized gains and losses on certain derivatives thatqualified as cash flow hedges and unrealized gains on available-for-salesecurities. Changes in accumulated other comprehensive (loss) income, net oftax are as follows (in millions):

| Balance,  December 31, 2002                        |   | $      | (55    | )      |
|---------------------------------------------------------|--------|--------|--------|--------|
| Other comprehensive income for the period:              |   |   |   |
| Reclassification to  earnings, net of tax effect of $29 |   | 55     |   |
| Balance,  December 31, 2003                        |   | — |   |
| Balance,  December 31, 2004                        |   | — |   |
| Other comprehensive income for the period:              |   |   |   |
| Unrealized gain on  available-for-sale securities       |   | 27     |   |
| Balance, December 31, 2005                         |   | $      | 27     |   |

 

The$55 million in accumulated other comprehensive loss at December 31, 2002,is primarily associated with deferred interest rate swap hedging lossesaccounted for as qualifying hedges under SFAS No. 133 that had beenpreviously settled.

Pursuantto the bankruptcy proceedings, interest payments were suspended on the debtassociated with the Company’s interest rate swaps. Therefore, the deferredinterest rate swap hedging losses were reclassified from other comprehensiveloss to earnings in 2003, effective with the Chapter 11 filing.

The $27 million in accumulated othercomprehensive income at December 31, 2005 is associated with unrealizedgains on available for sale securities. The unrealized gains will bereclassified to earnings when the securities are sold.

**13.**          IncomeTaxes

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

| ** **                           | ** ** | **For the Years Ended December 31,** | ** ** |
|--------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                           | ** ** | **2005**                                                      | ** ** | **2004** | ** ** | **2003** | ** ** |
| Current:                             |       |                                                          |       |   |   |   |   |
| Federal                              |       | $                                                             | 7          |   | $ | (10 | ) | $ | 77 |   |
| State                                |       | 9                                                             |       | (6 | ) | 1 |   |
| Deferred:                            |       |                                                          |       |   |   |   |   |
| Federal                              |       | (12                                                           | )          | 2 |   | 6 |   |
| State                                |       | 1                                                             |       | (1 | ) | 27 |   |
| Provision (benefit) for income taxes |       | $                                                             | 5          |   | $ | (15 | ) | $ | 111 |   |

 

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

| ** **                                                 | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| U.S. federal  statutory income tax (benefit) provision     |       | $        | (265       | )        | $          | 32       |       | $ | (1,073 | ) |
| State and local  income taxes, net of federal income taxes |       | 1        |       | (1       | )          | (72      | )          |
| LLC income not  subject to federal taxation                |       | 315      |       | (44      | )          | 110      |       |
| Change in  deferred tax asset valuation allowance          |       | (534     | )          | (4       | )          | 658      |       |
| Impact of  non-deductible goodwill impairment              |       | —   |       | —   |       | 465      |       |
| Impact of the  Plan                                        |       | 466      |       | —   |       | —   |       |
| Other, net                                                 |       | 22       |       | 2        |       | 23       |       |
| Tax (benefit)  provision                                   |       | $        | 5          |     | $          | (15      | )          | $ | 111 |   |

 

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Thetax effects of temporary differences that give rise to significant portions of deferredtax assets and liabilities are as follows at December 31, 2005 and 2004(in millions):

| ** **                        | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------------|------------|----------|------------|----------|------------|
| Deferred tax assets:              |       |     |       |     |       |
| Revenue subject to refund         |       | $        | —     |     | $          | 154 |   |
| Property and intangible assets    |       | 99       |       | 435      |       |
| Net operating loss carryforwards  |       | 79       |       | 165      |       |
| Other, net                        |       | 45       |       | 28       |       |
| Deferred tax assets               |       | 223      |       | 782      |       |
| Valuation allowance               |       | (223     | )          | (757     | )          |
| Net deferred tax assets           |       | —   |       | 25       |       |
| Deferred tax  liabilities:        |       |     |       |     |       |
| Price risk management liabilities |       | —   |       | (10      | )          |
| Other, net                        |       | —   |       | (25      | )          |
| Total                             |       | —   |       | (35      | )          |
| Net deferred tax  liabilities     |       | $        | —     |     | $          | (10 | ) |

 

Several changes to the Company’s tax posture occurredas a result of the Plan. Implementation of the Plan included the conversion ofcertain of the Company’s regarded corporate entities to limited liability companiescoupled with the liquidation and/or merger of certain regarded corporateentities into other disregarded corporate entities for income tax purposes. Asa result, certain subsidiaries previously treated as regarded corporateentities for income tax purposes have either been liquidated or converted intodisregarded entities for income tax purposes pursuant to the Plan.Additionally, certain partnerships owned by regarded corporate entities werealso liquidated, and now form part of disregarded entities for income taxpurposes. The result of the above Plan effects was to eliminate the Company’srecording of tax expense and benefit prospectively with respect to theliquidated regarded corporate entities. Furthermore, with respect to thoseliquidated regarded corporate entities, all previously existing deferred taxassets and liabilities were eliminated as of December 31, 2005. Certain ofthe Company’s other subsidiaries continue to exist as regarded corporateentities for income tax purposes, including Mirant New York, Inc., HudsonValley Gas Corporation, Mirant Kendall, LLC and Mirant Special Procurement, Inc.

SFAS No. 109, requires that a valuation allowancebe established when it is more likely than not that all or a portion of adeferred tax asset will not be realized. The ultimate realization of deferredtax assets is dependent upon the generation of future taxable income during theperiods in which those temporary differences are deductible. In making thisdetermination, management considers all available positive and negativeevidence affecting specific deferred tax assets, including the Company’s pastand anticipated future performance, the reversal of deferred tax liabilities,and the implementation of tax planning strategies.

Objective positive evidence is necessary to support aconclusion that a valuation allowance is not needed for all or a portion ofdeferred tax assets when significant negative evidence exists. Cumulative prioryear losses are the most compelling form of negative evidence considered bymanagement in this determination. Additionally, management considered the factthat Mirant had not reimbursed the Company for current period net operatinglosses since the Petition Date. In 2005, 2004 and 2003, the Company hadrecognized changes in its valuation allowance of $(534) million, $(4) millionand $658 million, respectively, related to its net deferred tax assets.

At December 31, 2005, the Company had $182 millionof NOL carryforwards for federal income tax purposes expiring from 2022 to 2025and $322 million of NOL carryforwards for state income tax purposesexpiring on various dates. These NOL carryforwards are available to offsetfuture federal and state income taxes.

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

The Company has contingentliabilities related to tax uncertainties arising in the ordinary course ofbusiness in other jurisdictions. The Company periodically assesses itscontingent liabilities in connection with these uncertainties based upon thelatest information available. For those uncertainties where it is probable thata loss has been incurred and the loss or range of loss can be reasonablyestimated, a liability is recorded on the combined and consolidated financialstatements. As additional information becomes available, the assessment andestimates of such liabilities are adjusted accordingly.

***Pro Forma Income Tax Disclosures***

The Company is not subject to income taxes except forthose subsidiaries of the Company that are separate taxpayers. Mirant Americasand Mirant are otherwise directly responsible for income taxes related to theCompany’s operations. The following reflects a pro forma disclosure of theincome tax provision (benefit) that would be reported if the Company were to beallocated income taxes related to its operations.

Proforma income tax provision (benefit) attributable to income before tax wouldconsist of the following (in millions):

| ** **                            | ** ** | **For the Years Ended December 31,** | ** ** |
|---------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                            | ** ** | **2005**                                                      | ** ** | **2004** | ** ** | **2003** | ** ** |
| Current provision  (benefit):         |       |                                                          |       |   |   |   |   |   |   |   |   |
| Federal                               |       |                                                          | $          | — |   |   |   | $ | — |   |   | $ | (6 | ) |
| State                                 |       |                                                          | 9          |   |   |   | (8 | ) |   | — |   |
| Deferred benefit:                     |       |                                                          |       |   |   |   |   |   |   |   |   |
| Federal                               |       |                                                          | —     |   |   |   | — |   |   | (15 | ) |
| State                                 |       |                                                          | —     |   |   |   | — |   |   | (3 | ) |
| Total income tax  provision (benefit) |       |                                                          | $          | 9 |   |   |   | $ | (8 | ) |   | $ | (24 | ) |

 

Thefollowing table presents the pro forma reconciliation of the Company’s federalstatutory income tax (benefit) provision for continuing operations adjusted forreorganization items to the pro forma effective tax provision (benefit) (inmillions):

| ** **                                                 | ** ** | **For the Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2005**                                                      | ** ** | **2004** | ** ** | **2003** | ** ** |
| U.S. federal statutory  income tax (benefit) provision     |       | $                                                             | (265       | ) | $ | 32 |   | $ | (1,073 | ) |
| State and local  income taxes, net of federal income taxes |       | —                                                        |       | (1 | ) | — |   |
| Impact of  non-deductible goodwill impairment              |       | —                                                        |       | — |   | 465 |   |
| Change in  deferred tax asset valuation allowance          |       | (10)                                                          |       | (54 | ) | 590 |   |
| Impact of the  Plan                                        |       | 223                                                           |       | — |   | — |   |
| Other, net                                                 |       | 61                                                            |       | 15 |   | (6 | ) |
| Tax provision  (benefit)                                   |       | $                                                             | 9          |   | $ | (8 | ) | $ | (24 | ) |

 

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Thetax effects of temporary differences that give rise to significant portions ofthe pro forma deferred tax assets and liabilities would be as follows at December 31,2005 and 2004 (in millions):

| ** **                                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred tax assets:                                        |       |     |       |     |       |
| Obligations under energy delivery and purchase  commitments |       | $        | —     |     | $          | 240 |   |
| Revenue subject to refund                                   |       | 182      |       | 199      |       |
| Net operating loss carryforwards                            |       | 809      |       | 539      |       |
| Property and intangible assets                              |       | 189      |       | 328      |       |
| Price risk management liabilities—affiliate            |       | 89       |       | —   |       |
| Other, net                                                  |       | 108      |       | 127      |       |
| Deferred tax assets                                         |       | 1,377    |       | 1,433    |       |
| Valuation allowance                                         |       | (1,350   | )          | (1,360   | )          |
| Net deferred tax assets                                     |       | 27       |       | 73       |       |
| Deferred tax  liabilities:                                  |       |     |       |     |       |
| Price risk management liabilities—affiliate            |       | (10      | )          | (32      | )          |
| Other, net                                                  |       | (17      | )          | (41      | )          |
| Total                                                       |       | (27      | )          | (73      | )          |
| Net deferred tax  assets                                    |       | $        | —     |     | $          | — |   |

 

The ultimate utilization of the Company’s remainingNOLs will depend on several factors, including its future financial performanceand certain tax elections. Specifically, the Company’s utilization of NOLs willbe impacted by whether Mirant elects NOL treatment under Internal Revenue Code Section (“§”) 382(l) (5) or§ 382(l) (6). Under § 382(l)(5), Mirant would have unlimited use of its NOLsas long as there is not a change of ownership (broadly defined as 50 percentchange of five percent shareholders) within two years of emergence. On a proforma basis, the § 382(l)(5) election would require the Company to reduceits federal NOLs to approximately $1,834 million from $2,009 million due tointerest accrued on debt settled with stock for the three years prior toemergence. Under § 382(l) (6), Mirant would be subject to an overallannual limitation on use of NOLs. Mirant will make the § 382(l) (5) or§ 382(l) (6) election in its 2006 annual tax return filed in 2007.

The Company has notprovided a pro forma deferred tax liability with respect to the Company’sinvestment in the Mirant Americas Preferred Stock discussed in Note 6, sincethe underlying transaction is disregarded for income tax purposes.

**14.**          Litigationand Other Contingencies

The Company is involved ina number of significant legal proceedings. In certain cases plaintiffs seek torecover large and sometimes unspecified damages, and some matters may beunresolved for several years. The Company cannot currently determine theoutcome of the proceedings described below or the ultimate amount of potentiallosses and therefore has not made any provision for such matters unlessspecifically noted below. Pursuant to SFAS No. 5, “*Accountingfor Contingencies*,” management provides for estimated losses to theextent information becomes available indicating that losses are probable andthat the amounts are reasonably estimable. Additional losses could have amaterial adverse effect on the Company’s combined and consolidated financialposition, results of operations or cash flows.

***Chapter 11 Proceedings***

On the Petition Date, and various dates thereafter,the Mirant Debtors filed voluntary petitions for relief under Chapter 11of the Bankruptcy Code. On August 21, 2003, and September 8, 2003,the Bankruptcy Court entered orders establishing a December 16, 2003, bardate (the “Bar Date”) for filing proofs of claim against the Mirant Debtors’estates.

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Most of the material claims filed against the MirantDebtors’ estates were disallowed or were resolved and became “allowed” claimsbefore confirmation of the Plan. For example, the claims filed by theCalifornia Attorney General, Pacific Gas & Electric (“PG&E”),various other California parties, plaintiffs in certain rate payer class actionlawsuits, the plaintiffs in certain bondholder litigation, and Utility Choice,L.P., which are described in the Company’s 2004 Form 10-K, are amongthe claims that were resolved prior to confirmation of the Plan. A number ofclaims, however, remain unresolved.

Except for claims and other obligations not subject todischarge under the Plan and unless otherwise provided below, all claimsagainst the Mirant Debtors’ estates representing obligations that arose priorto July 14, 2003, are subject to compromise under the Plan. This meansthat the claimant will receive a distribution of Mirant common stock, cash, orboth Mirant common stock and cash in accordance with the terms of the Plan insatisfaction of the claim. As a result, the exact amount of the claim may stillbe litigated, but the Company will not be required to make any payment inrespect of such litigation until a resolution is obtained, through settlement,judgment or otherwise.

As of December 31, 2005, approximately 23.5million of the shares of Mirant common stock to be distributed under the Planhave been reserved for distribution with respect to claims that are disputed bythe Mirant Debtors and have not been resolved. Under the terms of the Plan, tothe extent such claims are resolved now that the Company has emerged frombankruptcy, the claimants will be paid from the reserve of 23.5 million shareson the same basis as if they had been paid out when the Plan became effective.That means that their allowed claims will receive the same pro ratadistributions of Mirant common stock, cash, or both common stock and cash aspreviously allowed claims in accordance with the terms of the Plan. The Companymaintains that it has funded the disputed claims reserve at a sufficient levelto settle the remaining unresolved proofs of claim it received during thebankruptcy proceedings and any claims resulting from the rejection of certaincontracts with PEPCO, as described below in *PEPCO Litigation*.However, to the extent the aggregate amount of the payouts determined to be duewith respect to such disputed claims ultimately exceeds the amount of thefunded claim reserve, Mirant would have to issue additional shares of commonstock to address the shortfall, which would dilute existing Mirantshareholders, and the Company would have to pay additional cash amounts asnecessary under the terms of the Plan to satisfy such pre-petition claims. TheCompany will continue to monitor its obligations as the disputed claims areresolved.

The Company’s Lovett andBowline generation facilities in New York are subject to disputes with localtax authorities regarding property tax assessments and with the New York StateDepartment of Environmental Conservation, (“NYSDEC”) regarding environmentalcontrols. Mirant Lovett is also in discussions with the Independent SystemOperator of New York (“NYISO”) and utilities regarding an agreement that wouldcompensate Mirant Lovett for the contribution of the Lovett facility to thereliability of the New York electric power system. The facilities areforecasted to have negative operating cash flows at their current taxvaluations. Until a settlement is reached on property taxes, environmentalcontrols and reliability that would permit economically feasible operation, theCompany’s subsidiaries that own the facilities, Mirant Lovett and MirantBowline, will remain in Chapter 11. Mirant Lovett and Mirant Bowline arecurrently in settlement discussions on all of these issues. Althoughnegotiations are continuing, settlements may not be reached in the near future,or at all. Until such settlements are reached and the companies emerge frombankruptcy, we will not have access to the cash from operations generated fromthese subsidiaries. Mirant NY-Gen, which owns hydroelectric facilities atSwinging Bridge, Rio and Mongaup, and small combustion turbine facilities atHillburn and Shoemaker, is insolvent. Its expenses are being funded under adebtor-in-possession facility made by Mirant Americas with the approval of, andunder the supervision of, the Bankruptcy Court. Mirant NY-Gen is currentlydiscussing with the Federal Energy Regulatory Commission (“FERC”) appropriateremediation for a sinkhole discovered in May 2005 in the dam at theSwinging Bridge facility. Mirant NY-Gen conducted a flood study to determinedownstream consequences if the maximum capacities of the reservoirs wereexceeded at its New York Swinging Bridge, Rio and Mongaup generationfacilities, and Mirant NY-Gen could be requested by the 

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FERC toremediate those dams as well. Mirant NY-Gen has initiated discussions with theFERC for surrendering its permits to operate all the hydroelectric facilitiesat Swinging Bridge, Rio and Mongaup, and expects to begin that formal processsoon. It is not possible at this point to determine the cost of remediating thedam at Swinging Bridge and surrendering the permits, but such costs may besubstantial.

***PEPCO Litigation***

In 2000, Mirant purchased power generating facilitiesand other assets from PEPCO, including certain PPAs between PEPCO and thirdparties. Under the terms of the Asset Purchase and Sale Agreement (“APSA”), Mirant and PEPCO entered into the Back-to-BackAgreement with respect to certain PPAs, including PEPCO’s long-term PPAs withOhio Edison Company (“Ohio Edison”) and Panda-Brandywine L.P. (“Panda”),under which (1) PEPCO agreed to resell to Mirant all capacity, energy,ancillary services and other benefits to which it is entitled under thoseagreements; and (2) Mirant agreed to pay PEPCO each month all amounts duefrom PEPCO to the sellers under those agreements for the immediately precedingmonth associated with such capacity, energy, ancillary services and otherbenefits. The Ohio Edison PPA terminated in December 2005 and thePanda PPA runs until 2021. Under the Back-to-Back Agreement, Mirant isobligated to purchase power from PEPCO at prices that are typically higher thanthe market prices for power.

Mirant assigned its rightsand obligations under the Back-to-Back Agreement to Mirant Americas EnergyMarketing. In the Chapter 11 cases of the Mirant Debtors, PEPCO asserted thatan Assignment and Assumption Agreement dated December 19, 2000, thatincludes as parties PEPCO and various subsidiaries of ours causes oursubsidiaries that are parties to the agreement to be jointly and severallyliable to PEPCO for various obligations, including the obligations under theBack-to-Back Agreement. The Mirant Debtors have sought to reject the APSA, theBack-to-Back Agreement, and the Assignment and Assumption Agreement, and therejection motions have not been resolved. Under the Plan, the obligations ofthe Mirant Debtors under the APSA (including any other agreements executedpursuant to the terms of the APSA and found by a final court order to be partof the APSA), the Back-to-Back Agreement, and the Assignment and AssumptionAgreement are to be performed by Mirant Power Purchase, LLC (“Mirant PowerPurchase”), whose performance is guaranteed by Mirant. If any of the agreementsis successfully rejected, the obligations of Mirant Power Purchase, and Mirant’sguarantee obligations terminate with respect to that agreement, and PEPCO wouldbe 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 theBankruptcy Court were to conclude that the Assignment and Assumption Agreementimposed liability upon the Company’s subsidiaries for the obligations under theBack-to-Back Agreement and the Back-to-Back Agreement were to be rejected, theresulting rejection damages claim could result in a claim in the Chapter 11proceedings against the Company’s subsidiaries but any such claim would bereduced by the amount recovered by PEPCO on its comparable claim againstMirant.

***California and Western Power Markets***

*CaliforniaRate Payer Litigation.**  *Certainof our subsidiaries are subject to litigation related to their activities inCalifornia and the western power markets and the high prices for wholesaleelectricity experienced in the western markets during 2000 and 2001. Variouslawsuits were filed in 2000 through 2003 that asserted claims under Californialaw based on allegations that certain owners of electricity generationfacilities in California and energy marketers, including the Company, MirantAmericas Energy Marketing and our subsidiaries owning generating facilities inCalifornia, engaged in various unlawful and anti-competitive acts that servedto manipulate wholesale power markets and inflate wholesale electricity pricesin California. All of these suits have been dismissed by final orders exceptfor six such suits that were filed between November 27, 2000, and May 2,2001, in various California Superior Courts and consolidated before theSuperior Court for the County of San Diego for pretrial purposes. Although theplaintiffs dismissed Mirant from those suits, they have not filed to dismisscertain of our subsidiaries that are also 

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defendants. On October 3,2005, the California state court dismissed those six consolidated suits on thegrounds that the plaintiffs’ claims were barred by federal preemption as aresult of the Federal Power Act. On December 5, 2005, the plaintiffs filedan appeal of the dismissal. The plaintiffs in the six consolidated suits didnot file claims in the Chapter 11 proceedings, and it is the Company’s viewthat their claims are barred by the Plan now that it has become effective.

*FERCRefund Proceedings.*   On July 25, 2001, theFERC issued an order requiring proceedings (the “FERC Refund Proceedings”) todetermine the amount of any refunds and amounts owed for sales made by marketparticipants, including Mirant Americas Energy Marketing, to the California IndependentSystem Operator (“CAISO”) or the California Power Exchange (“Cal PX”) from October 2,2000, through June 20, 2001 (the “Refund Period”). Various parties haveappealed these FERC orders to the United States Court of Appeals for the NinthCircuit (the “Ninth Circuit”) seeking review of a number of issues, includingchanging the Refund Period to include periods prior to October 2, 2000,and expanding the sales of electricity subject to potential refund to includebilateral sales made to the California Department of Water Resources (the “DWR”)and other parties. Any such expansion of the Refund Period or the types ofsales of electricity potentially subject to refund could significantly increasethe refund exposure of Mirant Americas Energy Marketing in this proceeding.Although Mirant Americas Energy Marketing is the Mirant entity that engaged intransactions with the CAISO and the Cal PX, the orders issued by the FERC inthe refund proceedings, and the filings made by other parties in those proceedings,generally refer to the Mirant entity involved as Mirant without being morespecific. It is the Company’s view that the Mirant entity that would actuallybe liable to third parties for any refunds determined by the FERC to be owed,or that would be due any receivables found to be owed to Mirant, is MirantAmericas Energy Marketing.

In the July 25, 2001, order, the FERC alsoordered that a preliminary evidentiary proceeding be held to develop a factualrecord on whether there had been unjust and unreasonable charges for spotmarket bilateral sales in the Pacific Northwest from December 25, 2000,through June 20, 2001. In that proceeding, the California AttorneyGeneral, the California Public Utility Commission (the “CPUC”) and theCalifornia Electricity Oversight Board (the “EOB”) filed to recover certainrefunds from parties, including Mirant Americas Energy Marketing, for bilateralsales of electricity to the DWR at the California/Oregon border, claiming thatsuch 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 byvarious parties. Various parties have appealed the FERC’s decision to the NinthCircuit.

On September 9, 2004, the Ninth Circuit reversedthe FERC’s dismissal of a complaint filed in 2002 by the California AttorneyGeneral that sought refunds for transactions conducted in markets administeredby the CAISO and the Cal PX outside the Refund Period set by the FERC and fortransactions between the DWR and various owners of generation and powermarketers, including Mirant Americas Energy Marketing and subsidiaries of theCompany. The Ninth Circuit remanded the proceeding to the FERC for it todetermine what remedies, including potential refunds, are appropriate whereentities, including Mirant Americas Energy Marketing, purportedly did notcomply with certain filing requirements for transactions conducted undermarket-based rate tariffs. Mirant Americas Energy Marketing and other partieshave filed a petition for rehearing with the Ninth Circuit that remainspending.

On January 14, 2005,**Mirantand certain of its subsidiaries, including the Company, entered into aSettlement and Release of Claims Agreement (the “California Settlement”) withPG&E, Southern California Edison Company (“SCE”), San Diego Gas andElectric Company, the CPUC, the DWR, the EOB and the Attorney General of theState of California (collectively, the “California Parties”) and with theOffice of Market Oversight and Investigations of the FERC. The CaliforniaSettlement settled a number of disputed lawsuits and regulatory proceedingsthat were pursued originally in state and federal 

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courts and before theFERC. 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, (asthe successor to Mirant California Investments, Inc.). The CaliforniaSettlement was approved by the FERC on April 13, 2005, and becameeffective April 15, 2005, upon its approval by the Bankruptcy Court. TheCalifornia Settlement resulted in the release of most of Mirant Americas EnergyMarketing’s potential liability (1) in the FERC Refund Proceedings forsales made in the CAISO or the Cal PX markets, (2) in the proceeding alsoinitiated by the FERC in July 2001 to determine whether there had beenunjust and unreasonable charges for spot market bilateral sales in the PacificNorthwest from December 25, 2000, through June 20, 2001, and (3) inany proceedings at the FERC resulting from the Ninth Circuit’s reversal of theFERC’s dismissal of the complaint filed in 2002 by the California AttorneyGeneral. Under the California Settlement, the California Parties and thoseother market participants who have opted into the settlement have released theMirant Settling Parties from any liability for refunds related to sales ofelectricity and natural gas in the western markets from January 1, 1998,through July 14, 2003. Also, the California Parties have assumed theobligation of Mirant Americas Energy Marketing to pay any refunds determined bythe FERC to be owed by Mirant Americas Energy Marketing to other parties thatdo not opt into the settlement for transactions in the CAISO and Cal PX marketsduring the Refund Period, with the liability of the California Parties for suchrefund obligation limited to the amount of certain receivables assigned byMirant Americas Energy Marketing to the California Parties under the CaliforniaSettlement. Subject to applicable bankruptcy law, however, Mirant AmericasEnergy Marketing will continue to be liable for any refunds that the FERCdetermines it to owe (1) to participants in the Cal PX and CAISO marketsthat are not California Parties (or that did not elect to opt into thesettlement) for periods outside of the Refund Period and (2) toparticipants in bilateral transactions with Mirant Americas Energy Marketingthat are not California Parties (or that did not elect to opt into thesettlement).

It is the Company’s view that the bulk of anyobligations of Mirant Americas Energy Marketing to make refunds as a result ofsales completed prior to July 14, 2003, in the CAISO or Cal PX markets orin bilateral transactions either have been addressed by the CaliforniaSettlement or have been resolved as part of Mirant Americas Energy Marketing’sbankruptcy proceedings. To the extent that Mirant Americas Energy Marketing’spotential refund liability arises from contracts that were transferred toMirant Energy Trading as part of the transfer of the trading and marketingbusiness under the Plan, Mirant Energy Trading may have exposure to any refundliability related to transactions under those contracts.

*FERCShow Cause Proceeding Relating to Trading Practices.**  *On June 25, 2003, the FERC issued a show causeorder (the “Trading Practices Order”) to more than 50 parties, including MirantAmericas Energy Marketing and subsidiaries of Mirant Americas Generation, thata FERC staff report issued on March 26, 2003, identified as havingpotentially engaged in one or more trading strategies of the type employed byEnron Corporation and its affiliates (“Enron”), as described in Enron memosreleased by the FERC in May 2002. The Trading Practices Order identifiedcertain specific trading practices that the FERC indicated could constitutegaming or anomalous market behavior in violation of the CAISO and Cal PXtariffs. The Trading Practices Order requires the CAISO to identifytransactions between January 1, 2000, and June 20, 2001, that mayinvolve the identified trading strategies, and then requires the applicablesellers involved in those transactions to demonstrate why such transactionswere not violations of the CAISO and Cal PX tariffs. On September 30,2003, the Mirant entities filed with the FERC for approval of a settlementagreement (the “Trading Settlement Agreement”) entered into between certainMirant entities and the FERC Trial Staff, under which Mirant Americas EnergyMarketing would pay $332,411 to settle the show cause proceeding, except for anissue 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 allegationsof improper trading conduct with respect to the selling of ancillary servicesduring 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 tothe Trading Settlement Agreement reached with the FERC Trial Staff 

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with respect to the saleof ancillary services. Under that amendment, the FERC would have an allowedunsecured claim in Mirant Americas Energy Marketing’s bankruptcy proceeding for$3.67 million in settlement of the allegations with respect to the sale ofancillary services. The FERC approved the Trading Settlement Agreement, asamended, on June 27, 2005, and the Bankruptcy Court approved it on August 24,2005. Certain parties have filed motions for rehearing with the FERC, whichmotions remain pending.

*MirantAmericas Energy Marketing Contract Dispute With Nevada Power.**  *On December 5, 2001, Nevada Power Co. filed acomplaint at the FERC seeking reformation of the purchase price of energy undera contract it had entered with Mirant Americas Energy Marketing, claiming thatthe prices under that contract were unjust and unreasonable because, when itentered into the contract, Western power markets were dysfunctional andnon-competitive markets. On June 25, 2003, the FERC dismissed thiscomplaint. Nevada Power has appealed that dismissal to the United States Courtof Appeals for the Ninth Circuit. The sales made under the contract with NevadaPower have been completed, and we expect that any refund claim related to thatcontract, if not now barred, will be addressed in the Chapter 11 proceedings.

*Mirant Americas EnergyMarketing Contract Dispute With Southern California Water.**  *On December 21, 2001, Southern California WaterCo. filed a complaint at the FERC seeking reformation of the purchase price ofenergy under a long-term contract it had entered with Mirant Americas EnergyMarketing, claiming that the prices under that contract were unjust andunreasonable because, when it entered the contract, Western power markets weredysfunctional and non-competitive markets. On June 25, 2003, the FERCdismissed this proceeding. Southern California Water has appealed thatdismissal to the United States Court of Appeals for the Ninth Circuit. Thecontract with Southern California Water Company continues through 2006. Uponthe transfer of the assets of the trading and marketing business to MirantEnergy Trading under the Plan, Mirant Energy Trading assumed Mirant AmericasEnergy Marketing’s contract obligations to Southern California Water Co.,including any potential refund obligations.

***Bondholder Litigation***

*Mirant Americas GenerationBondholder Suit.**  *On June 10,2003, certain holders of senior notes of Mirant Americas Generation maturingafter 2006 filed a complaint in the Court of Chancery of the State of Delaware*, California Public Employees’ Retirement System, et al. v. MirantCorporation, et al.,* that named as defendants Mirant, MirantAmericas, Mirant Americas Generation, certain past and present Mirantdirectors, and certain past and present Mirant Americas Generation managers.Among other claims, the plaintiffs assert that a restructuring plan pursued bythe Company prior to its filing a petition for reorganization under Chapter 11of the Bankruptcy Code was in breach of fiduciary duties allegedly owed to themby Mirant, Mirant Americas and Mirant Americas Generation’s managers. Inaddition, the plaintiffs challenge certain dividends and distributions made byMirant Americas Generation prior to the Petition Date. The plaintiffs seekdamages in excess of $1 billion. Mirant has removed this suit to the UnitedStates District Court for the District of Delaware. This action was stayed withrespect to the Mirant entities that are defendants by the filing of the Chapter11 proceedings of these entities. The order entered by the Bankruptcy Courtconfirming the Plan enjoins the prosecution of this action and requires that itbe dismissed. On March 8, 2006, the Bankruptcy Court entered an ordercompelling the plaintiffs in this action to dismiss their complaint inaccordance with the terms of the Plan. On March 17, 2006, the partiesfiled a stipulation of dismissal dismissing the suit.

***U.S. Government Inquiries***

*Department of JusticeInquiries.*   InNovember 2002, Mirant received a subpoena from the Department of Justice (“DOJ”),acting through the United States Attorney’s office for the Northern 

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District ofCalifornia, requesting information about its activities and those of itssubsidiaries for the period since January 1, 1998. The subpoena requestedinformation related to the California energy markets and other topics,including the reporting of inaccurate information to the trade press thatpublish natural gas or electricity spot price data. The subpoena was issued aspart of a grand jury investigation. The DOJ’s investigation of the reporting ofinaccurate natural gas price information is continuing, and Mirant has heldpreliminary discussions with DOJ regarding the disposition of this matter. TheDOJ’s investigation is based upon the same circumstances that were the subjectof an investigation by the Commodity Futures Trading Commission (“CFTC”) thatwas settled in December 2004. As described in Mirant’s Annual Report on Form 10-Kfor the year ended December 31, 2004, in *LegalProceedings—Other Governmental Proceedings—CFTC Inquiry*, Mirant andMirant Americas Energy Marketing pursuant to the settlement consented to theentry of an order by the CFTC in which it made findings, which are neitheradmitted nor denied by Mirant and Mirant Americas Energy Marketing, that (1) fromJanuary 2000 through December 2001, certain Mirant Americas EnergyMarketing natural gas traders (a) knowingly reported inaccurate price,volume, and/or counterparty information regarding natural gas cash transactionsto publishers of natural gas indices and (b) inaccurately reported toindex publishers transactions observed in the market as Mirant Americas EnergyMarketing transactions and (2) from January to October 2000,certain Mirant Americas Energy Marketing west region traders knowinglydelivered the false reports in an attempt to manipulate the price of naturalgas. Under the settlement, the CFTC received a subordinated allowed, unsecuredclaim against Mirant Americas Energy Marketing of $12.5 million in the Chapter11 proceedings. The DOJ could decide that further action against Mirant andMirant Americas Energy Marketing is not appropriate or could seek indictmentsagainst one or more Mirant entities, or the DOJ and Mirant could agree to adisposition that might involve undertakings or fines, the amount of whichcannot be reasonably estimated at this time but which could be material. Miranthas cooperated fully with the DOJ and intends to continue to do so. At thistime, it is the Company’s view that any action taken by the DOJ against Mirantor its subsidiaries related to the reporting of natural gas price informationwould not involve us or our subsidiaries except to the extent that anydisposition of this matter results in ongoing undertakings by Mirant EnergyTrading as the recipient of the assets of Mirant Americas Energy Marketingunder the Plan.

***Environmental Matters***

*EPAInformation Request.**  *InJanuary 2001, the EPA issued a request for information to Mirantconcerning the air permitting and air emissions control implications under theEPA’s new source review regulations (“NSR”) promulgated under the Federal CleanAir Act (“Clean Air Act”) of past repair and maintenance activities at thePotomac River plant in Virginia and the Chalk Point, Dickerson and Morgantownplants in Maryland. The requestedinformation concerns the period of operations that predates the Company subsidiaries’ownership and lease of those plants. Mirant has responded fully to thisrequest. Under the APSA, PEPCO is responsible for fines and penalties arisingfrom any violation associated with historical operations prior to the Companysubsidiaries’ acquisition or lease of the plants. If the Mirant Debtors succeedin rejecting the APSA as described above in *PEPCO Litigation*,PEPCO may assert that it has no obligation to reimburse Mirant for any fines orpenalties imposed upon Mirant for periods prior to the Company subsidiaries’acquisition or lease of the plants. If a violation is determined to haveoccurred at any of the plants, the Company subsidiary owning or leasing theplant may be responsible for the cost of purchasing and installing emissionscontrol equipment, the cost of which may be material. If such violation isdetermined to have occurred after the Company’s subsidiaries acquired or leasedthe plants or, if occurring prior to the acquisition or lease, is determined toconstitute a continuing violation, the Company subsidiary owning or leasing theplant at issue would also be subject to fines and penalties by the state orfederal government for the period subsequent to its acquisition or lease of theplant, the cost of which may be material.

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*MirantPotomac River Notice of Violation.**  *OnSeptember 10, 2003, the Virginia Department of Environmental Quality (“VirginiaDEQ”) issued a Notice of Violation (“NOV”) to Mirant Potomac River allegingthat it violated its Virginia Stationary Source Permit to Operate by emittingNOx in excess of the “cap” established by the permit for the 2003 summer ozoneseason. Mirant Potomac River responded to the NOV, asserting that the cap isunenforceable, noting that it can comply through the purchase of emissions allowancesand raising other equitable defenses. Virginia’s civil enforcement statuteprovides for injunctive relief and penalties. On January 22, 2004, the EPAissued an NOV to Mirant Potomac River alleging the same violation of itsVirginia Stationary Source Permit to Operate as set out in the NOV issued bythe Virginia DEQ.

On September 27, 2004, Mirant Potomac River,Mirant Mid-Atlantic, the Virginia DEQ, the Maryland Department of theEnvironment, the DOJ and the EPA entered into, and filed for approval with theUnited States District Court for the Eastern District of Virginia, a consentdecree that, if approved, will resolve Mirant Potomac River’s potentialliability for matters addressed in the NOVs previously issued by the VirginiaDEQ and the EPA. The consent decree requires Mirant Potomac River and MirantMid-Atlantic to (1) install pollution control equipment at the PotomacRiver plant and at the Morgantown plant leased by Mirant Mid-Atlantic inMaryland, (2) comply with declining system-wide ozone season NOx emissionscaps from 2004 through 2010, (3) comply with system-wide annual NOxemissions caps starting in 2004, (4) meet seasonal system averageemissions rate targets in 2008 and (5) pay civil penalties and performsupplemental environmental projects in and around the Potomac River plantexpected to achieve additional environmental benefits. Except for theinstallation of the controls planned for the Potomac River units and theinstallation of selective catalytic reduction (“SCR”) or equivalent technologyat Mirant Mid-Atlantic’s Morgantown Units 1 and 2 in 2007 and 2008, the consentdecree does not obligate the Company’s subsidiaries to install specificallydesignated technology, but rather to reduce emissions sufficiently to meet thevarious NOx caps. Moreover, as to the required installations of SCRs atMorgantown, Mirant Mid-Atlantic may choose not to install the technology by theapplicable deadlines and leave the units off either permanently or until suchtime as the SCRs are installed. The consent decree is subject to the approvalof the district court and the Bankruptcy Court.

The owners/lessors under the lease-financingtransactions covering the Morgantown and Dickerson plants (the “Owners/Lessors”)objected to the proposed consent decree in the Bankruptcy Court and filed amotion to intervene in the district court action. As part of a resolution ofdisputed matters in the Chapter 11 proceedings, the Owners/Lessors have nowagreed not to object to the consent decree, subject to certain terms set forthin the Plan and Confirmation Order.

On July 22, 2005, the district court granted amotion filed by the City of Alexandria seeking to intervene in the districtcourt action, although the district court imposed certain limitations on theCity of Alexandria’s participation in the proceedings. On September 23,2005, the City of Alexandria filed a motion seeking authority to file anamended complaint in the action seeking injunctive relief and civil penaltiesunder the Clean Air Act for alleged violations by Mirant Potomac River of itsVirginia Stationary Source Permit To Operate and the State of Virginia’s StateImplementation Plan. Based upon a computer modeling, the City of Alexandriaasserted that emissions from the Potomac River plant exceed national ambientair quality standards (“NAAQS”) for SO2, nitrogen dioxide (“NO2”), andparticulate matter. The City of Alexandria also contended based on its modelinganalysis that the plant’s emissions of hydrogen chloride and hydrogen fluorideexceed Virginia state emissions standards. Mirant Potomac River disputes theCity 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 filean amended complaint.

*MirantPotomac River Downwash Study.**  *OnSeptember 23, 2004, the Virginia DEQ and Mirant Potomac River entered intoan order by consent with respect to the Potomac River plant under which MirantPotomac River agreed to perform a modeling analysis to assess the potentialeffect of “downwash” 

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from the plant (1) onambient concentrations of SO2, NO2, carbon monoxide (“CO”) and particulatematter less than or equal to 10 micrometers (“PM10”) for comparison to theapplicable NAAQS and (2) on ambient concentrations of mercury forcomparison to Virginia Standards of Performance for Toxic Pollutants. Downwashis the effect that occurs when aerodynamic turbulence induced by nearbystructures causes emissions from an elevated source, such as a smokestack, tobe mixed rapidly toward the ground resulting in higher ground levelconcentrations of emissions. If the modeling analysis indicates that emissionsfrom the facility may cause exceedances of the NAAQS for SO2, NO2, CO or PM10,or exceedances of mercury compared to Virginia Standards of Performance forToxic Pollutants, the consent order requires Mirant Potomac River to submit tothe Virginia DEQ a plan and schedule to eliminate and prevent such exceedanceson a timely basis. Upon approval by the Virginia DEQ of the plan and schedule,the approved plan and schedule is to be incorporated by reference into theconsent order. The results of the computer modeling analysis showed thatemissions from the Potomac River plant have the potential to contribute tolocalized, modeled instances of exceedances of the NAAQS for SO2, NO2 and PM10under certain conditions.

On August 24, 2005, power production at all fiveunits of the Potomac River generating facility was temporarily halted in responseto a directive from the Virginia DEQ. The decision to temporarily shut down thefacility arose from findings of a study commissioned under the order by consentreferred to above. The Virginia DEQ’s directive was based on results from thestudy’s computer modeling showing that air emissions from the facility have thepotential to contribute to localized, modeled exceedances of the health-basedNAAQS under certain conditions. On August 25,2005, the District of Columbia Public Service Commission filed an emergencypetition and complaint with the FERC and the Department of Energy (“DOE”) toprevent the shutdown of the Potomac River facility. The matter remains pendingbefore the FERC and the DOE. On September 21, 2005, Mirant Potomac Rivercommenced partial operation of one unit of the plant. On December 20,2005, due to a determination by the DOE that an emergency situation exists withrespect to a shortage of electric energy, the DOE ordered Mirant Potomac Riverto generate electricity at the Potomac River generation facility, as requestedby PJM, during any period in which one or both of the transmission linesserving the central Washington, D.C. area are out of service due to a plannedor unplanned outage. In addition, the DOE ordered Mirant Potomac River, at allother times, for electric reliability purposes, to keep as many units inoperation as possible and to reduce the start-up time of units not inoperation. The DOE required Mirant Potomac River to submit a plan, on or beforeDecember 30, 2005, that met this requirement and did not significantlycontribute to NAAQS exceedances. The DOE advised that it would consider MirantPotomac River’s plan in consultation with the EPA. The order further providesthat Mirant Potomac River and its customers should agree to mutuallysatisfactory terms for any costs incurred by it under this order or just andreasonable terms shall be established by a supplemental order. Certain partiesfiled for rehearing of the DOE order, and on February 17, 2006, the DOEissued an order granting rehearing solely for purposes of considering therehearing requests further. Mirant Potomac River submitted an operating plan inaccordance with the order. On January 4, 2006, the DOE issued an interimresponse to Mirant Potomac River’s operating plan authorizing immediateoperation of one baseload unit and two cycling units, making it possible tobring the entire plant into service within approximately 28 hours. The DOE’sorder expires after September 30, 2006, but Mirant Potomac River expectsit will be able to continue to operate these units after that expiration. In aletter received December 30, 2005, the EPA invited Mirant Potomac Riverand the Virginia DEQ to work withthe EPA to ensure that Mirant Potomac River’s operating plan submitted to theDOE adequately addresses NAAQS issues. The EPA also asserts in its letter thatMirant Potomac River did not immediately undertake action as directed by theVirginia DEQ’s August 19, 2005, letter and failed to comply with therequirements of the Virginia State Implementation Plan established by thatletter. Mirant Potomac River received a second letter from the EPA on December 30,2005, requiring Mirant to provide certain requested information as part of anEPA investigation to determine the Clean Air Act compliance status of thePotomac River facility. The facility will not resume normal operations 

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untilit can satisfy the requirements of the Virginia DEQ and the EPA with respect toNAAQS, unless, for reliability purposes, it is required to return to operationby a governmental agency having jurisdiction to order its operation. On January 9,2006, the FERC issued an order directing PJM and PEPCO to file a long-term planto maintain adequate reliability in the Washington D.C. area and surroundingregion and a plan to provide adequate reliability pending implementation ofthis long-term plan. On February 8, 2006, PJM and PEPCO filed theirproposed reliability plans. The Company is working with the relevant state andfederal agencies with the goal of restoring all five units of the facility tonormal operation in 2007. The financial and operational implications ofthe discontinued or limited operation of the Potomac River plant or any suchmodifications are not known at this time, but could be material depending onthe length of time that operations are discontinued or limited.

*Cityof Alexandria Nuisance Suit.**  *OnOctober 7, 2005, the City of Alexandria filed a suit against MirantPotomac River and Mirant Mid-Atlantic in the Circuit Court for the City ofAlexandria. The suit asserts nuisance claims, alleging that the Potomac Riverplant’s emissions of coal dust, flyash, NOx, SO2, particulate matter, hydrogenchloride, hydrogen fluoride, mercury and oil pose a health risk to thesurrounding community and harm property owned by the City. The City seeksinjunctive relief, damages and attorneys’ fees. On February 17, 2006, theCity amended its complaint to add additional allegations in support of itsnuisance claims relating to noise and lighting, interruption of traffic flow bytrains delivering coal to the Potomac River plant, particulate matter from thetransport and storage of coal and flyash, and potential coal leachate into thesoil and groundwater from the coal pile.

*NewYork State Administrative Claim.**  *OnJanuary 24, 2006, the State of New York and the NYSDEC filed a notice ofadministrative claims in the Company’s Chapter 11 proceedings asserting a claimseeking to require the Company to provide funding to its subsidiaries owninggenerating facilities in New York to satisfy certain specified environmentalcompliance obligations. The State of New York alleges that during the pendencyof the Chapter 11 proceedings the Company and its subsidiaries that haveemerged from bankruptcy made decisions on behalf of the Company’s subsidiariesowning generating facilities in New York and did not appropriately maintain thecorporate separateness between itself and those subsidiaries. The Companydisputes those allegations. The State of New York cites various existingoutstanding matters between the State and the Company’s subsidiaries owninggenerating facilities in New York related to compliance with environmental lawsand regulations, most of which are not material. The most significantcompliance obligation identified by the State of New York in its notice ofadministrative claim relates to a consent decree entered into on June 11,2003 (the “2003 Consent Decree”), by Mirant New York and Mirant Lovett with theState of New York to resolve issues related to NSR requirements under the CleanAir Act related to the Lovett plant. Under the 2003 Consent Decree, MirantLovett is required to make an election to install certain environmentalcontrols on units 4 and 5 of the Lovett facility or shut down those units by2007 to 2008. The State of New York notes in its notice of administrative claimthat the cost of implementing such environmental controls could exceed $200million. The State of New York andthe NYSDEC have executed a stipulatedorder with the Company and its New York subsidiaries to stay resolution of thisadministrative claim. The stipulated order was entered by the Bankruptcy Courton February 23, 2006.

*Riverkeeper Suit AgainstMirant Lovett.**  *On March 11,2005, Riverkeeper, Inc. filed suit against Mirant Lovett in the UnitedStates District Court for the Southern District of New York under the FederalWater Pollution Control Act (the “Clean Water Act”). The suit alleges thatMirant Lovett’s failure to implement a marine life exclusion system at itsLovett generating plant and to perform monitoring for the exclusion of certainaquatic organisms from the plant’s cooling water intake structures violatesMirant Lovett’s water discharge permit issued by the State of New York. Theplaintiff requests the court to enjoin Mirant Lovett from continuing to operatethe Lovett generating plant in a manner that allegedly violates the Clean WaterAct, to impose civil penalties of $32,500 per day of violation, and to awardthe plaintiff attorney’s fees. On April 20, 2005, the district courtapproved a stipulation agreed to by the plaintiff and 

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Mirant Lovett thatstays the suit until 60 days after entry of an order by the Bankruptcy Courtconfirming a plan of reorganization for Mirant Lovett becomes final andnon-appealable.

***City of Alexandria Zoning Action***

***On December 18, 2004, the City Councilfor the City of Alexandria, Virginia (the “City Council”) adopted certainzoning ordinance amendments recommended by the City Planning Commission thatresulted in the zoning status of Mirant Potomac River’s generating plant beingchanged from “noncomplying use” to “nonconforming use subject to abatement.”Under the nonconforming use status, unless Mirant Potomac River applies for andis granted a special use permit for the plant during the seven-year abatementperiod, the operation of the plant must be terminated within a seven-yearperiod, and no alterations that directly prolong the life of the plant will bepermitted during the seven-year period. If Mirant Potomac River were to applyfor and receive a special use permit for the plant, the City Council wouldlikely impose various conditions and stipulations as to the permitted use ofthe 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 in1989 (the “1989 SUPs”), one applicable to the administrative office space atMirant Potomac River’s plant and the other for the plant’s transportationmanagement plan. Under the terms of the approved action, the revocation of the1989 SUPs was to take effect 120 days after the City Council revocation,provided, however, that if Mirant Potomac River within such 120-dayperiod filed an application for the necessary special use permits to bring theplant into compliance with the zoning ordinance provisions then in effect, theeffective date of the revocation of the 1989 SUPs would be stayed until finaldecision by the City Council on such application. The approved action furtherprovides that if such special use permit application is approved by the CityCouncil, revocation of the 1989 SUPs will be dismissed as moot, and if the CityCouncil does not approve the application, the revocation of the 1989 SUPs willbecome effective and the plant will be considered a nonconforming use subjectto abatement.***

***On January 18, 2005, Mirant Potomac River and MirantMid-Atlantic filed a complaint against the City of Alexandria and the CityCouncil in the Circuit Court for the City of Alexandria. The complaint seeks tooverturn the actions taken by the City Council on December 18, 2004, changingthe zoning status of Mirant Potomac River’s generating plant and approvingrevocation of the 1989 SUPs, on the grounds that those actions violatedfederal, state and city laws. The complaint asserts, among other things, thatthe actions taken by the City Council constituted unlawful spot zoning, werearbitrary and capricious, constituted an unlawful attempt by the City Councilto regulate emissions from the plant, and violated Mirant Potomac River’s dueprocess rights. Mirant Potomac River and Mirant Mid-Atlantic request the courtto enjoin the City of Alexandria and the City Council from taking anyenforcement action against Mirant Potomac River or from requiring it to obtaina special use permit for the continued operation of its generating plant. OnJanuary 18, 2006, the court issued an oral ruling following a trial that theCity of Alexandria acted unreasonably and arbitrarily in changing the zoningstatus of Mirant Potomac River’s generating plant and in revoking the 1989SUPs. On February 24, 2006, the court entered judgment in favor of MirantPotomac River and Mirant Mid-Atlantic declaring the change in the zoning statusof Mirant Potomac River’s generating plant adopted December 18, 2004, to beinvalid and vacating the City Council’s revocation of the 1989 SUPs. The Cityof Alexandria has filed notice of its appeal of this judgment.***

***PEPCO Assertion of Breach of Local Area SupportAgreement***

Following the shutdown ofthe Potomac River plant on August 24, 2005, Mirant Potomac River notifiedPEPCO on August 30, 2005, that it considered the circumstances resultingin the shutdown of the plant to constitute a force majeure event under theLocal Area Support Agreement dated December 19, 2000, between PEPCO andMirant Potomac River. That agreement imposes obligations upon Mirant 

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PotomacRiver to dispatch the Potomac River plant under certain conditions, to givePEPCO several years advance notice of any indefinite or permanent shutdown ofthe plant, and to pay all or a portion of certain costs incurred by PEPCO fortransmission additions or upgrades when an indefinite or permanent shutdown ofthe plant occurs prior to December 19, 2010. On September 13, 2005,PEPCO notified Mirant Potomac River that it considers Mirant Potomac River’sshutdown of the plant to be a material breach of the Local Area SupportAgreement that is not excused under the force majeure provisions of theagreement. PEPCO contends that Mirant Potomac River’s actions entitle PEPCO torecover as damages the cost of constructing additional transmission facilities.PEPCO, on January 24, 2006, filed a notice of administrative claimsasserting that Mirant Potomac River’s shutdown of the Potomac River plantcauses Mirant Potomac River to be liable for the cost of such transmissionfacilities, which cost it estimates to be in excess of $70 million. MirantPotomac River disputes PEPCO’s interpretation of the agreement. The outcome ofthis matter cannot be determined at this time. 

***Asbestos Cases***

As part of the PEPCOpurchase, Mirant agreed to indemnify PEPCO for certain liabilities arising inlawsuits filed after December 19, 2000, even if they relate to incidentsoccurring prior to that date, with certain qualifications. Since theacquisition, PEPCO has notified Mirant of more than 100 asbestos cases,distributed among three Maryland jurisdictions (Prince George’s County,Baltimore City and Baltimore County), as to which it claims a right ofindemnity. Based on information and relevant circumstances known at this time,the Company does not anticipate that these suits will have a material adverseeffect on its financial position, results of operations or cash flows. Underthe Plan these indemnity obligations arising under the APSA with PEPCO becamethe obligations of Mirant Power Purchase.

***New York Tax Proceedings***

The Company’s subsidiaries that own the Bowline andLovett generating plants in New York are the petitioners in various proceedings(“Tax Certiorari Proceedings”) initially brought in the New York state courtschallenging the assessed value of those generating plants determined by theirrespective local taxing authorities. Mirant Bowline has challenged the assessedvalue of the Bowline generating facility and the resulting local taxassessments paid for tax years 1995 through 2005. Mirant Bowline succeeded torights held by Orange & Rockland Utilities, Inc. (“Orange &Rockland”) for the tax years prior to its acquisition of the Bowline Plant in1999 under its agreement with Orange & Rockland for the purchase ofthat plant. Mirant Lovett has initiated proceedings challenging the assessedvalue of the Lovett facility for each of the years 2000 through 2005. If theTax Certiorari Proceedings result in a reduction of the assessed value of thegenerating facility at issue in each proceeding, the New York Debtor owning thefacility would be entitled to a refund with interest of any excess taxes paidfor those tax years.

On September 30, 2003, the Mirant Debtors filed amotion (the “Tax Determination Motion”) with the Bankruptcy Court requestingthat it determine what the property tax liability should have been for theBowline generating facility in each of the years 1995 through 2003 and for theLovett generating facility in each of the years 2000 through 2003. The basesfor the relief requested in the Tax Determination Motion on behalf of MirantBowline and Mirant Lovett were that the assessed values of the generatingfacilities made by the relevant taxing authorities had no justifiable basis andwere far in excess of their actual value. The local taxing authorities haveopposed the Tax Determination Motion, arguing that the Bankruptcy Court eitherlacks jurisdiction over the matters addressed by the Tax Determination Motionor should abstain from addressing those issues so that they can be addressed bythe state courts in which the Tax Certiorari Proceedings described in thepreceding paragraph were originally filed.

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Collectively, MirantBowline and Mirant Lovett have not paid approximately $62 million assessed bylocal taxing authorities on the Bowline and Lovett generating facilities for2003, which fell due on September 30, 2003, and January 30, 2004, approximately$53 million assessed by local taxing authorities on the generating facilitiesfor 2004 that fell due on September 30, 2004, and January 30, 2005,and approximately $59 million assessed by local taxing authorities on thegenerating facilities for 2005 that fell due on September 30, 2005, andJanuary 30, 2006, in order to preserve their respective rights to offsetthe overpayments of taxes made in earlier years against the sums payable onaccount of current taxes. The failure to pay the taxes due on September 30,2003, January 30, 2004, September 30, 2004, January 30, 2005,September 30, 2005, and January 30, 2006, could subject MirantBowline and Mirant Lovett to additional penalties and interest.

***Other Legal Matters***

The Company is involved invarious other claims and legal actions arising in the ordinary course ofbusiness. In the opinion of management, the ultimate disposition of thesematters will not have a material adverse effect on the Company’s financialposition, results of operations or cash flows.

***Other Contingencies***

On May 5, 2005,Mirant NY-Gen discovered a sinkhole at its Swinging Bridge dam, located inSullivan County, New York. In response, Mirant NY-Gen filled this sinkhole,inspected the dam’s penstock and slopes for damage, drew down the lake level,and cleaned the diversion tunnel. Mirant NY-Gen’s analysis indicates that themost probable cause of the sinkhole was erosion of soil comprising the damthrough a hole in the penstock. The dam is currently stabilized, but is in needof additional repairs. Mirant NY-Gen currently expects to incur additionalcosts to repair the dam that could be material. Mirant NY-Gen currently expectsto recover insurance proceeds for a portion of these repair costs. As a resultof the sinkhole, Mirant NY-Gen was required to perform and provide to the FERCa flood study relating to the Swinging Bridge, Rio and Mongaup reservoirs todetermine the maximum capacity of the reservoirs and the down streamconsequences of a rain event resulting in a greater than the maximum capacityevent. The flood study found that under the very extreme weather conditionsassumed for the study (which included rainfall over a short period in amountswell in excess of the highest rainfall amounts recorded for such a periodhistorically), the water flowing into the reservoirs could cause the level ofthe reservoirs to exceed the height of the dams at Mirant NY-Gen’s hydrofacilities, leading to downstream flooding. Mirant NY-Gen is evaluating theresults of the flood study and determining what modifications may be warrantedto its hydro facilities based on those results. The costs of suchmodifications, if any are necessary, are unknown at this time, but could besignificant. Mirant NY-Gen currently remains in Chapter 11. Mirant NY-Gen hasrequested the Bankruptcy Court to approve a debtor-in-possession loan to itfrom Mirant Americas to provide funding for the repairs on the Swinging Bridgedam.

**15.**   Asset Retirement Obligations

Effective January 1, 2003, the Company adoptedSFAS No. 143, which requires an entity to recognize the fair value of aliability for an asset retirement obligation in the period in which it isincurred. Additionally, effective December 31, 2005, the Company adoptedFIN 47,which expands the scope of asset retirement obligations to be recognizedto include asset retirement obligations that may be uncertain as to the natureor timing of settlement. Upon initial recognition of a liability for an assetretirement obligation or a conditional asset retirement obligation, an entityshall capitalize an asset retirement cost by increasing the carrying amount ofthe related long-lived asset by the same amount as the liability. The liabilityis accreted to its present fair value, and the capitalized cost is depreciatedover the useful life of the related asset. Asset retirement obligationsassociated with long-lived assets included within the scope of SFAS No. 143and FIN 47 are those for which a legal obligation exists under enacted laws,statutes and written or oral contractions, including obligations arising underthe doctrine of promissory estoppel.

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The Company identified certain asset retirementobligations within its power generation operations. These asset retirementobligations are primarily related to asbestos abatement in facilities on ownedor leased property and other environmental obligations related to fuel storagefacilities, wastewater treatment facilities, closing of ash disposal sites andclosing of owned pipelines.

Asbestos abatement is the most significant type ofasset retirement obligation identified for recognition in the Company’sadoption of FIN 47. The EPA has regulations in place governing the removal ofasbestos. Due to the nature of asbestos, it can be difficult to ascertain theextent of contamination in older acquired facilities unless substantialrenovation or demolition takes place. Therefore, the Company incorporatedcertain assumptions based on the relative age and size of its facilities toestimate the current cost for asbestos abatement. However, the actual abatementcost could differ from the estimates used to measure the asset retirementobligation. As a result, these amounts will be subject to revision when actualabatement activities are undertaken.

Thefollowing represents the balance of the asset retirement obligations and theadditions and accretion of the asset retirement obligations (in millions):

| ** **                                                                    | ** ** | **For the Years Ended  December 31,** | ** ** |
|-------------------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                                    | ** ** | **2005**                                                  | ** ** | **2004** | ** ** | **2003** | ** ** |
| Beginning balance, January 1                                             |       |                                                      | $          | 10 |   |   |   | $ | 9 |   |   |   | $ | — |   |   |
| Liabilities recognized upon adoption of SFAS 143                              |       |                                                      | —     |   |   |   | — |   |   |   | 8 |   |   |
| Revisions to cash flows for liabilities recognized upon adoption of  SFAS 143 |       |                                                      | (5         | ) |   |   | — |   |   |   | — |   |   |
| Liabilities recognized upon adoption of FIN 47                                |       |                                                      | 27         |   |   |   | — |   |   |   | — |   |   |
| Accretion expense                                                             |       |                                                      | 1          |   |   |   | 1 |   |   |   | 1 |   |   |
| Ending  balance, December 31                                             |       |                                                      | $          | 33 |   |   |   | $ | 10 |   |   |   | $ | 9 |   |   |

 

Thefollowing represents, on a pro forma basis, the amount of the liability forasset retirement obligations as if FIN 47 had been applied during all periodsaffected (in millions):

| ** **                                                                    | ** ** | **For the Years Ended  December 31,** | ** ** |
|-------------------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                                    | ** ** | **2005**                                                  | ** ** | **2004** | ** ** | **2003** | ** ** |
| Beginning balance, January 1                                             |       |                                                      | $          | 35 |   |   |   | $ | 33 |   |   |   | $ | — |   |   |
| Liabilities recognized upon adoption of SFAS 143                              |       |                                                      | —     |   |   |   | — |   |   |   | 8 |   |   |
| Revisions to cash flows for liabilities recognized upon adoption of  SFAS 143 |       |                                                      | (5         | ) |   |   | — |   |   |   | — |   |   |
| Liabilities recognized upon adoption of FIN 47                                |       |                                                      | —     |   |   |   | — |   |   |   | 23 |   |   |
| Accretion expense                                                             |       |                                                      | 3          |   |   |   | 2 |   |   |   | 2 |   |   |
| Ending  balance, December 31                                             |       |                                                      | $          | 33 |   |   |   | $ | 35 |   |   |   | $ | 33 |   |   |

 

**16.**   Commitments andContingencies

Mirant Americas Generationhas made firm commitments to buy materials and services in connection with itsongoing operations and has made financialguarantees relative to some of its investments.

***Cash Collateral and Letters of Credit***

In order to sell power and purchase fuel in theforward markets and perform other energy trading and marketing activities, theCompany often is required to provide trade credit support to its counterpartiesor make deposits with brokers. In addition, the Company often is required toprovide trade credit support for access to the transmission grid, toparticipate in power pools, to fund debt service reserves and for otheroperating activities. Trade credit support includes cash collateral, letters ofcredit and financial guarantees. In the event of default by the Company, thecounterparty can draw on a letter of credit or apply cash collateral held tosatisfy the existing amounts outstanding under an open contract. Letters ofcredit that 

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expired in 2005 were drawnor replaced with another form of credit support to the counterparty, asrequired. The Company’s outstanding issued letters of credit totaled $56million as of December 31, 2005.

Followingis a summary of cash collateral posted with counterparties and brokers andletters of credit issued at December 31, (in millions):

| ** **              | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------|------------|----------|------------|----------|------------|
| Cash collateral  posted |       | $        | 685        |     | $          | 407 |   |
| Letters of credit       |       | 56       |       | 226      |       |
| Total                   |       | $        | 741        |     | $          | 633 |   |

 

***Commitments***

Inaddition to debt and other obligations in the combined and consolidated balancesheets, Mirant Americas Generation has the following annual commitments at December 31,2005 under various agreements (in millions):

| **Fiscal Years Ending:**   | ** ** | ** ** | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|--------------------------------------|------------|------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| Operating leases                     |       | $          | 109        |     | $          | 116      |       | $        | 124        |     | $          | 145      |       | $              | 143        |      |       | $ | 1,745 |   |   | $ | 2,382 |   |
| Fuel and  transportation commitments |       | 296        |       | 217      |       | —   |       | —   |       | —   |       |     | —     |           |       | 513       |       |
| Long-term service  agreements        |       | 4          |       | 12       |       | 10       |       | 13       |       | 27       |       |     | 205        |           |       | 271       |       |
| Other purchase  commitments          |       | 142        |       | —   |       | —   |       | —   |       | —   |       |     | —     |           |       | 142       |       |
| Total commitments                    |       | $          | 551        |     | $          | 345      |       | $        | 134        |     | $          | 158      |       | $              | 170        |      |       | $ | 1,950 |   |   | $ | 3,308 |   |

 

*Operating Leases*

Mirant Mid-Atlantic leases the Morgantown andDickerson baseload units and associated property through 2034 and 2029,respectively, and has an option to extend the leases. Any extensions of therespective leases would be limited to 75% of the economic useful life of thefacility, as measured from the beginning of the original lease term through theend of the proposed remaining lease term. The Company is accounting for theseleases as operating leases. Rent expenses associated with the Morgantown andDickerson operating leases totaled approximately $99 million, $103 million and$96 million for the years ended December 31, 2005, 2004 and 2003,respectively. While there is variability in the scheduled payment amounts overthe lease term, the Company recognizes rental expense for these leases on astraight-line basis. The rental expense based on the original scheduled rentpayments is $96 million per year. The additional expense recorded in 2005 and2004 was payable under the terms of the leases and was commensurate with the0.5% increase in interest on the lessor notes that was payable by the lessorsfor the period in which Mirant Mid-Atlantic was not a reporting entity underthe Securities Exchange Act of 1934. As of December 31, 2005 and 2004,Mirant Mid-Atlantic had paid approximately $292 million and $285 million,respectively, of actual operating lease payments in accordance with the leaseagreements in excess of rent expense recognized. In addition to theregularly scheduled rent payments, Mirant Mid-Atlantic paid an additional $11million in 2004, as required by the lease agreements. A further $12 million ofscheduled rent due on June 30, 2005, was funded through a draw made by thelease trustee on letters of credit arranged by the Company. In September 2005,the lease trustee made an additional draw of $49 million prior to the lettersof credit expiration in September 2005. This amount is recorded in fundson deposit in the combined and consolidated balance sheets. On January 3,2006, as part of the settlement and emergence from bankruptcy, Mirant NorthAmerica posted a $75 million letter of credit for the benefit of MirantMid-Atlantic to cover the debt service reserve obligation on the leases. Uponposting of the letter of credit, the lease trustee returned $56 million of cashcollateral held to Mirant Mid-Atlantic.

As of December 31, 2005, the total notionalminimum lease payments for the remaining terms of the leases aggregatedapproximately $2.4 billion and the aggregate termination value for the leaseswas approximately $1.4 billion and generally decreases over time. MirantMid-Atlantic leases the Morgantown 

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and the Dickerson baseloadunits from third party owner lessors. These owner lessors each own theundivided interests in these baseload generating facilities. The subsidiariesof the institutional investors who hold the membership interests in the ownerlessors are called owner participants. Equity funding by the owner participantsplus transaction expenses paid by the owner participants totaled $299 million.The issuance and sale of pass through certificates raised the remaining $1.2billion needed for the owner lessors to acquire the undivided interests.

The pass through certificates are not directobligations of Mirant Mid-Atlantic. Each pass through certificate represents afractional undivided interest in one of three pass through trusts formedpursuant to three separate pass through trust agreements between Mirant Mid-Atlanticand State Street Bank and Trust Company of Connecticut, National Association,as pass through trustee. The property of the pass through trusts consists oflessor notes. The lessor notes issued by an owner lessor are secured by thatowner lessor’s undivided interest in the lease facilities and its rights underthe related lease and other financing documents.

On November 30, 2005, the Company entered into asettlement agreement with the Morgantown and Dickerson facilities’ ownerlessors and the indenture trustee. Pursuant to this settlement agreement andthe Plan, the Company has made several payments including a settlement paymentof $6.5 million each to the owner lessors and the indenture trustee, $2.9million as restoration payments under the leases, and a reimbursement of legaland consulting fees of approximately $22 million. With the exception of $6.5million paid to the indenture trustee in January 2006, the remainingamounts were paid in December 2005. The total costs of $38 million havebeen recorded in reorganization items, net in the combined statements ofoperations.

The Company hascommitments under other operating leases with various terms and expirationdates. Total minimum lease payments under non-cancelable operating leases is$16 million for the period from 2006 to 2010 and total $15 million thereafter.Expenses associated with these commitments totaled approximately $4 million,$5 million and $4 million during 2005, 2004 and 2003, respectively.

*Fuel andTransportation Commitments*

In April 2002, Mirant Mid-Atlantic enteredinto a long-term synthetic fuel purchase agreement. The fuel supplierconverts coal feedstock received at Mirant Mid-Atlantic’s Morgantownfacility into a synthetic fuel. Under the terms of the agreement, Mirant Mid-Atlanticis required to purchase a minimum of 2.4 million tons of fuel per annumthrough December 2007. Minimum purchase commitments became effective uponthe commencement of the synthetic fuel plant operation at the Morgantownfacility in July 2002. The purchase price of the fuel varies with thedelivered cost of the coal feedstock. Based on current coal prices, as of December 31,2005, total estimated commitments under this agreement were $200 million.Expenses associated with this agreement totaled approximately $125 million,$141 million and $115 million for the years ended December 31, 2005,2004 and 2003, respectively, and are recorded in cost of fuel, electricity andother products—nonaffiliate on the accompanying combined statements ofoperations.

In addition to the coal commitment described above,the Company has approximately $245 million in purchase commitments relatedto an arrangement between Mirant Energy Trading, formerly Mirant AmericasEnergy Marketing, and the synthetic fuel supplier whereby the synthetic fuelsupplier is required to purchase coal directly from the coal supplier. MirantEnergy Trading’s coal purchase commitments, and thereby the Company’scommitments, are reduced to the extent that the synthetic fuel supplierpurchases coal under this arrangement. Duringthe first quarter of 2005, the Company recognized a $13 million gain due to anet settlement in lieu of receiving certain volumes of coal from the coalsupplier as a result of rail car transportation scheduling issues which resultedin lower cost of fuel-affiliate.

The Company has also entered into a fuel supplyagreement with an independent third party to provide approximately 90% of theestimated coal to be burned at one of the New York facilities through 

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2005. The Company had totalminimum commitments under fuel purchase and transportation agreements of$513 million at December 31, 2005.

This supplierconcentration could adversely affect the Company’s financial position orresults of operations should these parties default under the provisions of theagreements.

*Long-TermService Agreements*

As of December 31,2005, the total estimated commitments under long-term service agreements (“LTSAs”)associated with turbines installed or in storage were approximately $271million. These commitments are payable over the terms of the respectiveagreements, which range from ten to twenty years. These agreements have termsthat allow for cancellation of the contracts by the Company upon the occurrenceof several major events during the term of the contracts. Estimates for futurecommitments for the LTSAs are based on the stated payment terms in thecontracts at the time of execution. These payments are subject to an annualinflationary adjustment.

*Other PurchaseCommitments*

*Other purchase commitmentsrepresents open purchase orders less invoices received or accrued related toopen purchase orders for general procurement of products and services purchasedin the ordinary course of business. These include construction, maintenance andlabor activities at the Company’s generation facilities. Mirant Mid-Atlanticentered into an agreement on June 24, 2005 for an SCR System at theMorgantown generating station. The system shall be furnished and installed tocomply with a State of Maryland environmental consent decree to reduce theemissions of NOx. The contract value of this capital expenditure isapproximately $94 million.*

 

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**Item 9.**                        Changesin and Disagreements with Accountants on Accounting and Financial Disclosure

None

**Item 9A.**                Controlsand Procedures

**InherentLimitations in Control Systems**

A control system,no matter how well conceived and operated, can provide only reasonable, notabsolute, assurance that the objectives of the control system are met. Further,the design of a control system must reflect the fact that there are resourceconstraints, and the benefits of controls must be considered relative to theircosts. Because of the inherent limitations in all control systems, noevaluation of controls can provide absolute assurance that all control issuesand instances of fraud, if any, within the Company have been detected. Theseinherent limitations include the realities that judgments in decision-makingcan be faulty, and that breakdowns can occur because of simple error ormistake. Additionally, controls can be circumvented by the individual acts ofsome persons, by collusion of two or more people, or by management override ofthe control. The design of any system of controls also is based in part uponcertain assumptions about the likelihood of future events, and there can be noassurance that any design will succeed in achieving its stated goals under allpotential future conditions. Over time, controls may become inadequate becauseof changes in conditions, or the degree of compliance with the policies orprocedures may deteriorate. Because of the inherent limitations in acost-effective control system, misstatements due to error or fraud may occurand not be detected. As a result, our management, including the Chief ExecutiveOfficer and Chief Financial Officer, does not expect that our disclosure controls and procedures, or our internal controlover financial reporting, will prevent all error and all fraud.

**Effectivenessof Disclosure Controls and Procedures**

As required by Exchange Act Rule 13a-15(b),our management, including our Chief Executive Officer and our Chief FinancialOfficer, conducted an assessment of the effectiveness of the design andoperation of our disclosure controls and procedures (as defined by Rules 13a-15(e) and15d-15(e) under the Exchange Act), as of December 31, 2005.Based upon this assessment, our management concluded that, as of December 31,2005, the design and operation of these disclosure controls and procedures wereeffective.

Appearing as exhibits tothis annual report are the certifications of the Chief Executive Officer andthe Chief Financial Officer required in accordance with Section 302 of theSarbanes-Oxley Act of 2002.

**Changes in Internal Controls**

Since October 1, 2005, ourBoard of Managers and several key senior management positions, includingthe Chief Executive Officer, have been replaced with new management personnelnot previously with the Company. Because acompany’s control environment is affected both by the attitude of seniormanagement and management’s awareness of the function of the controlenvironment, we have examined our control environment in light of thesemanagement changes to ensure that it is still functioning appropriately.

The Company’s new senior management personnel haveextensive experience in our sector and have demonstrated their support for astrong control environment. Furthermore, since their arrival, certain factorsthat we rely on to establish and maintain the proper “tone at the top,”including corporate governance policies and communication programs, have beensupported and strengthened. We have maintained the same information technologycontrols, and our internal audit and internal control organizations continue tofunction in the same manner as they did prior to the management changes andwithout restriction or limitation.

The management of the Company, therefore, hasconcluded that the changes to senior management that occurred in the fourthquarter of 2005 did not materially affect, and are not reasonably likely tomaterially affect, internal controls.

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**PART III**

**Item 10.**                 *Directors and Executive Officers of the Registrant*

Thefollowing table sets forth information with respect to our managers who are notalso executive officers as of January 1, 2006.
| Name                  | ** ** | ** ** | ** ** | **Age** | ** ** |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | **Position** | ** ** |
|-----------------------|------------|------------|------------|---------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------|------------|
| Edward R. Muller |       |       | 54         |    |       | 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, LLC. 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   |       |       | 61         |    |       | 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, LLC. 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). |

 

Thefollowing table sets forth information with respect to our executive officers asof January 1, 2006.
| Name                             | ** ** | ** ** | ** ** | **Age** | ** ** |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       | **Position** | ** ** |
|----------------------------------|------------|------------|------------|---------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------|------------|
| Robert M.  Edgell           |       |       | 59         |    |       | Chairman of the  Board, President and Chief Executive Officer of Mirant Americas  Generation, LLC as of January 9, 2006. Chairman of the Board  and Chief Executive Officer of Mirant Mid-Atlantic, LLC. 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.                                                                                                                                                                                                                                                                                                                                                                               |
| J. William  Holden III |       |       | 45         |    |       | Senior Vice  President, Chief Financial Officer and Treasurer. Mr. Holden has been  Senior Vice President and Treasurer of Mirant Corporation since  April 2002 and has served as Senior Vice President, Chief Financial  Officer and Treasurer of Mirant Americas Generation, LLC and Mirant  Mid-Atlantic, LLC since November 2002. Previously, he was Chief  Financial Officer for Mirant’s Europe group from 2001 to February 2002,  Vice President and Treasurer of Mirant from 1999 to 2001, Vice President,  Operations and Business Development for Mirant’s South American region from  1996 to 1999, and Vice President, Business Development for Mirant’s Asia  group from 1994 to 1995. He held various positions at Southern Company from  1985 to 1994 including Director of Corporate Finance. |
| Thomas E.  Legro            |       |       | 54         |    |       | Senior Vice  President, Controller and Principal Accounting Officer of Mirant Corporation,  Mirant Americas Generation, LLC and Mirant Mid-Atlantic, LLC as of  December 2005. Prior to joining Mirant, he served as Vice President,  Chief Accounting Officer and Corporate Controller, National Energy &  Gas Transmission, Inc. (2001-2004). Vice President, Corporate  Controller, Director of Financial Planning and Analysis, and Assistant  Controller, Edison Mission Energy (1990-2001).                                                                                                                                                                                                                                                                                                                        |

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| Robert E. Driscoll |   |   | 56 |   |   | Chief Operating  Officer of Mirant Americas Generation, LLC and Mirant  Mid-Atlantic, LLC as of January 9, 2006. Mr. Driscoll is  Senior Vice President and Head of Asset Management, U.S. Region of Mirant  Corporation. From 2001 through 2005, he was employed as Chief Executive  Officer, Australia and Senior Vice President, Asia of Edison Mission Energy  and from 1995 through 2001, he was employed as Senior Vice President, Asia of  Edison Mission Energy. |
|-------------------------|--------|--------|----|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| S. Linn  Williams  |   |   | 59 |   |   | Executive Vice  President and General Counsel of Mirant Americas Generation, LLC and  Mirant Mid-Atlantic, LLC since 2006. Executive Vice President, General  Counsel and Chief Compliance Officer of Mirant since 2005. Served as an  International Chamber of Commerce arbitrator (2004-2005). Chief Executive  Officer, European Division (1998-2000), and Senior Vice President and General  Counsel (1994-1998) of Edison Mission Energy.                                          |
| Vance N.  Booker   |   |   | 52 |   |   | Senior Vice  President, Administration of Mirant Americas Generation, LLC and Mirant  Mid-Atlantic, LLC since 2002. Senior Vice President, Administration of  Mirant since 1999. Vice President, Administration of Mirant (1998-1999).                                                                                                                                                                                                                                                  |
| Paul R.  Gillespie |   |   | 58 |   |   | Senior Vice  President of Mirant Americas Generation, LLC, and Mirant  Mid-Atlantic, LLC and Mirant since January 2006. Served as Counsel  and Tax Counsel at Haynes and Boone, LLP (2002-2005). Vice President of  Tax at Primus Telecommunications (2004-2005), Vice President of Tax and  Associate General Counsel at Optiglobe Communications, Inc (2000-2001) and  Vice President of Tax at Edison Mission Energy (1996-2000).                                          |

 

The executive officers ofMirant Americas Generation, LLC were elected to serve until theirsuccessors are elected and have qualified or until their removal, resignation,death or disqualification.

*FamilyRelationships*

None

*Certain LegalProceedings*

On July 14, 2003,Mirant and most of its domestic subsidiaries filed for reorganization underChapter 11 of the United States Bankruptcy Code. Certain of the Company’sofficers are also officers or directors of other subsidiaries that filed forreorganization under Chapter 11. As such, each of the Company’s executiveofficers has been associated with a corporation that filed a petition under thefederal bankruptcy laws within the last five years.

*Audit Committee andAudit Committee Financial Expert*

We do not have aseparately designated standing Audit Committee. Because Mirant AmericasGeneration is an indirect wholly-owned subsidiary of Mirant Corporation, theBoard of Managers does not have independent members and therefore has notseparately designated a member as a financial expert.

*Section 16(a) BeneficialOwnership Reporting Compliance*

We do not have equitysecurities registered pursuant to Section 12 of the Exchange Act andtherefore do not have officers with Section 16 reporting obligations.

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*Code of Ethics forSenior Financial Officers*

The Code of Ethics thatapplies to Mirant’s senior financial officers also applies to the seniorfinancial officers of Mirant Americas Generation. A copy of the code is postedon Mirant’s website at *www.mirant.com*and also will be provided, without charge, upon request made in writing to theCorporate Secretary at 1155 Perimeter Center West, Atlanta, GA 30338. We intendto post any amendments and waivers to the Code of Ethics for senior financialofficers on this website.

*ShareholderNominees to Board of Directors*

We will not adoptprocedures by which shareholders may recommend manager candidates because weare a wholly-owned subsidiary of Mirant Americas, Inc.

**Item 11.**                 *Executive Compensation*

Our executives and managers are not compensatedseparately for their service as executive officers and managers of MirantAmericas Generation.

We are a limited liability company that is managed bya Board of Managers. All members of our Board of Managers are officers ofMirant or its subsidiaries, and they do not receive any additional compensationfor their services as managers. Mirant Services, a direct subsidiary of Mirant,directly pays the salaries of our officers listed in Item 10. A portion ofthose salaries are effectively reimbursed to Mirant by us through anadministrative services agreement with Mirant Services. Consequently, we haveno compensation committee and no direct employment agreements.

None of our officers have any contracts or agreementsin their capacities as officers of Mirant Americas Generation.

All members of our management are eligible toparticipate in certain employee benefit plans and arrangements sponsored byMirant for its similarly situated employees. These may include the pensionplan, savings plan, long-term incentive compensation plan, annual incentivecompensation plan, health and welfare plans and other plans that may beestablished in the future.

All of our equity is heldby our direct parent, Mirant Americas, Inc. Therefore, our equity is notpublicly traded and there is no basis to compare the price performance of ourequity to the price performance of an index or peer group.

**Item 12.**                 *Security Ownership of Certain Beneficial Owners and Management*

We are a wholly-ownedsubsidiary of Mirant Americas, Inc.; therefore, none of our managers orofficers holds any equity interests in Mirant Americas Generation.

**Item 13.**                 *Certain Relationships and Related Transactions*

Our relationships withaffiliates and related transactions are described in Note 6 to ourcombined and consolidated financial statements.

**Item 14.**                 *Principal Accountant Fees and Services*

Not Applicable.

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**PART IV**

**Item 15.**                 *Exhibits and Financial Statements*

**a)**               1.                 *Financial Statements*

Our consolidated financialstatements, including the notes thereto and independent auditors’ reportthereon, are set forth on pages 79 through 131 of the Annual Report on Form 10-K,and are incorporated herein by reference.

**2.**                 *FinancialStatement schedules*

None

**3.**                 *Exhibit Index*
| Exhibit   Number | ** ** |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | **Exhibit Name** | ** ** |
|------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------------|------------|
| 1.1*             |       | Purchase  Agreement, dated as of October 2, 2001, among Mirant Americas Generation  Inc. (the “Company”) and Salomon Smith Barney Inc., Banc of America  Securities LLC, Blaylock & Partners, L.P., Scotia Capital  (USA) Inc., TD Securities (USA) Inc. and Tokyo-Mitsubishi International plc  as “Initial Purchasers” (designated in Mirant Americas Generation, Inc.  Registration Statement on Form S-4/A Amendment No. 1,  Registration No. 333-85124 as Exhibit 1.1) |
| 2.1*             |       | Amended and  Restated Joint Chapter 11 Plan of Reorganization for Registrant and its  Affiliated Debtors (designated on Form 8-K filed December 15,  2005 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*             |       | Limited Liability  Company Agreement for Mirant Americas Generation, LLC dated  October 31, 2001 (designated in Mirant Americas Generation, LLC  Form 10-Q for the Quarter Ended September 30, 2001 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)                                                                                                                                                                                                                                                      |

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| 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*  |   | Mirant Americas  Generation, LLC—Facility B Credit Agreement (Designated on  Form 8-K filed February 12, 2003 as Exhibit 10.70)                                                                                                                                         |
| 10.2*  |   | Mirant Americas  Generation, LLC—Facility C Credit Agreement (Designated on  Form 8-K filed February 12, 2003 as Exhibit 10.71)                                                                                                                                         |
| 10.3*  |   | California  Settlement Agreement dated January 13, 2005 (Designated on Mirant  Corporation Form 10-K for the year ended December 31, 2004 as  Exhibit 10.39)                                                                                                                      |
| 10.4*  |   | 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)                 |
| 10.5   |   | Administrative  Services Agreement dated as of January 3, 2006 between Mirant Americas  Generation, Inc. and Mirant Services, LLC                                                                                                                                                      |
| 10.6   |   | 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                                                                                         |
| 10.7   |   | 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                                                                                                                   |
| 10.8   |   | Power Sale, Fuel  Supply and Services Agreement dated as of January 3, 2006 between Mirant  Americas Energy Marketing, LP and Mirant Chalk Point, LLC                                                                                                                                       |
| 10.9   |   | Power Sale, Fuel  Supply and Services Agreement dated as of January 3, 2006 between Mirant  Americas Energy Marketing, LP and Mirant Mid-Atlantic, LLC                                                                                                                                      |
| 10.10  |   | Power Sale, Fuel  Supply and Services Agreement dated January 3, 2006 between Mirant  Americas Energy Marketing, LP and Mirant Potomac River, LLC                                                                                                                                           |
| 10.11  |   | Power Sale, Fuel  Supply and Services Agreement dated January 3, 2006 between Mirant  Americas Energy Marketing, LP and Mirant Texas, LP                                                                                                                                                         |
| 10.12  |   | Power Sale, Fuel  Supply and Services Agreement dated January 3, 2006 among Mirant  Americas Energy Marketing, LP, Mirant Delta, LLC, and Mirant  Potrero, LLC                                                                                                                         |
| 10.13  |   | Power Sale, Fuel  Supply and Services Agreement dated January 3, 2006 among Mirant  Americas Energy Marketing, LP and Mirant Zeeland, LLC                                                                                                                                                        |
| 10.14* |   | 2005 Omnibus  Incentive Compensation Plan (Designated on Mirant Corporation Form 8-K  filed January 3, 2006 as Exhibit 10.1)                                                                                                                                                           |

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| 12.1* |   | Statement  regarding ratio of earnings to fixed charges (designated in Mirant Americas  Generation, Inc. Registration Statement on Form S-4/A  Amendment No. 1, Registration No.333-85124 as Exhibit 12.1) |
|-------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 16.1* |   | Arthur Andersen  LLP letter to the Securities and Exchange Commission dated May 15, 2002  (designated as Exhibit 16 on Form 8-K filed May 16,  2002)                                                       |
| 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)).                                 |

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*                    Asteriskindicates exhibits incorporated by reference.

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities Exchange Actof 1934, the registrant has duly caused this report to be signed on its behalfby the undersigned, thereunto duly authorized, on this 31st day of March, 2006.
|        |     | MIRANT  AMERICAS GENERATION, LLC                |
|--------|----------|------------------------------------------------------|
|   | By:      | /S/ ROBERT M. EDGELL                                 |
|   | * * | Robert M. Edgell                                     |
|   | * * | *President  and Chief Executive Officer and Manager* |
|   | * * | *(Principal  Executive Officer)*                     |

 

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**MIRANT AMERICASGENERATION, LLC**

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below on March 31, 2006 by the following persons on behalf ofthe registrant and in the capacities indicated.
|                            | **Signatures** | ** **                                                  | ** ** |  | **Title** | ** ** |
|----------------------------|----------------|-------------------------------------------------------------|------------|--|-----------|------------|
| /s/ ROBERT M.  EDGELL      |           | President and  Chief Executive Officer and Manager of       |
| Robert M.  Edgell     |           | 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                                                  |
| Edward R.  Muller     |           | Mirant Americas  Generation, LLC                            |
| /S/ JAMES V. IACO          |           | Manager of                                                  |
| James V.  Iaco        |           | Mirant Americas  Generation, LLC                            |

 

 

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**Supplemental Information to be Furnished with ReportsFiled Pursuant toSection 15(d) of the Act by Registrants Which Have Not RegisteredSecurities Pursuant to Section 12 of the Act**

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

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