**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

----

**Form 10-K**

**x**                              ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934

**For the Fiscal Year Ended December 31, 2006**

**Or**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934

**For the Transition Periodfrom                    to**

**Mirant Corporation**

(Exact name of registrant asspecified in its charter)
| **Delaware**                                                       | **001 16107**             | **58 2056305**                        |
|--------------------------------------------------------------------|---------------------------|---------------------------------------|
| (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)         | ** **                |

 

Securitiesregistered pursuant to Section 12(b) of the Act:

|                                             | **Title of each class** | ** **                  | ** ** | ** ** | **Name of each exchange  on which registered** | ** ** |
|---------------------------------------------|-------------------------|-----------------------------|------------|------------|------------------------------------------------|------------|
| **Common Stock, par value $0.01 per share** |                    | **New York Stock Exchange** |
| **Series A Warrants**                  |                    | **New York Stock Exchange** |
| **Series B Warrants**                  |                    | **New York Stock Exchange** |

 

Securities registered pursuant to Section 12(g) of the Act:

**None**

Indicate by check markwhether the registrant is a well-known seasoned issuer (as defined by Rule 405of the Securities Act). o Yes  x No

Indicate by check mark if theregistrant is not required to file reports pursuant to Section 13 or Section 15(d) ofthe Exchange Act. o Yes  x 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 preceding 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days. x Yes o No

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained 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. o

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.x LargeAccelerated Filer   o Accelerated Filer   o Non-acceleratedFiler

Indicate by check markwhether the registrant is a shell company (as defined in 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

Aggregate market value ofvoting stock held by non-affiliates of the registrant was approximately$8,041,023,653 on June 30, 2006 (based on $26.80 per share, the closingprice in the daily composite list for transactions on the New York StockExchange that day). As of January 31, 2007, there were 255,974,046 sharesof the registrant’s Common Stock, $0.01 par value per share, outstanding.

 

----

**TABLEOF CONTENTS**

|               | ** ** | ** **                                                                                                         | ** ** | **Page** | ** ** |
|---------------|------------|--------------------------------------------------------------------------------------------------------------------|------------|----------|------------|
|          | ** ** | **Glossary of Certain Defined Terms**                                                                              |       | i - vi   |       |
|          | ** ** | **PART I**                                                                                                    | ** ** |     |       |
| Item 1.  |       | Business                                                                                                           |       | 6        |       |
| Item 1A. |       | Risk  Factors                                                                                                      |       | 27       |       |
| Item 1B. |       | Unresolved Staff Comments                                                                                          |       | 36       |       |
| Item 2.  |       | Properties                                                                                                         |       | 37       |       |
| Item 3.  |       | Legal  Proceedings                                                                                                 |       | 39       |       |
| Item 4.  |       | Submission of Matters to a Vote of Security Holders                                                                |       | 51       |       |
|          | ** ** | **PART II**                                                                                                   | ** ** |     |       |
| Item 5.  |       | Market for Registrant’s Common Equity, Related  Stockholder Matters and Issuer Purchases of Equity Securities |       | 52       |       |
| Item 6.  |       | Selected  Financial Data                                                                                           |       | 55       |       |
| Item 7.  |       | Management’s Discussion and Analysis of Results of  Operations and Financial Condition                        |       | 56       |       |
| Item 7A. |       | Quantitative and Qualitative Disclosures About Market  Risk                                                        |       | 90       |       |
| Item 8.  |       | Financial Statements and Supplementary Data                                                                        |       | F-2      |       |
| Item 9.  |       | Changes in and Disagreements with Accountants on  Accounting and Financial Disclosure                              |       | 94       |       |
| Item 9A. |       | Controls and Procedures                                                                                            |       | 94       |       |
| Item 9B. |       | Other  Information                                                                                                 |       | 95       |       |
|          | ** ** | **PART III**                                                                                                  | ** ** |     |       |
| Item 10. |       | Directors and Executive Officers of the Registrant                                                                 |       | 96       |       |
| Item 11. |       | Executive Compensation                                                                                             |       | 96       |       |
| Item 12. |       | Security Ownership of Certain Beneficial Owners and  Management and Related Stockholder Matters                    |       | 96       |       |
| Item 13. |       | Certain Relationships and Related Transactions                                                                     |       | 96       |       |
| Item 14. |       | Principal Accountant Fees and Services                                                                             |       | 96       |       |
|          | ** ** | **PART IV**                                                                                                   |       |     |       |
| Item 15. |       | Exhibits and Financial Statement Schedules                                                                         |       | 97       |       |

 

2

----

**Glossary of Certain Defined Terms**

**ACO**—Administrative ComplianceOrder.

**AEP**—American Electric Power, Inc.

**APB**—Accounting Principles Board.

**APB 18**—APB Opinion No. 18, *The Equity Method of Accounting for Investments in Common Stocks*.

**APB 22**—APB Opinion No. 22, *Disclosure of Accounting Policies*.

**APSA**—Asset Purchase and SaleAgreement.

**Bankruptcy Code**—United StatesBankruptcy Code.

**Bankruptcy Court**—United StatesBankruptcy Court for the Northern District of Texas, Fort Worth Division.

**Baseload Generating Units**—Unitsthat satisfy minimum baseload requirements of the system and produceelectricity at an essentially constant rate and runs continuously.

**BOT**—The Philippine Government’sbuild, operate and transfer program.

**CAIR**—Clean Air Interstate Rule.

**CAISO**—California IndependentSystem Operator.

**Cal DWR**—California Department ofWater Resources.

**Cal PX**—California PowerExchange.

**CAMR**—Clean Air Mercury Rule.

**CERCLA**—Federal ComprehensiveEnvironmental Response, Compensation and Liability Act of 1980.

**CFTC**—Commodity Futures TradingCommission.

**Clean Air Act**—Federal Clean AirAct.

**Clean Water Act**—Federal WaterPollution Control Act.

**CO**—Carbon monoxide.

**CO2**—Carbon dioxide.

**Company**—Old Mirant prior to January 3,2006, and new Mirant on or after January 3, 2006.

**CPUC**—California Public UtilitiesCommission.

**CUC**—Curacao Utilities Company.

**DOE**—United States Department ofEnergy.

**DOJ**—United States Department ofJustice.

**DP&L**—Dayton Power &Light.

**EBITDA**—Earnings before interest,taxes, depreciation and amortization.

**EITF**—The Emerging Issues TaskForce formed by the Financial Accounting Standards Board.

**EITF 04-13**—EITF Issue No. 04-13,*Accounting for Purchases and Sales of Inventorywith the Same Counterparty*.

i

----

**EITF 06-3**—EITF Issue No. 06-3,*How Taxes Collected from Customers and Remitted toGovernmental Authorities Should Be Presented in the Income Statement (That Is,Gross versus Net Presentation)*.

**EOB**—California ElectricityOversight Board.

**EPA**—United States EnvironmentalProtection Agency.

**EPAct 2005**—Energy Policy Act of2005.

**EPS**—Earnings per Share.

**ERCOT**—Electric ReliabilityCouncil of Texas.

**ERISA**—Employee Retirement IncomeSecurity Act of 1974.

**FASB**—Financial AccountingStandards Board.

**FERC**—Federal Energy RegulatoryCommission.

**FIN**—FASB Interpretation.

**FIN 46R**—FIN No. 46R, *Consolidation of Variable Interest Entities (revised December 2003)—anInterpretation of Accounting Research Bulletin No. 51*.

**FIN 47**—FIN No. 47, *Accounting for Conditional Asset Retirements—an interpretation of FASBStatement No. 143*.

**FIN 48**—FIN No. 48, *Accounting for Uncertainty in Income Taxes—an interpretation of FASBStatement No. 109*.

**FSP**—FASB Staff Position.

**FSP AUG AIR-1**—FSP AUGAIR-1, *Accounting for Planned Major MaintenanceActivities*.

**FSP FAS 13-2**—FSP FAS 13-2,*Accounting for a Change or Projected Change in theTiming of Cash Flows Relating to Income Taxes Generated by a Leveraged LeaseTransaction*.

**FSP FIN 46R-6**—FASB StaffPosition FASB Interpretation 46R-6, *Determining theVariability to Be Considered in Applying FASB Interpretation No. 46R*.

**GAAP**—Generally acceptedaccounting principles in the United States.

**Grand Bahama Power**—Grand BahamaPower Company.

**Gross Margin**—Operating revenueless cost of fuel, electricity and other products.

**Hudson Valley Gas**—Hudson ValleyGas Corporation.

**IBEW**—International Brotherhoodof Electrical Workers.

**ICE**—InterContinental Exchange, Inc.

**Intermediate Generating Units**—Unitsthat meet system requirements that are greater than baseload and less thanpeaking.

**ISO**—Independent System Operator.

**ISO**—**NE**—IndependentSystem Operator-New England.

**JEP**—Jamaica Energy Partners.

**JPPC**—Jamaica Private PowerCompany Limited.

**JPS**—Jamaica Public ServiceCompany Limited.

ii

----

**LIBOR**—London InterBank OfferedRate.

**LICAP**—Locational installedcapacity plan.

**LTSA**—Long term serviceagreement.

**Massachusetts DEP**—MassachusettsDepartment of Environmental Protection.

**MC Asset Recovery**—MC AssetRecovery, LLC.

**MDE**—Maryland Department of theEnvironment.

**Mirant**—Old Mirant prior to January 3,2006, and New Mirant on or after January 3, 2006.

**Mirant Americas**—Mirant Americas, Inc.

**Mirant Americas Energy Marketing**—MirantAmericas Energy Marketing, LP.

**Mirant Americas Generation**—MirantAmericas Generation, LLC.

**Mirant Asia-Pacific**—MirantAsia-Pacific Limited.

**Mirant Bowline**—Mirant Bowline,LLC.

**Mirant Canal**—Mirant Canal, LLC.

**Mirant Chalk Point**—Mirant ChalkPoint, LLC.

**Mirant Delta**—Mirant Delta, LLC.

**Mirant Energy Trading**—MirantEnergy Trading, LLC.

**Mirant JPS Finance**—Mirant JPSCOFinance LTD.

**Mirant Lovett**—Mirant Lovett,LLC.

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

**Mirant New York**—Mirant New York, Inc.

**Mirant North America**—MirantNorth America, LLC.

**Mirant NY-Gen**—Mirant NY-Gen,LLC.

**Mirant Pagbilao**—Mirant PagbilaoCorporation.

**Mirant Peaker**—Mirant Peaker,LLC.

**Mirant Potomac River**—MirantPotomac River, LLC.

**Mirant Power Purchase**—MirantPower Purchase, LLC.

**Mirant Sual**—Mirant SualCorporation.

**Mirant Sugar Creek**—Mirant SugarCreek, LLC.

**Mirant Trinidad Investments**—MirantTrinidad Investments, LLC.

**Mirant Zeeland**—Mirant Zeeland,LLC.

**MISO**—Midwest Independent TransmissionSystem Operator.

**MMbtu—**Million British ThermalUnits.

**MW**—Megawatt.

iii

----

**MWh**—Megawatt hour.

**NAAQS**—National ambient airquality standards.

**NEPOOL**—New England Power Pool.

**New Mirant**—Mirant Corporation onor after January 3, 2006.

**NO2**—Nitrogen dioxide.

**NOL**—Net operating loss.

**NOV**—Notice of violation.

**NOx**—Nitrogen oxides.

**NPC**—National Power Corporation.

**NSR**—New source review.

**NSTAR**—NSTAR Electric and GasCorporation.

**NYISO**—Independent SystemOperator of New York.

**NYSDEC**—New York State Departmentof Environmental Conservation.

**NYSE**—New York Stock Exchange.

**OCI**—Other comprehensive income.

**Ohio Edison**—Ohio Edison Company.

**Old Mirant**—MC 2005, LLC, knownas Mirant Corporation prior to January 3, 2006.

**Orange and Rockland**—Orange andRockland Utilities, Inc.

**OTC**—Over-the-Counter.

**Panda**—Panda-Brandywine, LP.

**Peaking Generating Units**—Unitsused to meet requirement during the periods of greatest or peak load on thesystem.

**Pension Protection Act**—PensionProtection Act of 2006.

**Pepco**—Potomac Electric PowerCompany.

**PG&E**—Pacific Gas &Electric Company.

**PILOT**—Payments in lieu of taxes.

**PJM**—Pennsylvania-NewJersey-Maryland Interconnection, LLC.

**PM10**—Particulate matter that is10 microns or less in size.

**PowerGen**—The Power GenerationCompany of Trinidad and Tobago.

**PPA**—Power purchase agreement.

**PUHCA**—Public Utility HoldingCompany Act of 1935.

**PURPA**—Public Utility RegulatoryPolicies Act of 1978.

**Reserve Margin**—Excess capacityover peak demand.

**RMR**—Reliability-must-run.

iv

----

**RPM**—Reliability Pricing Model.

**RTO**—Regional transmissionorganization.

**SAB**—SEC Staff AccountingBulletin.

**SAB No. 107**—SAB No. 107,*Share-Based Payment.*

**SAB No. 108**—SAB No. 108,*Considering the Effects of Prior Year Misstatementswhen Quantifying Misstatements in Current Year Financial Statements*.

**SCE**—Southern California EdisonCompany.

**SEC**—U.S. Securities and ExchangeCommission.

**Securities Act**—The SecuritiesAct of 1933.

**SFAS**—Statement of FinancialAccounting Standards Board.

**SFAS No. 5**—SFAS No. 5,*Accounting for Contingencies*.

**SFAS No. 109**—SFAS No. 109,*Accounting for Income Taxes*.

**SFAS No. 123**—SFAS No. 123,*Accounting for Stock-Based Compensation*.

**SFAS No. 123R**—SFAS No. 123R,*Share-Based Payment.*

**SFAS No. 132R**—SFAS No. 132R,**Employers’ Disclosures about Pensions and OtherPostretirement Benefits—an amendment of FASB Statements No. 87, 88, and106.**

**SFAS No. 133**—SFAS No. 133,*Accounting for Derivative Instruments and HedgingActivities*.

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

**SFAS No. 143**—SFAS No. 143,*Accounting for Asset Retirement Obligations*.

**SFAS No. 144**—SFAS No. 144,*Accounting for the Impairment or Disposal ofLong-Lived Assets*.

**SFAS No. 153**—**SFAS No. 153****, Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.**

**SFAS No. 155**—SFAS No. 155,*Accounting for Certain Hybrid Financial Instruments—anamendment of FASB Statements No. 133 and 140*.

**SFAS No. 156**—SFAS No. 156,*Accounting for Servicing of Financial Assets—anamendment of FASB Statement No. 140*.

**SFAS No. 157**—SFAS No. 157,*Fair Value Measurements.*

**SFAS No. 158**—SFAS No. 158,*Employer’s Accounting for Defined Benefit Pensionand Other Postretirement Plans: an amendment of FASB Statements No. 87,88, 106, and 132R*.

**SFAS No. 159**—SFAS No. 159,*The Fair Value Option for Financial Assets andFinancial Liabilities—Including an Amendment of FASB Statement No 115*.

**Shady Hills**—Shady Hills PowerCompany, L.L.C.

**SO2**—Sulfur dioxide.

**SOP 90-7**—Statement ofPosition 90-7, *Financial Reporting byEntities in Reorganization Under the Bankruptcy Code*.

**T&TEC**—Trinidad and TobagoElectricity Commission.

**The Tokyo Electric Power Company**—TheTokyo Electric Power Company, Incorporated.

v

----

**TPA**—Transition power agreement.

**UWUA**—Utility Workers Union ofAmerica.

**VaR**—Value-at-risk.

**VIE**—Variable interest entity.

**Virginia DEQ**—Virginia Departmentof Environmental Quality.

**West Georgia**—West GeorgiaGenerating Company, L.L.C.

vi

----

**CAUTIONARYSTATEMENT REGARDING FORWARD-LOOKING INFORMATION**

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,one can identify forward-looking statements by terminology such as “may,”“will,” “should,” “expect,” “plan,” “anticipate,” “estimate,” “predict,” “target,”“potential” or “continue” or the negative of these terms or other 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 industry of generating, transmitting and distributing electricity;changes in state, federal and other regulations (including rate and otherregulations); changes in, or changes in the application of, environmental andother laws and regulations to which we and our subsidiaries and affiliates areor could become subject;

·       failureof our assets to perform as expected, including outages for unscheduledmaintenance or repair, and the timely completion of the repairs on the Sualgenerating facility;

·       ourability to divest our Caribbean business at a price and on terms that we wouldbe willing to accept, and our ability to consummate the sale of our Philippinebusiness and the sale of six of our U.S. intermediate and peaking naturalgas-fired plants, as well as any adverse impact on our credit ratings that mayresult from such sales;

·       changesin market conditions, including developments in the supply, demand, volume andpricing of electricity and other commodities in the energy markets, or theextent and timing of the entry of additional competition in our markets orthose of our subsidiaries and affiliates;

·       increasedmargin requirements, market volatility or other market conditions that couldincrease our obligations to post collateral beyond amounts which are expected;

·       ourinability to access effectively the over-the-counter and exchange-basedcommodity markets or changes in commodity market liquidity or other commoditymarket conditions, which may affect our ability to engage in asset managementand proprietary trading activities as expected, or result in materialextraordinary gains or losses from open positions in fuel oil or othercommodities;

·       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 beyondcollateral posted;

·       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 ISOs or RTOs that reduce our revenue and mayresult in a failure to compensate our generation units adequately for all oftheir costs;

·       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, including its transportation, on terms and prices acceptable tous;

3

----

·       legislativeand regulatory initiatives and changes in the application of laws andregulations by national and local governments, including increases in tax ratesor assessments, in non-U.S. jurisdictions in which our subsidiaries operate;

·       factorsthat affect the operations of our international subsidiaries, such as politicalinstability, local security concerns, tax increases, expropriation of property,cancellation of contract rights and environmental regulations;

·       theinability of our operating subsidiaries to generate sufficient cash flow tosupport our operations;

·       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 supply and delivery of fuel for our facilities;

·       curtailmentof operations due to transmission constraints;

·       environmentalregulations that restrict our ability or render it uneconomic to operate ourbusiness, including regulations related to the emission of carbon dioxide andother greenhouse gases;

·       ourinability to complete construction of emissions reduction equipment by January 2010to meet the requirements of the Maryland Healthy Air Act, which may result inreduced unit operations and reduced cash flows and revenues from operations;

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

·       thefact that our New York subsidiaries remain 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 North Americaand Mirant Asia-Pacific Limited contained in their financing agreements andrestrictions on Mirant Mid-Atlantic contained in its leveraged lease documents,which may affect our ability to access the cash flow of those subsidiaries tomake debt service and other payments;

·       theresolution of claims and obligations that were not resolved during the Chapter11 process that may have a material adverse effect on our results ofoperations; and

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

Many of these risks arebeyond our ability to control or predict. All forward-looking statementsattributable to us or persons acting on our behalf are expressly qualified intheir entirety by cautionary statements contained throughout this report.Because of these risks, uncertainties and assumptions, you should not placeundue reliance on these forward-looking statements. Furthermore,forward-looking statements speak only as of the date they are made.

**Factors that CouldAffect Future Performance**

We undertake no obligation to update publicly orrevise any forward-looking statements to reflect events or circumstances thatmay arise after the date of this report.

4

----

In addition to thediscussion of certain risks in Management’s Discussion and Analysis of Resultsof Operations and Financial Condition and the accompanying Notes to Mirant’sconsolidated financial statements, other factors that could affect our futureperformance (business, financial condition or results of operations and cashflows) are set forth under “Item 1A. Risk Factors.”

**Certain Terms**

As used in this report, “we,” “us,” “our,” the “Company”and “Mirant” refer to Mirant Corporation and its subsidiaries, unless thecontext requires otherwise. Also, as used in this report “we,” “us,” “our,” the“Company” and “Mirant” refer to old Mirant prior to January 3, 2006, andto new Mirant on or after January 3, 2006, as further discussed in “ Item1. Business.”

5

----

**PART I**

**Item 1.****                        *Business***

**Overview**

We generate revenue primarily through the productionof electricity in the United States, the Philippines and the Caribbean. As of December 31,2006, we owned or leased 17,522 MW of electric generating capacity. Mirant Corporationwas incorporated in Delaware on September 23, 2005, and is the successorto a corporation of the same name that was formed in Delaware on April 3,1993. This succession occurred by virtue of the transfer of substantially allof Old Mirant’s assets to New Mirant in conjunction with Mirant’s emergencefrom bankruptcy protection on January 3, 2006. Old Mirant was thenrenamed and transferred to a trust, which is not affiliated with new Mirant.New Mirant serves as the corporate parent of the business enterprise and,pursuant to the Plan of Reorganization (the “Plan”) that was approved inconnection with old Mirant’s emergence from bankruptcy, has no successorliability for any unassumed obligations of old Mirant.

In the third quarter of 2006, we commenced separateauction processes to sell our Philippine (2,203 MW) and Caribbean (1,050 MW)businesses and certain of our U.S. natural gas-fired assets totaling 3,619 MW,including our Zeeland (903 MW), West Georgia (613 MW), Shady Hills (469 MW),Sugar Creek (561 MW), Bosque (546 MW) and Apex (527 MW) facilities. See Note 3to our consolidated financial statements for additional information regardingthe treatment of these businesses and assets as discontinued operations as aresult of these decisions.

On December 11, 2006, we entered into adefinitive purchase and sale agreement with a consortium of The Tokyo ElectricPower Company and Marubeni Corporation for the sale of our Philippine businessfor a purchase price of $3.424 billion, plus a working capital adjustment atthe closing. After the payment of related debt, which is estimated to be $642million at the closing, the net proceeds to Mirant are expected to be $3.121billion after transaction costs. The transaction is expected to close in thesecond quarter of 2007 after the satisfaction of certain customary conditionsand the return to operation of both units of the Sual plant.

On January 15, 2007, we entered into a definitivepurchase and sale agreement with a subsidiary of LS Power Equity Partners I,L.P., LS Power Equity Partners II, L.P. and certain other affiliated funds,(collectively, “LS Power”), for the sale of six U.S. natural gas-fired plantsfor a purchase price of $1.407 billion, which includes estimated workingcapital and certain surplus generating equipment. After the payment of $83million of related debt, the net proceeds are expected to be $1.307 billionafter transaction costs. The transaction is expected to close in the secondquarter of 2007 after the satisfaction of certain customary conditions.

The auction and due diligence processes in respect ofthe sale of the Caribbean business are under way and the sale of the Caribbeanbusiness is expected to close by mid-2007.

After giving effect to the aforementioned sales, ourcontinuing operations of 10,650 MW will consist of the ownership, long-termlease and operation of power generation facilities located in the Mid-Atlanticand Northeast regions of the United States and in California, and energytrading and marketing operations in Atlanta.

The annual, quarterly andcurrent reports, and any amendments to those reports, that we file with orfurnish to the SEC are available free of charge on our website atwww.mirant.com as soon as reasonably practicable after they are electronicallyfiled with or furnished to the SEC. General information about us, including ourCorporate Governance Guidelines, the charters for our Audit, Compensation, andNominating and Governance Committees, and our Code of Ethics and BusinessConduct, can be found at www.mirant.com. We will provide print copies of thesedocuments to any shareholder upon written request 

6

----

toCorporate Secretary, Mirant Corporation, 1155 Perimeter Center West, Atlanta,Georgia 30338-5416. Information contained in our website is notincorporated into this Form 10-K.

***U.S. Competitive Environment***

Historically, vertically integrated electric utilitieswith monopolistic control over franchised territories dominated the powergeneration industry in the United States. The enactment of the PURPA, and thesubsequent passage of the Energy Policy Act of 1992, fostered the growth ofindependent power producers. During the 1990s, a series of regulatory policieswere partially implemented at both the federal and state levels to encourage competitionin wholesale electricity markets.

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

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

A number of factors combined to create excessgenerating capacity in certain U.S. markets, including a 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. In certain markets in the United States, that excess has been absorbedor is close to being absorbed. Electricity demand has been growing and supplyhas not appreciably increased. Given the substantial time necessary to permitand construct new power plants, we think that the markets in the United Statesin which we operate need to begin the process now of adding generating capacityto meet growing demand. A number of key ISOs have implemented capacity marketsas a way to encourage such construction of additional generation, but it is notclear whether independent power producers will be sufficiently incentivized tobuild this new generation.

Falling reserve margins, as well as high electricityprices as a result of high natural gas prices, have led to renewed interest innew coal-fired or nuclear plants. Coal-fired generation and nuclear generationcurrently account for approximately 50% and 20%, respectively, of theelectricity produced in the United States. There is substantial environmentalopposition to building either coal-fired or nuclear plants.

In light of the foregoing market conditions, someregulated utilities are proposing to construct coal-fired units or nuclearplants, in some cases with governmental subsidies or under legislative mandate.Unlike independent power producers like us, these utilities often are able torecover fixed costs through regulated retail rates, allowing them to buildwithout relying on market prices to recover their investments.

Many regulated utilitiesare also seeking to acquire distressed assets or make substantial environmentalimprovements to existing coal plants, in each case with regulatory assurancethat the utility will be permitted to recover its costs, plus earn a return onits investment. Success by utilities in those efforts may put independent powerproducers at a disadvantage because they rely heavily on market prices ratherthan regulatory assurances.

7

----

**Business Segments**

Previously, we managed our business as three operatingsegments: United States, Philippines and Caribbean. In 2006, we commencedseparate auction processes to dispose of our Caribbean and Philippine businessesand certain U.S. natural gas-fired assets. The planned sales have resulted inthe reclassification of the revenues and expenses of these businesses andassets to discontinued operations and the reclassification of the relatedassets and liabilities to held for sale for all periods presented. In thefourth quarter of 2006, we re-evaluated the business segments of our continuingoperations. As a result, we now have four operating segments: Mid-Atlantic,Northeast, California and Other Operations. Other Operations includesproprietary trading and fuel oil management activities and gains and lossesrelated to a contractual arrangement entered into with Pepco with respect tocertain PPAs, including Pepco’s long-term PPAs with Panda and Ohio Edison (the “Back-to-BackAgreement”). For selected financial information about our business segments,see Note 20 to our consolidated financial statements contained elsewhere inthis report. See “Item 2. Properties” for a complete list of our assets. Wehave restated corresponding items of segment information for prior periods toconform with our current operating segments.

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

| ** **                   | ** ** | **Revenues** | ** ** | **%**  | ** ** | **Gross  Margin** | ** ** | **%**  | ** ** | **Operating  Income** | ** ** | **%**  | ** ** |
|------------------------------|------------|--------------|------------|--------|------------|-------------------|------------|--------|------------|-----------------------|------------|--------|------------|
| Business Segment:            |       |         |       |   |       |              |       |   |       |                  |       |   |       |   |   |   |   |
| Mid-Atlantic                 |       |         | $          | 1,901  |       |              | 61         | %      | $          | 1,318                 |       | 68     | %          |   | $ | 918 |   |   | 81 | % |
| Northeast                    |       |         | 827        |   |       | 27                | %          | 358    |       | 18                    | %          |   | 128        |   |   | 11 | % |
| California                   |       |         | 171        |   |       | 6                 | %          | 115    |       | 6                     | %          |   | 39         |   |   | 4 | % |
| Other Operations             |       |         | 204        |   |       | 6                 | %          | 118    |       | 6                     | %          |   | 52         |   |   | 5 | % |
| Eliminations                 |       |         | —     |   |       | —            | %          | 38     |       | 2                     | %          |   | (6         | ) |   | (1 | )% |
| Total Continuing  Operations |       |         | $          | 3,103  |       |              | 100        | %      | $          | 1,947                 |       | 100    | %          |   | $ | 1,131 |   |   | 100 | % |

 

*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.

*Ownership andOperation of Electricity Generation Assets*

As of December 31,2006, our continuing operations consist of owned or leased generationfacilities with 10,650 MW of generating capacity. Our generating portfolio isdiversified across fuel types, power markets and dispatch types and servescustomers located near many major metropolitan load centers. Our totalgeneration capacity includes approximately 32% baseload units, 48% intermediateunits and 20% peaking units.

*CommercialOperations*

Our commercial operations consist primarily ofprocuring fuel, dispatching electricity, hedging the production and sale ofelectricity by our generating facilities, fuel oil management and providinglogistical support for the operation of our facilities (for example, byprocuring transportation for coal). We often sell the electricity we produceinto the wholesale market at prices in effect at the time we produce it (“spotprice”). Those prices are volatile, however, and in order to reduce the risk ofthat volatility and achieve more predictable financial results, it is ourstrategy to enter into hedges—forward sales of electricity into 

8

----

the wholesale market andpurchases of fuel and emissions allowances to allow us to produce and sell theelectricity—for different periods of time. We procure these hedges in OTCtransactions or exchanges where electricity, fuel and emissions allowances arebroadly traded, or through specific transactions with buyers and sellers, usingfutures, forwards, swaps and options. We also sell capacity and ancillaryservices where there are markets for such products and when it is economic todo so. In addition to selling the electricity we produce and buying the fueland emissions allowances we need to produce electricity (“asset management”),we buy and sell some electricity that we do not produce and some fuel andemissions allowances that we do not need to produce electricity (“proprietarytrading”). Proprietary trading is a small part of our commercial operations,which we do in order to gain information about the markets to support our assetmanagement and to take advantage of selected opportunities that we may identifyfrom time to time. All of our commercial activities are governed by acomprehensive Risk Management Policy, which requires that our hedgingactivities with respect to our assets be risk-reducing and sets limits on thesize of trading positions and VaR in our proprietary trading activities.

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

We economically hedge a substantial portion of ourMid-Atlantic coal-fired baseload generation and certain of our Northeast coal,gas and oil-fired generation through OTC transactions. However, we generally donot hedge most of our intermediate and peaking units. In 2006 and thus far in2007, our Mirant Mid-Atlantic subsidiary entered into financial swaptransactions resulting in Mirant Mid-Atlantic being economically hedged forapproximately 92%, 93%, 97% and 38% of its expected on-peak coal-fired baseloadgeneration in 2007, 2008, 2009 and 2010, respectively. The financial swaptransactions include new hedges in addition to the previously disclosed January2006 hedges. These transactions are senior unsecured obligations of MirantMid-Atlantic and do not require the posting of cash collateral either forinitial margin or for securing exposure due to changes in power prices. As ofFebruary 26, 2007, our total portfolio is economically hedged approximately83%, 47%, 35% and 14% for 2007, 2008, 2009 and 2010, respectively. Thecorresponding fuel hedges are approximately 81%, 27%, 15% and 0% for 2007,2008, 2009 and 2010 respectively.

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

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 purchasecoal from a variety of suppliers under contracts with terms of varying lengths,some of which extend to 2009. For our oil-fired units, fuel typically ispurchased under short-term contracts linked to a transparent oil indexprice. For our gas-fired units, fuel typically is purchased under short-termcontracts with a variety of suppliers on a day-ahead or monthly basis.

Our coal supply primarilycomes from the Central Appalachian and Northern Appalachian coal regions. Allof our coal is delivered by rail, although we are in the process of permittinga barge unloading facility at our Morgantown station that will enable us toreceive coal by an alternative transportation source beginning in 2008. Wemonitor coal supply and delivery logistics carefully, and, despite occasional 

9

----

interruptionsof scheduled deliveries, to date we have managed to avoid any significantimpact to our operations. We maintain an inventory of coal at our coal-firedfacilities for this purpose. Interruptions of scheduled deliveries can occurbecause of supply disruptions due to strikes or other reasons or as a result ofrail system disruptions due to weather or other reasons.

*Mid-Atlantic Region*

We own or lease four generation facilities in theMid-Atlantic region with a total generation capacity of 5,256 MW: Chalk Point,Morgantown, Dickerson and Potomac River. Our Mid-Atlantic region had a combined2006 capacity factor (average percentage of full capacity used over a year) of36%. Our Mid-Atlantic facilities are located in Maryland and Virginia and wereacquired from Pepco in December 2000. The Chalk Point facility is ourlargest generation facility in the region. It consists of two coal-firedbaseload units, two oil and gas-fired intermediate units and two oil-fired andfive gas and oil-fired peaking units, for a total generation capacity of 2,429MW. Our next largest facility in the region is the Morgantown facility. Itconsists of two dual-fueled (coal and oil) baseload units and six oil-firedpeaking units, for a total generation capacity of 1,492 MW. The Dickersonfacility has three coal-fired baseload units, and one oil-fired and two gas andoil-fired peaking units, for a total generation capacity of 853 MW. The PotomacRiver station has three coal-fired baseload units and two coal-firedintermediate units, for a total generation capacity of 482 MW.

Power generated by our Mid-Atlantic facilities is soldinto the PJM market. For a discussion of the PJM market, see “RegulatoryEnvironment” below. We have participated indirectly in standard offer serviceauctions in Maryland and Washington, D.C. Power sales, made either directlythrough these auctions or indirectly through subsequent market transactionsthat are a result of the auction process, serve as economic hedges for theMid-Atlantic assets.

On August 24, 2005, power production at all fiveunits of the Potomac River generating facility was temporarily halted inresponse to a letter from the Virginia DEQ. OnAugust 25, 2005, the District of Columbia Public Service Commission filedan emergency petition and complaint with the FERC and the DOE to prevent theshutdown of the Potomac River facility. The matter remains pending before theFERC and the DOE. On December 20, 2005, due to a determination by the DOEthat an emergency situation existed with respect to the reliability of thesupply of electricity to central Washington, D.C., the DOE ordered MirantPotomac River to generate electricity at the Potomac River generating facility,as requested by PJM, during any period in which one or both of the transmissionlines serving central Washington, D.C. are out of service due to a planned orunplanned 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 in operationwithout contributing to any NAAQS exceedances. The DOE required Mirant PotomacRiver to submit a plan that met these requirements, on or before December 30,2005. The order further provides that Mirant Potomac River and its customersshould agree to mutually satisfactory terms for any costs incurred by it underthis order or just and reasonable terms shall be established by a supplementalorder. Certain parties filed for rehearing of the DOE order, and on February 17,2006, the DOE issued an order granting rehearing solely for purposes ofconsidering further the rehearing requests. Mirant Potomac River submitted anoperating plan in accordance with the order. On January 4, 2006, the DOEissued an interim response to Mirant Potomac River’s operating plan authorizingoperation of the units of the Potomac River generating facility on a reducedbasis, but making it possible to bring the entire plant into service withinapproximately 28 hours when necessary for reliability purposes. The DOE’s orderexpires July 1, 2007, but Mirant Potomac River expects it 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 addressed NAAQS issues. The EPA also asserted in its letter thatMirant Potomac River did 

10

----

notimmediately undertake action as directed by the Virginia DEQ’s August 19,2005, letter and failed to comply with the requirements of the Virginia StateImplementation Plan established by that letter. Mirant Potomac River received asecond letter from the EPA on December 30, 2005, requiring Mirant toprovide certain requested information as part of an EPA investigation todetermine the Clean Air Act compliance status of the Potomac River generatingfacility.

On June 1, 2006,Mirant Potomac River and the EPA executed an ACO by Consent to resolve the EPA’sallegations that Mirant Potomac River violated the Clean Air Act by notimmediately shutting down all units at the Potomac River facility upon receiptof the Virginia DEQ’s August 19, 2005, letter and to assure an acceptablelevel of reliability to the District of Columbia. The ACO (i) specifiescertain operating scenarios and SO2 emissions limits for the Potomac Riverfacility, which scenarios and limits take into account whether one or both ofthe 230kV transmission lines serving Washington, D.C. are out of service; (ii) requiresthe operation of trona injection units to reduce SO2 emissions; and (iii) requiresMirant Potomac River to undertake a model evaluation study to predict ambientair quality impacts from the facility’s operations. In accordance with thespecified operating scenarios, the ACO permits the facility to operate using adaily predictive modeling protocol. This protocol allows Mirant Potomac Riverto schedule the facility’s level of operations based on whether computermodeling predicts a NAAQS exceedance, based on weather and certain operatingparameters. On June 2, 2006, the DOE issued a letter modifying its January 6,2006, order to direct Mirant Potomac River to comply with the ACO in order toensure adequate electric reliability to the District of Columbia. MirantPotomac River is operating the Potomac River facility in accordance with theACO and has been able to operate all five units of the facility most of thetime under the ACO.

*Northeast Region*

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

*NewYork.**  *Our NewYork generating facilities were acquired from Orange and Rockland andConsolidated Edison Company of New York, Inc. in June 1999. The NewYork generating facilities consist of the Bowline and Lovett facilities andvarious smaller generating facilities comprising a total of 1,656 MW ofcapacity. The Bowline facility is a 1,125 MW dual-fueled (natural gas and oil)facility comprised of two intermediate/peaking units. 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 120 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 had anoperational interest in the Grahamsville facility, pursuant to a subleasebetween Orange and Rockland and Mirant NY-Gen. On October 31, 2006, wetransferred the Grahamsville facility to Orange and Rockland for transfer tothe City of New York. The capacity, energy and ancillary services from our NewYork generating units are sold into the bilateral markets and into the marketsadministered by the NYISO through Mirant Energy Trading. For a discussion ofNYISO, see “Regulatory Environment” below.

Our current plan is to retire units 3 and 5 at theLovett facility by April 30, 2007, and the remaining unit by April 30,2008, as required under the terms of a consent decree entered into on June 11,2003, to resolve issues related to NSR regulations promulgated under the CleanAir Act (the “2003 Consent Decree”) if certain environmental controls are notadded to the two units of the Lovett facility that burn 

11

----

coal. We are also considering scenarios that allowcontinued operations past April 2007 and April 2008 as we continue towork with the State of New York and other parties to achieve a solution relatedto environmental controls and to allow Lovett to continue to contribute to thereliability of the electric system of the State of New York. In orderfor the facility to remain viable on a long-term basis, we need to accomplishtwo primary tasks. First, we need to reach agreement with the State of New Yorkon amendments to the 2003 Consent Decreethat would address the installation of environmental equipment. Second, becausecurrent market conditions do not allow Mirant Lovett to recover the necessaryreturns to fund the installation of environmental controls specified under the2003 Consent Decree, we are seeking an agreement with a third party assuring usof enough revenue to justify the required capital expenditures. Our view isthat the Lovett facility is necessary to the provision of reliable electricityto the Lower Hudson Valley and other areas within the New York Control Area.

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

In May 2005, a sinkhole was discovered in the damof our Swinging Bridge facility. Inresponse, Mirant NY-Gen filled this sinkhole, inspected for damage the dam’sslopes and the enclosed pipe that delivers water from the reservoir to thegenerator, drew down the lake level and cleaned the diversion tunnel. MirantNY-Gen’s analysis indicates that the most probable cause of the sinkhole waserosion of soil comprising the dam from water flow through a hole in the pipethat delivers water from the reservoir to the generator. The dam is stabilized,and Mirant NY-Gen is performing additional remediation repairs. Byletter dated June 14, 2006, the FERC authorized Mirant NY-Gen to proceedwith its remediation plan for the sinkhole. The FERC has also concurred with theresults of Mirant NY-Gen’s flood study for its Swinging Bridge, Rio and Mongaupgeneration facilities, which study concluded that no additional remediation isrequired. On June 29, 2006, the Bankruptcy Court authorized Mirant NY-Gento proceed with implementation of the remediation plan. The current estimatedcost to remediate the dam at Swinging Bridge is approximately $29 million, ofwhich approximately $22 million had been incurred through December 31,2006. Mirant NY-Gen currently expects to recover insurance proceeds for aportion of these repair costs. TheBankruptcy Court has approved a debtor-in-possession loan to Mirant NY-Gen fromMirant Americas under which Mirant Americas, subject to certain conditions,would lend up to $16.5 million to Mirant NY-Gen to provide funding for therepairs on the Swinging Bridge dam.

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

On January 31, 2007, Mirant New York entered intoan agreement for the sale of Mirant NY-Gen, which owns the Hillburn andShoemaker gas turbine facilities and the Swinging Bridge, Rio and Mongauphydroelectric generating facilities. An auction process supervised by theBankruptcy Court is required before bankruptcy court approval may occur. Theestimated sales price of $3 million is subject to adjustments for workingcapital and certain dam remediation efforts that are ongoing at the SwingingBridge facility. The transaction is expected to close in the second quarter of2007.

12

----

*NewEngland.**  *Our NewEngland generating facilities, with a total capacity of 1,391 MW, were acquiredfrom subsidiaries of Commonwealth Energy System and Eastern UtilitiesAssociates in December 1998. The New England generating facilities consistof the Canal station, the Kendall station, the Martha’s Vineyard diesels and aninterest in the Wyman unit 4 facility. The Canal and Kendall facilities,located in close proximity to Boston, consist of 1,112 MW and 256 MW ofgenerating capacity, respectively, and are designed to operate during periodsof intermediate and peak demand. The Kendall facility is a combined cyclefacility which produces both steam and electricity for sale. Both the Canal andKendall facilities possess the ability to burn both natural gas and fuel oil.The Martha’s Vineyard diesels, with 14 MW of capacity, supply electricity onthe island of Martha’s Vineyard during periods of high demand or in the eventof a transmission interruption. The Wyman unit 4 interest is an approximate1.4% ownership interest (equivalent to 9 MW) in the 614 MW Wyman unit 4 locatedon Cousin’s Island, Yarmouth, Maine. Wyman unit 4 is primarily owned andoperated by the Florida Power and Light Group.

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

We had determined thatmarket fundamentals in NEPOOL did not permit us to operate the Kendall facilityon an economical basis as a merchant facility. We therefore had planned to shutdown, at least temporarily, the Kendall facility from January 2005 throughDecember 2007, with the possibility of restarting operations as early as January 2008.However, the ISO-NE determined that part of the capacity of the Kendallfacility was needed for reliability and proposed an RMR agreement with a termlasting until the earlier of (1) the date a locational installed capacitycost recovery mechanism applicable to the Kendall facility is in place or (2) 120-days after we are providedwritten notice. We entered into and received FERC approval for an agreementwith NSTAR and ISO-NE, which included the RMR agreement. On December 28,2006, ISO-NE provided notice that the RMR agreement shall terminate effective May 1,2007. A locational installed capacity market has been implemented in NewEngland and, as a result and coupled with additional steam sales, there are noplans to shut down the Kendall facility in 2007.

*California*

Our California facilities, with a total capacity of2,347 MW, are primarily gas-fired generating facilities and consist of thePittsburg, Contra Costa and Potrero facilities, which have generation capacityof 1,311 MW, 674 MW and 362 MW, respectively. Our California facilities had a2006 capacity factor of 6%*.*

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

Through the end of 2006, the majority of ourCalifornia assets were subject to RMR arrangements with the CAISO. Theseagreements are described further under “Regulatory Environment” below. OurCalifornia subsidiaries had the largest portfolio of units that operated underRMR arrangements in California, reflecting that the location of these units iskey to electric system reliability. Pittsburg unit 7 and Contra Costa unit 6were not subject to an RMR arrangement, and thus functioned solely as merchantfacilities in the CAISO. In 2006, we either sold the output of Pittsburg unit 7and Contra Costa unit 6 into the market through bilateral transactions withutilities and other merchant generators, or dispatched the units in the CAISOclearing markets.

On July 28, 2006, we signed two tollingagreements with PG&E to provide electricity from our natural gas-firedunits at Pittsburg and Contra Costa, including Pittsburg unit 7 and ContraCosta unit 6. The agreements are for 100% of the capacity from these assets,approximately 2,000 MW. The contracts have 

13

----

varying tenors rangingfrom one to four years, and include capacity of 1,985 MW for 2007, 2008 and2009, 1,303 MW for 2010 and 674 MW for 2011. We will receive monthly capacitypayments with bonuses and/or penalties based on guaranteed heat rate andavailability tolerances. As a result of these contracts, the Pittsburg andContra Costa units are no longer subject to the RMR agreements. Potrero units 3-6continue to be subject to the RMR arrangements as described.

On January 14, 2005,we and certain of our subsidiaries entered into a Settlement and Release ofClaims Agreement (the “California Settlement”) with PG&E, SCE, San DiegoGas and Electric Company, the CPUC, the Cal DWR, the EOB and the AttorneyGeneral of the State of California and with the Office of Market Oversight andInvestigations of the FERC. Pursuant to the settlement agreement that becameeffective in April 2005*,* thepartially constructed Contra Costa unit 8 project, which is a planned 530 MWcombined cycle generating facility, and related equipment (collectively, the “CC8Assets”) were transferred to PG&E on November 29, 2006. Mirant Deltareceived $70 million that under the terms of the settlement had been held in anescrow account to be paid to PG&E if the Contra Costa 8 project was nottransferred to it by June 30, 2008. We recognized a gain of $27 million inthe fourth quarter of 2006 as a result of these transfers.

***Discontinued Operations***

*Philippines*

Our subsidiaries have ownership interests in threegenerating facilities in the Philippines: Sual (1,218 MW/100% owned), Pagbilao(735 MW/100% owned) and Ilijan (1,251 MW/20% owned). As of December 31,2006, our net ownership interest in the generating capacity of these facilitieswas 2,203 MW.

Substantially all of the generation capacity of theSual and Pagbilao facilities is sold under long-term energy conversionagreements with the Philippine government-owned NPC. NPC acts as both thefuel supplier and the energy purchaser for the Sual and Pagbilao facilities.NPC procures all of the fuel necessary for generation at no cost to therespective operating company.

Under the energy conversion agreements, Sual andPagbilao receive both fixed capacity fees and variable energy fees. Fixedcapacity fees are paid without regard to the dispatch level of the facility.Variable energy fees are paid when the facility generates electricity.Currently, approximately 90% of the revenues with respect to our Philippineoperations come from fixed capacity charges. Nearly all of the capacity fees ofSual and Pagbilao are denominated in U.S. dollars. Energy fees and a portion ofthe capacity fees have both U.S. dollar and Philippine peso components that areindexed to inflation. The majority of the obligations of NPC under the energyconversion agreements are guaranteed by the full faith and credit of thePhilippine government.

The energy conversion agreements were executed underthe BOT program. The energy conversion agreements for the Sual, Pagbilao andIlijan facilities expire in October 2024, August 2025 and June 2022,respectively.

In addition to the energy conversion agreements withNPC, our Sual subsidiary has a joint marketing agreement with NPC for excesscapacity of 218 MW. Currently, electricity from the excess capacity of our Sualfacility is provided to selected customers such as economic zones, industrialcustomers and private electric distribution companies and cooperatives. As aresult of outages at both units of the Sual plant, we are currently purchasingpower from NPC to meet our supply obligations. See “Sual Outages” in Note 3 tothe consolidated financial statements where the outages are discussed further.

Real property taxes in thePhilippines are levied by applying a locally determined tax rate to the taxablevalue of property. We are currently the owner of record of the machinery andequipment on which real property taxes are levied but NPC is responsible forpayment of real property taxes under the energy conversion agreements for ourPagbilao and Sual power facilities. See Note 3 to the consolidatedfinancial 

14

----

statementscontained elsewhere in this report for further discussion of the real propertytaxes applicable to these facilities.

*Caribbean*

Our net ownership interest in the generating capacityof our Caribbean plants is 1,050 MW.

*JamaicaPublic Service Company Limited.*   We own an 80%interest in JPS, a fully integrated electric utility company that generates,transmits, distributes and sells electricity on the island of Jamaica. JPSoperates under a 20-year All-Island Electric License (the “License”) thatexpires in 2021 and that provides JPS with the exclusive right to sell power ona retail basis in Jamaica. Under the provisions of the License, JPS is grantedthe exclusive right to transmit, distribute and supply electricity throughoutthe island of Jamaica. JPS also has the right to develop new generationcapacity subject to a requirement that expansion projects in excess of 20 MW besubjected to a competitive tendering process. In instances of force majeure,the Office of Utilities and Regulation (the “OUR”) may waive the requirementsfor competitive tendering. JPS has installed generation capacity of 603 MW, andpurchases an additional 196 MW of firm capacity from three independent powerproducers under long-term purchase agreements and an additional 20 MW of energyfrom a wind farm on an as-available basis. JPS supplies electric power toapproximately 571,000 residential, commercial and industrial customers inJamaica. JPS is regulated by the OUR under a price cap model with rate casesheld every five years and with interim adjustments for changes in inflation,fuel prices, purchase power costs, foreign exchange movements and certainefficiency measures. JPS completed its most recent rate case in June 2004.

*GrandBahama Power Company.*   We own a 55.4% interest in Grand Bahama Power, a 151 MWintegrated electric utility company that generates, transmits, distributes andsells electricity on Grand Bahama Island. Grand Bahama Power has the exclusiveright and obligation to supply electric power to the residential, commercial andindustrial customers on Grand Bahama Island. As of December 31, 2006,Grand Bahama Power has approximately 19,000 customers. Grand Bahama Power’srates are set by the Grand Bahama Port Authority.

*ThePower Generation Company of Trinidad and Tobago.*   Weown a 39% interest in PowerGen, a power generation company that owns andoperates three power plants located on the island of Trinidad. The electricityproduced by PowerGen is provided to T&TEC, which serves approximately347,000 customers on the islands of Trinidad and Tobago and which holds a 51%interest in PowerGen. PowerGen has a power purchase agreement for approximately820 MW of capacity and spinning reserve with T&TEC that expires in 2009 andis guaranteed by the government of Trinidad and Tobago. Under this contract,the fuel is provided by T&TEC.

On December 6, 2005, PowerGen and T&TECexecuted a 30-year 208 MW power sales agreement. On February 23,2006, PowerGen began construction of the facility that is to supply the powerto be provided under this agreement and estimates a commercial operations dateof March 2007.

*CuracaoUtilities Company.*   We own a 25.5% interest in CUC at the Isla Refinery in Curacao,Netherlands Antilles. The 153 MW facility provides electricity, steam,desalinated water and compressed air to the refinery and up to 45 MW ofelectricity to the Curacao national grid.

At December 31, 2006, CUC was in technicaldefault under its $84 million senior debt facility due to delays incompletion of generation facilities. To date, CUC’s lenders have not exercisedtheir right to terminate the debt facility. CUC is currently pursuing anamendment and a waiver from the lenders and expects to receive it in the firstquarter of 2007. In the event the issue is not resolved, our annual dividendpayments from this investment may be at risk.

*Aqualectra.**  *We own a$40 million convertible preferred equity interest in Aqualectra, anintegrated water and electric company in Curacao, Netherlands Antilles, ownedby the government. Aqualectra has 

15

----

electric generatingcapacity of 235 MW and drinking water production capability of 69,000 cubicmeters per day. Aqualectra serves approximately 65,000 electricity and watercustomers. We receive 16.75% preferred dividends on our $40 millioninvestment on a quarterly basis. As described below, Aqualectra has not paid our September and December 2006preferred dividends because it is in default under its $87 million creditfacility. Aqualectra has a call option and we have a put option, both of whichare exercisable through December 31, 2007. We also have an option toconvert our convertible preferred equity interest in Aqualectra to commonshares through December 31, 2007. Neither we nor Aqualectra have exercisedsuch options at this time.

At December 31, 2006,Aqualectra was in default under its $87 million credit facility because ofbreaches in financial covenants. Aqualectra is in breach of thesecovenants primarily due to its inability to pass through escalating fuel coststo its customers. Aqualectra has been in default for breaching these debtcovenants in the past but has received waivers from the lenders which allowedthe payment of our preferred dividends. A primary condition of the bank waiverwas the existence of the energy fund. The energy fund, established by the Island Council and ExecutiveCouncil of the Island Territory of Curacao, was intended to stabilize the prices of theenergy related products on the island for the period 2005 through 2006.The energy fund was designed to provide Aqualectra with recovery of its fuelcosts in excess of those recovered from its customers for the period from January 2005 throughDecember 2006. As of December 31, 2006, the energy fund was depleted.The depletion of the fund has caused the bank waiver of the debt covenantbreach to expire. Aqualectra requesteda waiver from the lenders related toits financial covenant breaches but the lenders havedeclined to give a waiver until the energy fund is funded by the Curacaogovernment or the Curacao government provides for an increase in the Aqualectrarate structure to allow for the full recovery of its fuel costs. As of December 31,2006, dividend payments from Aqualectra totaling approximately $3 million arein arrears. Resolution of this issue could take several months andconsequently, the receipt of the March 2007 dividend payment could bedelayed.

***U.S. Natural Gas-Fired Assets***

Our six U.S. natural gas-fired intermediate andpeaking facilities have a total capacity of 3,619 MW.

The Zeeland facility, located in Zeeland, Michigan, iscomprised of simple cycle units totaling 327 MW of capacity and a 576 MWcombined cycle facility (903 MW of total capacity). The Zeeland facility isinterconnected with the International Transmission Company, which is a memberof the MISO and operates under the East Central Area Reliability CoordinationAgreement.

The West Georgia facility in Thomaston, Georgia, andthe Shady Hills facility in Pasco County, Florida, consist of gas and oil-firedcombustion turbines with capacities of 613 MW and 469 MW, respectively. Theyoperate in the Southeastern Electric Reliability Council. Currently, there isno ISO in the Southeastern Electric Reliability Council.

West Georgia has a PPA for a portion of the output ofthe West Georgia facility that will expire in May 2009. The annualcapacity amount nominated by West Georgia is approximately 448 MW. West Georgiareceives a capacity payment, start-up payments, and variable operating andmaintenance payments on a per MWh basis, and an index-based fuel payment. ThePPA allows West Georgia to provide replacement energy from the market to meetits contractual obligations. West Georgia may receive bonuses or incurpenalties for availability outside allowable limits. There are no provisionsfor renewal or extension of the contract. Output of the West Georgia facilitynot covered by the PPA is sold into the wholesale market by Mirant EnergyTrading.

West Georgia has a fuel supply contract which expiresin May 2009. West Georgia also has purchased firm gas transportation for22,500 MMbtu/day for the months of June through September under anagreement that expires in May 2009.

16

----

Shady Hills has a tolling agreement with acounterparty that runs through March 2007 for all of the facility’soutput. A second tolling agreement, which runs through April 2024, willbegin at the expiration of the existing agreement. Pursuant to the tollingarrangements, Shady Hills receives a monthly capacity payment, a variableoperating and maintenance payment on a per MWh basis, and a start-up paymenteach time a unit is turned on. The counterparty schedules and delivers allfuel. Shady Hills generates electricity and provides a heat rate andavailability guarantee and may receive bonuses and pay penalties when itsperformance is outside the guaranteed values.

The Sugar Creek facility is a 561 MW combined cyclefacility located in West Terre Haute, Indiana. The Sugar Creek facility has thephysical capability to be interconnected with either the Cinergy or AEPsystems. Cinergy is a member of the MISO, and AEP is a member of the PJMmarket. The facility is eligible to participate in the energy, capacity andancillary markets of PJM and MISO.

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

The Apex facility is a 527MW intermediate gas-fired combined-cycle facility located near Las Vegas,Nevada. Mirant Energy Trading has signed contracts with a third party for 225MW of capacity and energy from the Apex facility for the period from May 2003to April 2008.

**RegulatoryEnvironment**

The electricity industry is subject to comprehensiveregulation at the federal, state and local levels. At the federal level, theFERC has exclusive jurisdiction under the Federal Power Act over sales ofelectricity at wholesale and the transmission of electricity in interstatecommerce. Any of our subsidiaries that owns a generating facility 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 and theissuance of securities. In addition, under the Natural Gas Act, the FERC haslimited jurisdiction over certain resales of natural gas, but does not regulatethe prices received by our subsidiary that markets natural gas.

The FERC has authorized our subsidiaries thatconstitute public utilities under the Federal Power Act to sell energy andcapacity at wholesale at market-based rates and has authorized some of thesesubsidiaries to sell certain ancillary services at wholesale at market-basedrates. The majority of the output of the generation facilities owned by ourUnited States subsidiaries that constitute public utilities is sold pursuant tothis authorization, 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 undue marketpower in a regional market. The FERC requires that our subsidiaries withmarket-based rate authority, as well as those with blanket certificateauthorization permitting market-based sales of natural gas, adhere to certainmarket behavior rules and codes of conduct, respectively. If any of oursubsidiaries violates the market behavior rules or codes of conduct, theFERC may require a disgorgement of profits or revoke its market-basedrate authority or blanket certificate authority. If the FERC were to revokemarket-based rate authority, our affected subsidiary would have to file acost-based rate schedule for all or some of its sales of electricity atwholesale. If the FERC revoked the blanket certificate authority of any of oursubsidiaries, certain sales of natural gas would be prohibited.

17

----

Our facilities operate in ISO/RTO markets. In areaswhere ISOs or RTOs control the regional transmission systems, marketparticipants have expanded access to transmission service. ISOs operatereal-time and day-ahead energy and ancillary services markets, typicallygoverned by FERC-approved tariffs and market rules. Some RTOs and ISOs alsooperate capacity markets. Changes to the applicable tariffs and market rules maybe requested by market participants, state regulatory agencies and the systemoperator, and such proposed changes, if approved by the FERC, could have asignificant impact on our operations and business plan. While participation bytransmission-owning public utilities in ISOs and RTOs has been and isexpected to continue to be voluntary, the majority of such public utilities in NewEngland, New York, the Mid-Atlantic and California have joined the respectiveISO/RTO.

Our subsidiaries owning generation in the UnitedStates were exempt wholesale generators under the PUHCA, as amended, and all ofour subsidiaries owning generation outside the United States were eitherforeign utility companies or exempt wholesale generators. With the repeal ofthe PUHCA and the adoption of the Public Utility Holding Company Act of 2005,the FERC adopted new regulations effective February 8, 2006, that allowour subsidiaries owning generation in the United States to retain their exemptwholesale generator status as well as allow our subsidiaries owning generationoutside of the United States to remain either foreign utility companies orexempt wholesale generators.

State and local regulatory authorities havehistorically overseen the distribution and sale of electricity at retail to theultimate 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 electricity at retail in astate with a retail access program, it may be subject to state certificationrequirements and to bidding rules that provide default service tocustomers who choose to remain with their regulated utility distributioncompanies.

*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 and economically dispatchesgenerators. PJM administers day-ahead and real-time marginal cost clearingprice markets and calculates electricity prices based on a locational marginalpricing model. A locational marginal pricing model determines a price forenergy at each node in a particular zone taking into account the limitations ontransmission of electricity and losses involved in transmitting energy into thezone, resulting in a higher zonal price when cheaper power cannot be importedfrom another zone. Generation owners in PJM are subject to mitigation, whichlimits the prices that they may receive under certain specified conditions.

Load-serving entities within PJM are required to haveadequate sources of capacity. PJM operates a capacity market wherebyload-serving entities can procure their capacity requirements through asystem-wide single clearing price auction. In PJM, all capacity is assumed tobe universally deliverable, regardless of its location. PJM has greatlyexpanded its system to include Allegheny Power, Commonwealth Edison, AEP, DP&Land Dominion-Virginia Power. As a result, capacity prices have significantlydeclined. The PJM expansions have resulted in an apparent system-wide surplusof capacity, despite the fact that certain regions in PJM-Mid-Atlantic arecurrently in need of capacity additions.

On December 22, 2006, the FERC approved, withconditions, a settlement between PJM and multiple market participants regardingPJM’s RPM, which was originally filed with the FERC on August 31, 2005, toreplace the existing system-wide single clearing price capacity market. The RPMsettlement is intended to ensure reliability and reasonable rates in the PJMregion. The RPM settlement provides for a three-year forward capacity auctionusing a modified demand curve from the original RPM filing and locationaldeliverability zones that will be phased in over several years. Demand curvesare administrative 

18

----

mechanisms used toestablish electricity generation capacity prices. The RPM settlement willprovide increased opportunities for our power plants located in theMid-Atlantic region to receive more revenues for their capacity. The orderapproving the RPM is subject to rehearing and a motion to vacate. Partiesopposed to the RPM settlement have filed requests with the FERC to rehear,vacate or stay the effectiveness of the December 22, 2006, order, whichare currently pending before the FERC.

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 to first 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’s locational capacity market rules use a demandcurve mechanism to determine for every month the required amount of installedcapacity 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 years2005/2006, 2006/2007 and 2007/2008 with minor modifications to the NYISO’s proposal.The new demand curves may result in increased prices within the NYISO forcapacity.

Our New England plants participatein a market administered by ISO-NE. Mirant Energy Trading is a member ofNEPOOL, which is a voluntary association of electric utilities and other marketparticipants in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Islandand Vermont, and which functions as an advisory organization to ISO-NE. TheFERC approved ISO-NE as the RTO for the New England region effective on February 1,2005, making ISO-NE responsible for market rule filings at the FERC, inaddition to its responsibilities for the operation of transmission systems andadministration and settlement of the wholesale electric energy, capacity andancillary services markets. ISO-NE utilizes a locational marginal pricing modelsimilar to that used in PJM and NYISO. In early 2004, ISO-NE filed with theFERC to adopt a LICAP similar to NYISO’s capacity market. After extensivelitigation before the FERC on the LICAP proposal, on March 6, 2006,a comprehensive settlement proposal was filed with the FERC between ISO-NE andmultiple market participants that would replace the LICAP proposal with aforward capacity market (“FCM”) under which annual capacity auctions would beconducted for supply three years in advance of delivery. In addition, thesettlement provided for a four-year transition period under which capacitysuppliers would receive a set price for their capacity commencing on December 1,2006, and continuing with price escalators through May 31, 2010. On June 16,2006, the FERC issued a decision accepting the proposed FCM settlement withoutmodification. The FCM will result in increased opportunities for our NewEngland generators to receive more revenues for their capacity commencing in December 2006.The FERC’S orders regarding the LICAP and FCM are pending review with the U.S.Court of Appeals. On February 15, 2007, ISO-NE filed the market rules withthe FERC to implement FCM. The market rules were supported by a majorityof NEPOOL members. NEPOOL did not join in the filing but will be filingseparate comments. Existing resources will need to be qualified, and the amountof MW they have to participate in the first auction certified, by April 2007.In June 2007, another round of information will be due from new generators, ona more detailed and binding nature than the show of interest forms. In October,2007 all resources that want to participate in the first auction will be fully 

19

----

qualified by ISO-NE. Thefirst auction will take place starting February 4, 2008, for the deliveryperiod June 1, 2010 - May 31, 2011.

*California.  *OurCalifornia facilities are located inside the CAISO’s control area. The CAISOschedules transmission transactions, arranges for necessary ancillary servicesand administers a real-time balancing energy market. Most sales in Californiaare pursuant to bilateral contracts, but a significant percentage of generationoutput is sold in the real-time market. The CAISO does not operate a forwardmarket like those described for PJM and other Eastern ISO markets, nor does itcurrently operate a capacity market.

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

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

The FERC approved a $400 per MWh cap, effective on January 1,2006, on prices for energy in the CAISO market, which was an increase from theprevious $250 per MWh cap, but still far short of the $1,000 per MWh energy caputilized in the other FERC approved RTO markets. In addition, owners ofnon-hydroelectric generation in California, including certain of ourfacilities, must offer to keep their generation on-line and stand ready tooffer power into the CAISO’s spot markets if the output is not under contractor scheduled for delivery within the hour, unless granted a waiver by theCAISO. The practical effect of this rule is to obtain operating reserveswithout paying for them, and to release excess energy into the market, therebydepressing prices. On August 26, 2005, the Independent Energy Producers, atrade association, filed a complaint with 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 the must-offerrequirement. Prior to the FERC’s ruling on the merits of the complaint, theCAISO and multiple market participants filed a settlement that would implementa form of the RCST. On February 13, 2007, the FERC approved the RCSTsettlement with minor modifications with an effective date of June 1,2006. The RCST settlement may result in increased capacity revenueopportunities for generators and possibly could increase revenues for certainunits at our Pittsburg and Contra Costa plants for the June 1 - December 31,2006, period, depending upon how the CAISO implements the terms of thesettlement. However, after December 31, 2006, our Pittsburg and ContraCosta plants are under contract for varying periods from now until 2011,****and we will not realize any opportunities from RCST untilthose contracts expire.

The CPUC has issued aseries of orders purporting to require exempt wholesale generators and otherpower plant owners to comply with detailed operation, maintenance andrecordkeeping standards for electricity generating facilities. In its orders,the CPUC has stated its intent to implement and enforce these detailedstandards to maintain and protect the public health and safety of Californiaresidents and businesses, to ensure that electric generating facilities areeffectively and appropriately maintained and 

20

----

efficientlyoperated, and to ensure electrical service reliability and adequacy. The CPUChas adopted detailed reporting requirements for the standards, and conductsfrequent on-site spot inspections and more comprehensive facility audits toevaluate compliance. Some standards are intended to ensure that units aremaintained in a state of readiness so as to be available to operate ifrequested by a control area operator, while others provide procedures forchanging a unit’s long-term status. The CPUC’s efforts to implement and enforcethe operation, maintenance and recordkeeping standards could interfere with ourfuture ability to make economic business decisions regarding our units,including decisions regarding unit retirements, and could have a materialadverse impact on our business activities in California.

***EnvironmentalRegulation***

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 permits. Our costs of complying with environmental laws,regulations and permits are substantial. We expect that cash flows fromoperations will be sufficient to fund these capital expenditures.

*MarylandHealthy Air Act.*   On August 3,2006, we announced a plan to comply with the requirements of the MarylandHealthy Air Act by reducing SO2 emissions by as much as 95% at our Marylandpower plants. We will install flue gas desulphurization (“FGD”) emissionscontrols at our Chalk Point, Dickerson and Morgantown plants. In addition, wewill install selective catalytic reduction (“SCR”) systems at the Morgantown(as contemplated by the pending NOx Consent Decree described in “Item 3. LegalProceedings, Environmental Matters”) and Chalk Point facilities that willreduce NOx emissions byapproximately 80%. Together, the FGDs and the SCRs will reduce by approximately80% the emissions of ionic mercury from the three Maryland power plants.

The Maryland Healthy Air Act requires deeper reductionsin NOx and SO2 in 2010 and 2015 than reductions required under federal lawincluding the CAIR. As a result of passage of the more restrictive Marylandstate standard on NOx and SO2 emissions, our plan to install control equipmentwill allow the Maryland facilities to meet or exceed the CAIR limits. Weanticipate that the capital expenditures to achieve compliance for SO2 and NOxemissions will be approximately $1.6 billion through 2009. The Maryland HealthyAir Act also requires reductions of mercury emissions by the year 2010. As aresult of our installation of equipment to satisfy the more restrictiveMaryland state standard on mercury emissions, our Mid-Atlantic facilities willalso meet or exceed the CAMR limits. The state law also requires Maryland tojoin the Regional Greenhouse Gas Initiative (“RGGI”), a seven state plan toreduce CO2 emissions by 2018. The State of Maryland will initiate a rule-makingproceeding in 2007 to determine the regulatory framework for RGGIparticipation.

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

*AirEmissions Regulations.**  *Our mostsignificant environmental requirements in the United States generally fallunder the Clean Air Act and similar state laws. Under the Clean Air Act, we arerequired to comply with a broad range of mandates concerning air emissions,operating practices and pollution control equipment. Several of our facilitiesare located in or near metropolitan areas, such as New York City, Boston, SanFrancisco and Washington D.C., which are classified by the EPA as not achievingcertain NAAQS. As a result of the NAAQS classification of these areas, ouroperations are subject to more stringent air pollution requirements, including,in some cases, further emissions reductions. In the future, we anticipateincreased regulation of generation facilities under the Clean Air Act andapplicable state laws and regulations concerning air quality. Significant airregulatory programs to which we are subject include those described below.

21

----

*CleanAir Interstate Rule (CAIR).*   In May 2005,the EPA promulgated the CAIR regulations, which established in the easternUnited States an SO2 and NOx cap-and-allowancetrading program applicable to generation facilities. These cap-and-tradeprograms will be implemented in two phases, with the first phase going intoeffect in 2010 and more stringent caps going into effect in 2015. In order tocomply with the first phase of those regulations, we will have to installadditional pollution control equipment and/or purchase additional emissionsallowances, at significant cost. We are planning to install pollution controlequipment at some of our facilities to address, in part, our requirements underthe first phase of the CAIR. The costs of that equipment are included in ourestimate of anticipated environmental capital expenditures from 2007 through2010. However, since the determination of how much pollution control equipmentto install is based upon factors such as the cost of emissions allowances andthe operational demands on our generation facilities, our plans may changesignificantly. For our Maryland facilities, compliance with the MarylandHealthy Air Act meets or exceeds the requirements under CAIR.

*CleanAir Mercury Rule (CAMR).*   In May 2005, theEPA issued the CAMR, which limits total annual mercury emissions fromcoal-fired power plants across the United States through a two-phasedcap-and-trade program. The first phase begins in 2010 and the second phasebegins in 2018. The EPA expects that, in the first stage, the necessaryreductions in mercury will be achieved as a co-benefit using the same pollutioncontrol equipment required to achieve the reductions of SO2 and NOx under theCAIR. All states are required to adopt either the EPA rule or a state rule meetingthe minimum requirements outlined in the CAMR. Under the EPA rule, we willreceive an allocation of mercury emissions allowances associated with ourcoal-fired plants nationwide, unless there are restrictions imposed at thestate level. We expect our coal-fired facilities to comply with the CAMRregulations by taking advantage of the co-benefits derived from NOx and SO2controls that are, or will soon be, installed.

*NSRenforcement initiative.**  *In1999, the 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 cost. These enforcementactions were broadly challenged by the industry in the courts, among otherreasons, for being a new interpretation of longstanding regulations. In aneffort to provide additional clarity, it is expected that in 2007 the Bushadministration will adopt new air pollution rules to clarify whatconstitutes an emissions increase under the NSR program.

In 2001, the EPA requested information concerning someof our facilities in Maryland and Virginia covering a time period thatpre-dates our acquisition or lease of those facilities in December 2000.We responded fully to this request. Under the APSA, Pepco is responsible forfines and penalties arising from any violation associated with operations priorto our subsidiaries’ acquisition or lease of the plants. If a violation isdetermined to have occurred at any of the plants, our subsidiary owning orleasing the plant may be responsible for the cost of purchasing and installingemissions control equipment, the cost of which may be material. Oursubsidiaries owning or leasing the Chalk Point, Dickerson and Morgantown plantsin Maryland will be installing a variety of emissions control equipment onthose plants to comply with the Maryland Healthy Air Act, but that equipmentmay not include all of the emissions control equipment that would be requiredif a violation of the EPA’s NSR regulations is determined to have occurred atone or more of those plants. If such a violation is determined to have occurredafter our subsidiaries acquired or leased the plants or, if occurring prior tothe acquisition or lease, is determined to constitute a continuing violation,our subsidiary owning or leasing the plant at issue could also be subject tofines and penalties by the state or federal government for the period after itsacquisition or lease of the plant, the cost of which may be material, although applicablebankruptcy law may bar such liability for periods prior to January 3,2006, when the Plan became effective for us and our subsidiaries that own orlease these plants.

22

----

*Stateair regulations.*   Various stateswhere we do business also have other air quality laws and regulations withincreasingly stringent limitations and requirements that will become applicablein future years to our facilities and operations. We expect to incur additionalcompliance costs as a result of these additional state requirements, whichcould include significant expenditures on emissions controls or have otherimpacts on operations. Specific state items include:

*VirginiaCAIR and CAMR Implementation.**  *InApril 2006, Virginia enacted the Clean Smokestacks Law, which granted theVirginia State Air Pollution Control Board the discretion to limit the abilityof a facility in a non-attainment area to purchase additional mercury, SO2 andNOx allowances to achieve compliance with CAIR and CAMR. The State AirPollution Control Board has approved the implementing regulations to the CleanSmokestacks Law but they have not yet been promulgated. The State Air PollutionControl Board has interpreted the current form of these regulations asrestricting facilities in non-attainment areas from purchasing emissionallowances to achieve compliance with CAIR and CAMR. If the regulations arepromulgated in their current form and the State Air Pollution Control Board’sinterpretation is correct, such restrictions would reduce our flexibility incomplying with CAIR and CAMR and could result in operating restrictions for ourPotomac River generating facility in Virginia.

*MassachusettsEmissions Standards for Power Plants.**  *TheCommonwealth of Massachusetts has finalized regulations to further reduce NOxemissions from certain generation facilities. The Massachusetts regulationsrelate to NOx emissions during ozone season and become effective in 2009. Ouroperations will not be materially affected by the newly established limits.

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

On October 19, 2006, Mirant Lovett notified theNew York Public Service Commission, the NYISO, Orange and Rockland and certainother affected transmission and distribution companies in New York of itsintent to discontinue operation of units 3 and 5 of the Lovett facility in April 2007.The 2003 Consent Decree imposes similar requirements with respect to unit 4that have to be met by April 30, 2008.

*Climatechange.*   Concern over climate change 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 

23

----

restrictions on CO2emissions. In the last year, the United States Congress has considered billsthat would regulate domestic greenhouse gas emissions, but such bills have notreceived sufficient Congressional approval to date to become law. If the UnitedStates ultimately ratifies the Kyoto Protocol and/or if the United StatesCongress or individual states or groups of states in which we operate ultimatelypass legislation regulating the emissions of greenhouse gases such as the RGGIdiscussed below, any resulting limitations on generation facility CO2 emissionscould have a material adverse impact on all fossil fuel- fired generationfacilities (particularly coal-fired facilities), including ours.

On August 16, 2006, a model rule wasfinalized and seven states in the Northeast will move forward with theimplementation of the RGGI. This is a multi-state regional initiative that usesa regional cap-and-trade program to reduce CO2 emissions from power plants of25 MW or greater. The program aims to stabilize CO2 emissions to current levelsfrom 2009 to 2015. This is to be followed by a 10% reduction in emissions by2019. At this time, our assets in Maryland, Massachusetts and New York will beaffected, and we are evaluating our options to comply with the requirements ofthe rule.

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

At the federal level Congress is expected to advanceseveral mandatory CO2 bills, which may require reductions of CO2 emissionsnationwide.

*Waterregulations.**  *We arerequired under the 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. This is particularly true for regulatoryrequirements governing cooling water intake structures, which are subject toregulation under section 316(b) of the Clean Water Act. A recent decisionby the United States Court of Appeals for the Second Circuit in *Riverkeeper Inc. et al v. EPA*, in whichthe court**remanded numerousprovisions of the EPA’s current section 316(b) regulations for existingpower plants, has created substantial uncertainty about exactly whattechnologies or other measures will be needed to satisfy section 316(b) requirementsin the future and when any new requirements will be imposed. Until the EPA actson the issues remanded, it is impossible to say exactly what requirements willbe imposed or what they will cost.

In February 2006, Mirant Delta received correspondencefrom the U.S. Fish and Wildlife Service and the U.S. Army Corps of Engineersexpressing the view that the federal Endangered Species Act coverage for ourContra Costa and Pittsburg facilities located along the Sacramento River andSuisun Bay is insufficient or inoperative. Endangered Species Act consultationhas been formally reinitiated, and we are continuing to work with theseagencies to resolve these issues. It is possible, however, that we will beunable to resolve these issues with the agencies and that more formal legalaction may be instituted against us resulting in substantial fines oroperational curtailment of these facilities.

On May 10, 2006, the San Francisco Regional WaterQuality Control Board issued Mirant Potrero a National Pollution DischargeElimination System permit pursuant to the Clean Water Act regulating thePotrero facility’s cooling water and process water discharges to the SanFrancisco Bay. Communities for a Better Environment, an environmental advocacyorganization, contested various elements of the permit in a petition filed withthe California State Water Resources Control Board on June 8, 2006,seeking relief that could include a plant curtailment, and/or costlytechnological upgrades. Mirant Potrero filed a timely 

24

----

response to this petitionas the permit holder on November 27, 2006, in support of the RegionalBoard’s permit decision. A decision from the State Board is expected by July 2007.

On September 26, 2006, the MassachusettsDepartment of Environmental Protection and the EPA jointly issued to MirantKendall a Surface Water Discharge Permit (“SWDP”) and a National PollutantDischarge Elimination System (“NPDES”) permit for the Kendall generatingfacility. The new permit imposes in-stream temperature limits, an extensivetemperature, water quality and biological monitoring program, and a requirementto develop and install a barrier net system to reduce fish impingement andentrainment. The provisions regulating the thermal discharge could causesubstantial curtailments of the operations of the Kendall facility. MirantKendall has appealed significant portions of the SWDP and NPDES permit, alongwith a related state Water Quality Certificate. The portions of the permitsthat Mirant Kendall has appealed are stayed pending appeal. We are unable topredict the outcome of this proceeding.

*Wastes,hazardous materials and contamination.**  *Our facilities are subject to several wastemanagement laws and regulations in the United States. The Resource Conservationand Recovery Act of 1976 set forth comprehensive requirements for the handlingof 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, CERCLA, orSuperfund, establishes a framework for dealing with the cleanup of contaminatedsites. Many states have enacted similar state superfund statutes as well asother laws imposing obligations to investigate and clean up contamination.Areas of soil and groundwater contamination are known to exist at ourPittsburg, Contra Costa and Potrero facilities. Prior to our acquisition ofthose 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 andthe remediation of any groundwater or solid contamination identified byPG&E at the Pittsburg and Contra Costa generating facilities. Pursuant toour requests, PG&E has disposed of 807 cubic yards of contaminated soil atthe Potrero generating facility. We are not aware of soil or groundwaterconditions for which we expect our remediation costs to be material that arenot covered by third-party agreements.

25

----

**Employees**

At December 31, 2006, our corporate offices andmajority owned or controlled subsidiaries employed approximately 4,440 people.This number includes approximately 1,820 employees in the United States,approximately 1,620 employees in the Caribbean, and approximately 1,000employees in the Philippines. The following details the employees subject tocollective bargaining agreements:

 

| **Union**                                                                                                                      | ** ** | ** **                | ** ** | **Location** | ** ** | **Number of  Employees  Covered** | ** ** | **Contract  Expiration  Date** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------|------------|--------------|------------|----------------------------------------|------------|--------------------------------|------------|
| **Continuing Operations:**                                                                                                     |       |                      |       |         |       |                                   |       |                           |       |
| IBEW Local 1900                                                                                                                |       | Maryland  and Virginia    |       |         | 482        |                                   |       | 6/1/2010                       |       |
| IBEW Local 503                                                                                                                 |       | New  York                 |       |         | 136        |                                   |       | 6/1/2008                       |       |
| IBEW Local 1245                                                                                                                |       | California                |       |         | 123        |                                   |       | 10/31/2008                     |       |
| UWUA Local 369                                                                                                                 |       | Cambridge,  Massachusetts |       |         | 34         |                                   |       | 2/28/2009                      |       |
| UWUA Local 480                                                                                                                 |       | Sandwich,  Massachusetts  |       |         | 51         |                                   |       | 6/1/2011                       |       |
| Total                                                                                                                          |       |                      |       |         | 826        |                                   |       |                           |       |
| **Discontinued  Operations:**                                                                                                  |       |                      |       |         |       |                                   |       |                           |       |
| IBEW Local 396                                                                                                                 |       | Nevada                    |       |         | 18         |                                   |       | 7/28/2008                      |       |
| United Steel  Workers Local 12502(1)                                                                                           |       | Indiana  and Michigan     |       |         | 27         |                                   |       | 1/1/2007                       |       |
| Bahamas  Industrial Engineers, Managerial, and Supervisory Union(2)                                                            |       | Grand  Bahama             |       |         | 36         |                                   |       | 1/1/2005                       |       |
| Commonwealth Electrical  Workers Union(3)                                                                                      |       | Grand  Bahama             |       |         | 135        |                                   |       | 3/31/2005                      |       |
| Jamaica Public  Service Managers’ Association                                                                             |       | Jamaica                   |       |         | 165        |                                   |       | 11/30/2007                     |       |
| Union of Clerical  Administrative & Supervisory Employees; National Workers Union;  Bustamante Industrial Trade Union |       | Jamaica                   |       |         | 1,057      |                                   |       | 12/31/2007                     |       |
| Petroleum Workers  Federation of Curacao(4)                                                                                    |       | Curacao                   |       |         | 37         |                                   |       |                           |       |
| Total                                                                                                                          |       |                      |       |         | 1,475      |                                   |       |                           |       |

----

 

(1)          One year contractextension through 1/1/2008.

(2)          Union negotiations areat a stalemate. Overall, the industrial climate is stable.

(3)          Negotiations areongoing.

(4)          Initial contract undernegotiation.

To mitigate and reduce the risk of disruption duringlabor negotiations, we engage in contingency planning for continuation of ourgeneration and/or distribution activities to the extent possible during anadverse collective action by one or more of our unions. If our non-unionizedworkforce moved toward unionization, we could be materially affected throughincreased employee costs, work stoppages or both.

26

----

**Item 1A**                   *Risk Factors*

*The following arefactors that could affect our future performance:*

***Our revenues areunpredictable because many of our facilities operate without long-term powersales agreements, and our revenues and results of operations depend on marketand competitive forces that are beyond our control.***

We sell capacity,energy and ancillary services from many of our generating facilities intocompetitive power markets on a short-term fixed price basis or through powersales agreements. We are not guaranteed recovery of our costs or any return onour capital investments through mandated rates. The market for wholesaleelectric energy and energy services reflects various market conditions beyondour control, including the balance of supply and demand, the marginal and longrun costs incurred by our competitors and the impact of market regulation. Lackof diversification in revenue may also result in concentrated exposure tomarkets, especially PJM. The price for which we can sell our output may fluctuateon a day-to-day basis. The markets in which we compete remain subject to one ormore forms of regulation that limit our ability to raise prices during periodsof shortage to the degree that would occur in a fully deregulated market,limiting our ability to recover costs and an adequate return on our investment.Our revenues and results of operations are influenced by factors that arebeyond 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;

·       theability of wholesale purchasers of power to make timely payment for energy orcapacity, which may be adversely affected 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 prices we receive for sales ofenergy;

·       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 that 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.

27

----

***Changes incommodity prices may negatively affect our financial results by increasing thecost of producing power or lowering the price at which we are able to sell ourpower, and we may be unsuccessful at managing this risk.***

Our generation business is subject to changes in powerprices and fuel costs, which may affect 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 managementactivities 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, naturaldisasters, wars, embargoes and other catastrophic events, and federal, stateand foreign energy and environmental 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 affect our financial results andfinancial position, either favorably or unfavorably. Furthermore, the riskmanagement procedures we have in place may not always be followed or may notalways work as planned. As a result of these and other factors, we cannotpredict the impact that risk management decisions may have on our businesses,operating results or financial position. Although management devotes aconsiderable amount of attention to these issues, their outcome is uncertain.

***We are exposed tothe risk of fuel and fuel transportation cost increases and volatility andinterruption in fuel supply because our facilities generally do not havelong-term agreements for natural gas, coal and oil fuel supply.***

Although we attempt topurchase fuel based on our expected fuel requirements, we still face the risksof supply 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 maynot rise at the same rate, or may not rise at all, to match a rise in fuelcosts. This may have a material adverse effect on our financial performance.The volatility of fuel prices could adversely affect our financial results andoperations.

***Some of ourgeneration facilities depend on only one or a few customers or suppliers. Theseparties, as well as other parties with whom we have contracts, may fail toperform their obligations, or may terminate their existing agreements, whichmay result in a default on project debt or a loss in revenues and may requireus to institute legal proceedings to enforce the 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 facilities. The failure of any supplier orcustomer to fulfill its contractual obligations to the facility could have amaterial adverse effect on such facility’s financial results. The financialperformance of these facilities is dependent on the continued performance bycustomers and suppliers of their obligations under their long-term agreements.

28

----

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 generationfacilities involves risks that may have a material adverse impact on our cashflows and results of operations.***

The operation ofour generation facilities involves various operating risks, including, but notlimited 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 orgroundwater;

·       shortagesof equipment or spare parts;

·       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 theelimination of, the revenues generated by our facilities or an increase in thecosts of operating such facilities could materially affect our cash flows andresults of operations, including cash flows available to us to make payments onour debt or our other obligations.

***Our assetmanagement and proprietary trading activities may increase the volatility ofour quarterly and annual financial results.***

Weengage in asset management activities to economically hedge our exposure tomarket risk with respect to:  (1) electricitysales from our generation facilities; (2) fuel used by those facilities;and (3) emissions allowances. We generally attempt to balance ourfixed-price purchases and sales commitments in terms of contract volumes andthe timing of performance and delivery obligations through the use of financialand physical derivative contracts. We also use derivative contracts with respectto our limited proprietary trading andfuel oil management activities, through which we attempt to achieve incrementalreturns by transacting where we have specific market expertise. Derivativesfrom our asset management and proprietary trading activities are recorded on our balance sheet at fair valuepursuant to 

29

----

SFAS No. 133. None of our derivatives recorded at fairmarket value are designated as hedges under SFAS No. 133 and changes intheir fair value are therefore recognized currently in earnings as unrealizedgains or losses. As a result, our financial results—including gross margin,operating income and balance sheet ratios—will, at times, be volatile andsubject to fluctuations in value primarily due to changes in forwardelectricity and fuel prices. For a more detailed discussion of the accountingtreatment of our asset management and proprietary trading activities, see Note 7 to our consolidated financial statements,included herein.

***Our results aresubject to quarterly and seasonal fluctuations.***

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

·       variations in levels ofproduction.

***We compete to sellenergy and capacity in the wholesale power markets against some competitorsthat enjoy competitive advantages, including the ability to recover fixed coststhrough rate base mechanisms 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 affect our ability to compete effectively and could have anadverse impact on the revenues generated by our facilities.

***Operating inforeign countries involves a number of risks.***

Our operations andearnings in the Philippines and Caribbean have been, and may in the future be,affected from time to time in varying degrees by political instability and byother political developments and laws and regulations which may affect bothoperations and financial affairs, such as forced divestiture of assets orrequired public offerings of equity interests in those assets; restrictions onproduction, imports and exports; war or other international conflicts; civilunrest and local security concerns that threaten the safe operation of companyfacilities; price controls; tax increases and retroactive tax claims;expropriation of property; cancellation of contract rights; currencyfluctuations and environmental regulations. Both the likelihood of suchoccurrences and their overall effect upon us vary greatly from country tocountry and are not predictable.

***Our business andactivities are subject to extensive environmental requirements and could beadversely affected by such requirements, including future changes to them.***

Our business is subject to extensive environmentalregulations promulgated by federal, state and local authorities, which, amongother things, restrict the discharge of pollutants into the air, water andsoil, and also govern the use of water from adjacent waterways. Such laws andregulations frequently require us to obtain operating permits and remain incontinuous compliance with the conditions established by those operatingpermits. To comply with these legal requirements and the terms of our operatingpermits, we must spend significant sums on environmental monitoring, pollutioncontrol equipment and emissions allowances. If we were to fail to comply withthese requirements, 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.

30

----

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 April 2006, Maryland enacted the Healthy AirAct, which requires more significant reductions in emissions of NOx, SO2 and mercury than the recentlyfinalized CAIR and CAMR. This legislation affects our Chalk Point, Dickersonand Morgantown facilities. We anticipate that the capital expenditures toachieve compliance for SO2 and NOx emissions will be approximately $1.6 billionthrough 2009.

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 ourgeneration facilities, at disposal sites we currently utilize or have formerlyutilized, or at other locations for which we may be liable, or the failure orinability of parties contractually responsible to us for contamination torespond when claims or obligations regarding such contamination arise, couldhave a material adverse effect on our financial performance and condition.

***Major environmentalconstruction projects planned by 2010 at our Mid-Atlantic coal facilities maynot meet their anticipated schedule, which would restrict these units fromrunning at their maximum economic levels. In the event that the operatingconstraints were sufficiently severe, Mirant Mid-Atlantic may not havesufficient cash flow to permit it to make distributions or, if more severe, tomeet its obligations.***

Under the Maryland HealthyAir Act, we are required to reduce annual emissions below certain levels by January 2010.The levels established do not allow for the use of additional emissionsallowances to meet the mandated levels. To meet these requirements, we plan toinstall scrubbers on all of our Maryland coal facilities. We may not meet thisconstruction schedule by January 2010 due to a number of factors, whichmay result in a loss of cash flows from operations due to reduced unitoperations.

***The expecteddecommissioning and/or site remediation obligations of certain of ourgeneration facilities may negatively affect our cash flows.***

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 the 

31

----

future.If we are required to make material expenditures to decommission or remediateone or more of our facilities, such obligations will affect our cash flows andmay adversely affect our ability to make payments on our obligations.

***Our level ofindebtedness could adversely affect our ability to raise additional capital tofund our operations, limit our ability to react to changes in the economy orour industry and prevent us from meeting our obligations.***

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

***Mirant Corporationand its holding company subsidiaries, including Mirant Americas Generation andMirant North America, may not have access to sufficient cash to meet theirobligations if their subsidiaries, in particular, Mirant Mid-Atlantic, areunable to make distributions.***

We and certain of our subsidiaries, including MirantAmericas Generation and 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. In particular, asignificant portion of cash from our United States operations is generated bythe power generation facilities of Mirant Mid-Atlantic. Under the MirantMid-Atlantic leveraged leases, Mirant Mid-Atlantic is subject to a covenantthat restricts its right to make distributions to us. Mirant Mid-Atlantic’sability to satisfy the criteria set by that covenant in the future could beimpaired by factors which negatively affect the performance of its powergeneration facilities, including interruptions in operation or curtailment ofoperations to comply with environmental restrictions.

The obligations of MirantCorporation and its holding company subsidiaries, including the indebtedness ofMirant Americas Generation and Mirant North America, are effectivelysubordinated to the obligations or indebtedness of their respectivesubsidiaries, except to the extent that such obligations or indebtedness areassumed or guaranteed by a subsidiary.

***We may be unable togenerate sufficient liquidity to service our debt and to post required amountsof cash collateral necessary to effectively hedge market risks.***

Our ability to payprincipal and interest on our debt depends on our future operating performance.If our cash flows and capital resources are insufficient to allow us to makescheduled payments on our debt, we may have to reduce or delay capitalexpenditures, sell assets, seek additional capital, restructure or refinance.There can be no assurance that the terms of our debt will allow thesealternative measures, that 

32

----

thefinancial markets will be available to us on acceptable terms or that suchmeasures would satisfy 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 management activities may require us to post collateral either in theform of cash or letters of credit. As of December 31, 2006, we hadapproximately $227 million of posted cash collateral and $260 millionof letters of credit outstanding primarily to support our asset managementactivities 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.

We are an active participant in energy exchange andclearing markets. These markets require a per contract initial margin to beposted, regardless of the credit quality of the participant. The initialmargins are determined by the exchanges through the use of proprietary modelsthat rely on a variety of inputs and factors, including market conditions. Wehave limited notice of any changes to the margin rates. Consequently, we areexposed to changes in the per unit margin rates required by the exchanges andcould be required 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 issubject to complex government regulations. Changes in these regulations, ortheir administration, by legislatures, state and federal regulatory agencies,or other bodies may affect the costs of operating our facilities or our abilityto operate our facilities. Such cost impacts, in turn, may negatively affectour financial condition and results of operations.***

Generally, in the United States, we are subject toregulation by the FERC regarding the terms and conditions of wholesale serviceand rates, as well as by state agencies regarding physical aspects of ourgeneration facilities. The majority of our generation is sold at market pricesunder market-based rate authority granted by the FERC. If certain conditionsare not met, the FERC has the authority to withhold or rescind market-basedrate authority and require sales to be made based on cost-of-service rates. Aloss of our market-based rate authority could have a materially negative impacton our generation business.

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 affectour 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 intoPJM. Under PJM rules, AEP, Duquesne Light and DP&L were then deemed by PJMto be 

33

----

capable of providingcapacity to all areas of PJM. The integration of these companies into PJM inconjunction with the existing market rules depressed the prices that canbe charged for capacity in PJM.

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 certain of ourcompetitors. Many regulations that could be issued pursuant to the EPAct 2005may have an adverse impact on our business.

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 forthe supply of electricity, at both the wholesale and retail levels. Inaddition, any future legislation favoring large, vertically integratedutilities and a concentration of ownership of such utilities could affect ourability to compete successfully, and our business and results of operationscould suffer. We cannot provide assurance that the introductions of new laws,or other future regulatory developments, will not have a material adverseimpact on our business, operations or financial condition.

***We may be liablefor certain underfunded liabilities with respect to pension plans offered byMirant and its affiliates.***

We and our affiliates offer pension benefits toemployees through various pension plans. Funding obligations under the U.S.pension plans are governed by the ERISA and some of the plans are underfunded.As of December 31, 2006, our U.S. pension plans had an underfundedaccumulated benefit obligation of approximately $59 million, and anunderfunded projected benefit obligation of approximately $102 million, inaggregate as calculated in accordance with SFAS No. 158. As of December 31,2006, our non-U.S. pension plans were overfunded on an accumulated benefitobligation basis by approximately $78 million, and on a projected benefitobligation basis by approximately $54 million, in the aggregate, ascalculated in accordance with SFAS No. 158. Unless the underfundedliabilities are eliminated through asset returns, rising interest rates orother gains exceeding plan assumptions, we and our affiliates will have tosatisfy the underfunded amounts of these plans through cash contributions overtime. The timing and amounts of funding requirements depend upon a number offactors, including interest rates, asset returns, potential changes in pensionlegislation, our decision to make voluntary prepayments, applications for andreceipt of waivers to reschedule contributions and changes to pension planbenefits.

The Pension Protection Actwas enacted on August 17, 2006. While the Pension Protection Act will havesome effect on specific plan provisions in our retirement programs, the primaryeffect will be to change the minimum funding requirements for plan yearsbeginning in 2008. The Pension Protection Act has directed the United StatesDepartment of the Treasury to develop a new yield curve to discount pensionobligations for determining the funded status of a plan when calculatingfunding requirements. Until regulations are issued by the Department of theTreasury, we are unable to determine the effect on our consolidated financialstatements; however, such regulations are unlikely to have a material adverseeffect on our results of operations.

34

----

***Changes intechnology may significantly affect our generation business by making ourgeneration facilities less competitive.***

A basic premise of ourgeneration business is that generating power at central facilities achieveseconomies of scale and produces electricity at a low price. There are othertechnologies that can produce electricity, most notably fuel cells,microturbines, windmills and photovoltaic solar cells. It is possible thatadvances in technology will reduce the cost of alternative methods ofelectricity production to levels that are equal to or below that of mostcentral station electric production, which could have a material impact on ourresults of operations.

***Terrorist attacks,future war or risk of war may adversely affect our results of operations, ourability to raise capital or our future 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 affected. In addition, such an attack could affect ourability to service our indebtedness, our ability to raise capital and ourfuture growth opportunities.

***Our operations aresubject to hazards customary to the power generation industry. We may not haveadequate insurance to cover all of these 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 injury topersonnel or loss of life, severe damage to and destruction of property, plantand equipment, contamination of, or damage to, the environment and suspensionof operations. The occurrence of any one of these events may result in ourbeing named as a defendant in lawsuits asserting claims for substantialdamages, environmental cleanup costs, personal injury and fines and/orpenalties. We maintain an amount of insurance protection that we consideradequate, but we cannot assure that our insurance will be sufficient oreffective under all circumstances and against all hazards or liabilities towhich we may be subject. A successful claim for which we are not fully insuredcould have a material adverse effect on our financial results and our financialcondition.

***The subsidiariesthat own our generation facilities in New York, including our Lovett andBowline facilities, have not emerged from Chapter 11.***

Our subsidiaries related to our New York businessoperations, Mirant New York, Mirant Bowline, Mirant Lovett, Hudson Valley Gasand Mirant NY-Gen, remain in bankruptcy. Our Lovett and Bowline generationfacilities in New York were subject to disputes with local tax authoritiesregarding property tax assessments that were not resolved until December 2006.Mirant Lovett is in discussions with the NYSDEC and the New York State Officeof the Attorney General regarding environmental controls required under the2003 Consent Decree for the Lovett generation facility to continue operatingpast April 30, 2007, for unit 5 and past April 2008, with respect tounit 4. Until a resolution is reached on environmental controls that wouldpermit economically feasible operation, Mirant Lovett will likely remain inChapter 11. Mirant NY-Gen, which owns hydroelectric facilities at SwingingBridge, Rio and Mongaup, and small combustion turbine facilities at Hillburnand Shoemaker, is insolvent. Its expenses are being funded under adebtor-in-possession facility provided by Mirant Americas with the approval of,and under 

35

----

the supervision of, theBankruptcy Court. Mirant NY-Gen is proceeding with the implementation of aremediation plan for the sinkhole discovered in May 2005 in the dam at theSwinging Bridge facility.

On January 26, 2007, the Emerging New YorkEntities filed the Supplemental Plan with the Bankruptcy Court. For moreinformation on the Supplemental Plan, see “Item 3. Legal Proceedings, Chapter11 Proceedings.” The hearing before the Bankruptcy Court to consider theconfirmation of the Supplemental Plan is scheduled for March 21, 2007.Until our subsidiaries related to our New York business operations emerge frombankruptcy, we will not have access to the cash from operations generated fromthese subsidiaries. In 2006, our New York operations generated $17 million ofcash from operating activities.

On January 31, 2007,Mirant New York entered into an agreement for the sale of Mirant NY-Gen, whichowns the Hillburn and Shoemaker gas turbine facilities and the Swinging Bridge,Rio and Mongaup hydroelectric generating facilities. An auction processsupervised by the Bankruptcy Court is required before bankruptcy court approvalmay occur. The estimated sales price of $3 million is subject to adjustmentsfor working capital and certain dam remediation efforts that are ongoing at theSwinging Bridge facility. The transaction is expected to close in the secondquarter of 2007.

***We may be subjectto claims that were not discharged in the bankruptcy cases, which could have amaterial adverse effect on our results 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 bankruptcy filing in July 2003 wereresolved during our Chapter 11 proceedings. In addition, the BankruptcyCode provides that the confirmation of a plan of reorganization discharges adebtor from substantially all debts arising prior to confirmation and certaindebts arising afterwards. With a few exceptions, all claims that arose prior toour bankruptcy filing and before confirmation of the Plan in December 2005are (1) subject to compromise and/or treatment under the Plan or (2) discharged,in accordance with the Bankruptcy Code and terms of the Plan. Circumstances inwhich claims and other obligations that arose prior to our bankruptcy filingwere not discharged primarily relate to certain actions by governmental unitsunder police power authority, where we have agreed to preserve a claimant’sclaims, as well as, potentially, instances where a claimant had inadequatenotice of the bankruptcy filing. The ultimate resolution of such claims andother obligations may have a material adverse effect on our results ofoperations and profitability.

***We are currentlyinvolved in significant litigation that, if decided adversely to us, couldmaterially adversely affect our results of operations and profitability.***

We are currently involvedin various litigation matters, which are described in more detail in this Form 10-K.We intend to vigorously defend against those claims that we are unable tosettle, but the results of this litigation cannot be determined. Adverseoutcomes for us in this litigation could require significant expenditures by usand could have a material adverse effect on our results of operations andprofitability.

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

None.

36

----

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

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

**Operating Plants:**

| **Power Generation Business** | ** ** | **Location**          | ** ** | **Plant Type**           | ** ** | **Primary Fuel**     | ** ** | **Mirant’s  %  Leasehold/  Ownership  Interest(1)** | ** ** | **Total  MW(2)** | ** ** | **Net Equity  Interest/  Lease in  Total MW(2)** | ** ** | **2006  Capacity  Factor(3)** | ** ** |
|-----------------------------------------|------------|-----------------------|------------|-------------------------------|------------|---------------------------|------------|--------------------------------------------------------------------|------------|------------------|------------|-----------------------------------------------------------------|------------|-------------------------------|------------|
| **Continuing Operations**               |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            |       |                          |       |   |   |   |   |   |   |   |   |
| **Mid-Atlantic Region:**                |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            |       |                          |       |   |   |   |   |   |   |   |   |
| Chalk Point                             |       | Maryland              |       | Intermediate/Baseload/Peaking |       | Natural  Gas/Coal/Oil     |       |                                                               | 100        |             |       |                                                            | 2,429      |                          |       |   | 2,429 |   |   |   | 22 | % |   |
| Dickerson                               |       | Maryland              |       | Baseload/Peaking              |       | Natural  Gas/Coal/Oil     |       |                                                               | 100        |             |       |                                                            | 853        |                          |       |   | 853 |   |   |   | 42 | % |   |
| Morgantown                              |       | Maryland              |       | Baseload/Peaking              |       | Coal/Oil                  |       |                                                               | 100        |             |       |                                                            | 1,492      |                          |       |   | 1,492 |   |   |   | 58 | % |   |
| Potomac River                           |       | Virginia              |       | Intermediate/Baseload         |       | Coal                      |       |                                                               | 100        |             |       |                                                            | 482        |                          |       |   | 482 |   |   |   | 26 | % |   |
| Total Mid-Atlantic                      |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 5,256      |                          |       |   | 5,256 |   |   |   | 36 | % |   |
| **Northeast Region:**                   |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            |       |                          |       |   |   |   |   |   |   |   |   |
| Canal                                   |       | Massachusetts         |       | Intermediate                  |       | Natural  Gas/Oil          |       |                                                               | 100        |             |       |                                                            | 1,112      |                          |       |   | 1,112 |   |   |   | 17 | % |   |
| Kendall                                 |       | Massachusetts         |       | Baseload                      |       | Natural  Gas/Oil/Jet fuel |       |                                                               | 100        |             |       |                                                            | 256        |                          |       |   | 256 |   |   |   | 52 | % |   |
| Martha’s Vineyard                  |       | Massachusetts         |       | Peaking                       |       | Diesel                    |       |                                                               | 100        |             |       |                                                            | 14         |                          |       |   | 14 |   |   |   | 1 | % |   |
| Wyman                                   |       | Maine                 |       | Peaking                       |       | Fuel  Oil                 |       |                                                               | 1.4        |             |       |                                                            | 614        |                          |       |   | 9 |   |   |   | — |   |   |
| Total New England                       |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 1,996      |                          |       |   | 1,391 |   |   |   | 23 | % |   |
| Bowline                                 |       | New  York             |       | Intermediate/Peaking          |       | Natural  Gas/Oil          |       |                                                               | 100        |             |       |                                                            | 1,125      |                          |       |   | 1,125 |   |   |   | 2 | % |   |
| Hillburn                                |       | New  York             |       | Baseload/Peaking              |       | Natural  Gas/Jet Fuel     |       |                                                               | 100        |             |       |                                                            | 51         |                          |       |   | 51 |   |   |   | — |   |   |
| Lovett                                  |       | New  York             |       | Baseload/Peaking              |       | Natural  Gas/Coal/Oil     |       |                                                               | 100        |             |       |                                                            | 411        |                          |       |   | 411 |   |   |   | 44 | % |   |
| Mongaup                                 |       | New  York             |       | Intermediate/Peaking          |       | Hydro                     |       |                                                               | 100        |             |       |                                                            | 4          |                          |       |   | 4 |   |   |   | 23 | % |   |
| Rio                                     |       | New  York             |       | Intermediate/Peaking          |       | Hydro                     |       |                                                               | 100        |             |       |                                                            | 9          |                          |       |   | 9 |   |   |   | 34 | % |   |
| Shoemaker                               |       | New  York             |       | Peaking                       |       | Natural  Gas/Jet Fuel     |       |                                                               | 100        |             |       |                                                            | 44         |                          |       |   | 44 |   |   |   | 1 | % |   |
| Swinging Bridge                         |       | New  York             |       | Intermediate/Peaking          |       | Hydro                     |       |                                                               | 100        |             |       |                                                            | 12         |                          |       |   | 12 |   |   |   | 8 | % |   |
| Total New York                          |       |                  |       |                          |       |                      |       |                                                               | 100        |             |       |                                                            | 1,656      |                          |       |   | 1,656 |   |   |   | 13 | % |   |
| Total Northeast                         |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 3,652      |                          |       |   | 3,047 |   |   |   | 17 | % |   |
| **California:**                         |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            |       |                          |       |   |   |   |   |   |   |   |   |
| Contra Costa                            |       | California            |       | Intermediate                  |       | Natural  Gas              |       |                                                               | 100        |             |       |                                                            | 674        |                          |       |   | 674 |   |   |   | 2 | % |   |
| Pittsburg                               |       | California            |       | Intermediate                  |       | Natural  Gas              |       |                                                               | 100        |             |       |                                                            | 1,311      |                          |       |   | 1,311 |   |   |   | 4 | % |   |
| Potrero                                 |       | California            |       | Intermediate/Peaking          |       | Natural  Gas/Oil          |       |                                                               | 100        |             |       |                                                            | 362        |                          |       |   | 362 |   |   |   | 17 | % |   |
| Total California                        |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 2,347      |                          |       |   | 2,347 |   |   |   | 6 | % |   |
| **Total Continuing Operations**         |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 11,255     |                          |       |   | 10,650 |   |   |   |   |   |   |
| **Discontinued Operations**             |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            |       |                          |       |   |   |   |   |   |   |   |   |
| **Philippines:**                        |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            |       |                          |       |   |   |   |   |   |   |   |   |
| Sual                                    |       | Philippines           |       | Baseload                      |       | Coal                      |       |                                                               | 100        |             |       |                                                            | 1,218      |                          |       |   | 1,218 |   |   |   | 23 | % |   |
| Ilijan                                  |       | Philippines           |       | Baseload                      |       | Natural  Gas              |       |                                                               | 20         |             |       |                                                            | 1,251      |                          |       |   | 250 |   |   |   | — |   |   |
| Pagbilao                                |       | Philippines           |       | Baseload                      |       | Coal                      |       |                                                               | 100        |             |       |                                                            | 735        |                          |       |   | 735 |   |   |   | 49 | % |   |
| Total Philippines                       |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 3,204      |                          |       |   | 2,203 |   |   |   | 33 | % |   |
| **Caribbean:**                          |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            |       |                          |       |   |   |   |   |   |   |   |   |
| PowerGen(4)                             |       | Trinidad  and Tobago  |       | Intermediate/Peaking/Baseload |       | Natural  Gas              |       |                                                               | 39         |             |       |                                                            | 1,157      |                          |       |   | 451 |   |   |   | 55 | % |   |
| Jamaica Public Service Company Limited  |       | Jamaica               |       | Intermediate/Baseload/Peaking |       | Oil/Hydro                 |       |                                                               | 80         |             |       |                                                            | 603        |                          |       |   | 482 |   |   |   | 51 | % |   |
| Grand Bahama Power                      |       | Bahamas               |       | Peaking/Intermediate/Baseload |       | Oil                       |       |                                                               | 55.4       |             |       |                                                            | 151        |                          |       |   | 83 |   |   |   | 34 | % |   |
| CUC                                     |       | Netherlands  Antilles |       | Baseload/Peaking              |       | Pitch/Refinery  Gas       |       |                                                               | 25.5       |             |       |                                                            | 153        |                          |       |   | 34 |   |   |   | — |   |   |
| Total Caribbean                         |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 2,064      |                          |       |   | 1,050 |   |   |   | 52 | % |   |
| **U.S. Gas Assets:**                    |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            |       |                          |       |   |   |   |   |   |   |   |   |
| Zeeland                                 |       | Michigan              |       | Intermediate/Peaking          |       | Natural  Gas              |       |                                                               | 100        |             |       |                                                            | 903        |                          |       |   | 903 |   |   |   | 6 | % |   |
| West Georgia                            |       | Georgia               |       | Peaking                       |       | Natural  Gas/Oil          |       |                                                               | 100        |             |       |                                                            | 613        |                          |       |   | 613 |   |   |   | 3 | % |   |
| Sugar Creek                             |       | Indiana               |       | Peaking                       |       | Natural  Gas              |       |                                                               | 100        |             |       |                                                            | 561        |                          |       |   | 561 |   |   |   | 4 | % |   |
| Shady Hills                             |       | Florida               |       | Peaking                       |       | Natural  Gas              |       |                                                               | 100        |             |       |                                                            | 469        |                          |       |   | 469 |   |   |   | 8 | % |   |
| Bosque                                  |       | Texas                 |       | Baseload/Peaking              |       | Natural  Gas              |       |                                                               | 100        |             |       |                                                            | 546        |                          |       |   | 546 |   |   |   | 28 | % |   |
| Apex                                    |       | Nevada                |       | Intermediate                  |       | Natural  Gas              |       |                                                               | 100        |             |       |                                                            | 527        |                          |       |   | 527 |   |   |   | 39 | % |   |
| Total U.S. Gas Assets                   |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 3,619      |                          |       |   | 3,619 |   |   |   | 13 | % |   |
| **Total Discontinued Operations**       |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 8,887      |                          |       |   | 6,872 |   |   |   |   |   |   |
| **Total  Mirant**                       |       |                  |       |                          |       |                      |       |                                                               |       |             |       |                                                            | 20,142     |                          |       |   | 17,522 |   |   |   |   |   |   |

 

37

----

 

| **Distribution Business—Discontinued Operations** | ** ** | ** ** | ** ** | **Location** | ** ** | **Mirant’s %  Ownership  Interest** | ** ** | **Customers/  end-users** | ** ** |
|------------------------------------------------------------------|------------|------------|------------|--------------|------------|-----------------------------------------------|------------|---------------------------|------------|
| ** **                                                       | ** ** | ** ** | ** ** | ** **   | ** ** | **(in thousands)**                       | ** ** |
| Grand Bahama Power                                               |       | Bahamas    |       |         | 55.4       |                                          |       |                      | 19         |   |   |
| Jamaica Public Service  Company Limited                          |       | Jamaica    |       |         | 80.0       |                                          |       |                      | 571        |   |   |
| Total                                                            |       |       |       |         |       |                                          |       |                      | 590        |   |   |

----

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

(2)          MW amounts reflect netdependable capacity.

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

(4)          Inaddition, on December 6, 2005, PowerGen and T&TEC executed a 30-year208 MW power sales agreement. On February 23, 2006, PowerGen beganconstruction of an expansion at the Point Lisas generating facility andestimates a commercial operations date of March 2007.

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

38

----

**Item3.**                        *Legal Proceedings*

*Chapter 11 Proceedings*

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

As of December 31,2006, approximately 21 million of the shares of Mirant common stock to bedistributed under the Plan have not yet been distributed and have been reservedfor distribution with respect to claims that are disputed by the Mirant Debtorsand have not been resolved. A settlement entered into on May 30, 2006,among Pepco, Mirant, MC 2005, LLC f/k/a Mirant Corporation (“Old Mirant”), andvarious subsidiaries of Mirant, if approved by final order in the Chapter 11proceedings, would result in the distribution of up to 18 million of thereserved shares to Pepco, as described below in *PepcoLitigation*. Under the terms of the Plan, to the extent other suchunresolved claims are resolved now that we have emerged from bankruptcy, theclaimants will be paid from the reserved shares on the same basis as if they hadbeen paid when the Plan became effective. That means that their allowed claimswill receive the same pro rata distributions of Mirant common stock, cash, orboth common stock and cash as previously allowed claims in accordance with theterms of the Plan. To the extent the aggregate amount of the payouts determinedto be due with respect to such disputed claims ultimately exceeds the amount ofthe funded claim reserve, Mirant would have to issue additional shares ofcommon stock to address the shortfall, which would dilute existing Mirantshareholders, and Mirant and Mirant Americas Generation would have to payadditional cash amounts as necessary under the terms of the Plan to satisfysuch pre-petition claims. If we are required to issue additional shares ofcommon stock to satisfy unresolved claims, certain parties who under the Planreceived common stock and warrants also are entitled to receive additionalshares of common stock to avoid dilution of their distributions under the Plan.

Our subsidiaries relatedto our New York business operations, Mirant New York, Mirant Bowline, MirantLovett, Hudson Valley Gas and Mirant NY-Gen, remain in bankruptcy. Our Lovettand Bowline generation facilities in New York were subject to disputes withlocal tax authorities regarding property tax assessments that were not resolveduntil December 2006, as described below in *New York TaxProceedings*. Resolution of those tax disputes should allow MirantNew York, Mirant Bowline, and Hudson Valley Gas to emerge from bankruptcy in2007. On January 26, 2007, MirantNew York, Mirant Bowline, and Hudson Valley Gas (collectively the “Emerging NewYork Entities”) filed a Supplemental Joint Chapter 11 Plan of Reorganization ofthe Emerging New York Entities (the “Supplemental Plan”) with the BankruptcyCourt. The Supplemental Plan has two main components. First, theSupplemental Plan incorporates a settlement with the various New York taxjurisdictions that resolved the tax disputes related to the Lovett and Bowlinefacilities. Second, the Supplemental Plan provides unsecured creditors ofthe Emerging New York Entities with the same treatment afforded holders ofunsecured claims against Mirant Americas Generation and its subsidiaries underthe Plan. Such unsecured creditors of the Emerging New York Entities willreceive their**pro rata share of the pool of assetscreated under the Plan for the benefit of the unsecured creditors of MirantAmericas Generation and its subsidiaries. On January 26, 2007, theEmerging New York Entities also filed a motion with the Bankruptcy Court toestablish procedures to facilitate the consideration and confirmation of theSupplemental Plan. That motion requests, among other things, that theBankruptcy Court find that the Supplemental Plan does not alter in any respectfrom the Plan the treatment of the holders of unsecured claims against theEmerging New York Entities, and that all votes previously cast by such holdersin respect of the Plan (which votes accepted the Plan for the Emerging New YorkEntities by the requisite number and amount required by the Bankruptcy Code) 

39

----

should be deemed votes cast in respect of theSupplemental Plan. The hearing before the Bankruptcy Court to consider theconfirmation of the Supplemental Plan is scheduled for March 21, 2007.

On October 19, 2006,Mirant Lovett notified the New York Public Service Commission, the NYISO,Orange and Rockland and certain other affected transmission and distributioncompanies in New York of its intent to discontinue operation of units 3 and 5of the Lovett facility in April 2007. The discontinuance of operations atunit 5 is in accordance with the requirements of a June 11, 2003, ConsentDecree (the “2003 Consent Decree”) among Mirant Lovett, the State of New Yorkand the NYSDEC that requires Mirant Lovett to install certain environmentalcontrols on unit 5 of the Lovett facility or shut down that unit by April 30,2007. The 2003 Consent Decree imposes similar requirements with respect to unit4 that have to be met by April 30, 2008. Operations at unit 3 are beingdiscontinued because it is uneconomic to continue to run unit 3 if operationsat unit 5 are discontinued. Mirant Lovett is in discussions with the NYSDEC andthe New York State Office of the Attorney General regarding environmentalcontrols. If Mirant Lovett is able to agree with the New York Attorney General’soffice and the NYSDEC on alternative control technologies that would allow unit5 to remain in operation past April 30, 2007, then Mirant Lovett mayrescind the notice of its intent to discontinue operations at units 3 and 5.Until a resolution is reached on environmental controls that would permiteconomically feasible operation, Mirant Lovett will likely remain in Chapter11. Mirant NY-Gen, which owns hydroelectric facilities at Swinging Bridge, Rioand Mongaup, and small combustion turbine facilities at Hillburn and Shoemaker,is insolvent. Its expenses are being funded under a debtor-in-possessionfacility provided by Mirant Americas with the approval of, and under thesupervision of, the Bankruptcy Court. Mirant NY-Gen is proceeding with theimplementation of a remediation plan for the sinkhole discovered in May 2005in the dam at the Swinging Bridge facility. The status of the remediationeffort is discussed in “Other Contingencies” in Note 23 to the consolidatedfinancial statements.

On January 31, 2007,Mirant New York entered into an agreement for the sale of Mirant NY-Gen, whichowns the Hillburn and Shoemaker gas turbine facilities and the Swinging Bridge,Rio and Mongaup hydroelectric generating facilities. An auction processsupervised by the Bankruptcy Court is required before bankruptcy court approvalmay occur. The estimated sales price of $3 million is subject to adjustmentsfor working capital and certain dam remediation efforts that are ongoing at theSwinging Bridge facility. The transaction is expected to close in the secondquarter of 2007.

Until our subsidiariesrelated to our New York business operations emerge from bankruptcy, we will nothave access to the cash from operations generated from these subsidiaries. In2006, our New York operations generated $17 million of cash from operatingactivities.

*Pepco Litigation*

In 2000, Mirant purchasedpower generating facilities and other assets from Pepco, including certain PPAsbetween Pepco and third parties. Under the terms of the APSA, Mirant and Pepco entered into a contractualagreement (the “Back-to-Back Agreement”) with respect to certain PPAs,including Pepco’s long-term PPA with 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 Panda PPA runs until2021, and the Back-to-Back Agreement does not expire until all obligations havebeen performed under the Panda PPA. Under the Back-to-Back Agreement, Mirant isobligated to purchase power from Pepco at prices that typically are higher thanthe market prices for power.

*Pepco Contract Litigation.**  *On August 28, 2003, the Mirant Debtors filed amotion in the bankruptcy proceedings to reject the Back-to-Back Agreement (the “FirstRejection Motion”). If the Mirant Debtors succeed in rejecting the Back-to-BackAgreement, Mirant would have no further obligations with respect to thatagreement and Pepco would receive a claim in the bankruptcy proceedings for itsresulting 

40

----

damages. On December 9,2004, the United States District Court for the Northern District of Texas heldthat the Back-to-Back Agreement was a part of and not severable from, andtherefore could not be rejected apart from, the APSA. The Mirant Debtorsappealed that decision to the United States Court of Appeals for the FifthCircuit (the “Fifth Circuit”). On July 19, 2006, the Fifth Circuitaffirmed the district court’s December 9, 2004, decision, concluding thatthe APSA, the Back-to-Back Agreement and other agreements executed under theterms of the APSA constituted a single agreement and that the Back-to-BackAgreement could not be separately rejected.

On January 21, 2005,the Mirant Debtors filed a separate motion in the bankruptcy proceedings toreject the APSA, including the Back-to-Back Agreement but not including otheragreements entered into between Mirant and its subsidiaries and Pepco under theterms of the APSA (the “Second Rejection Motion”). On August 16, 2005, thedistrict court informally stayed the Second Rejection Motion pending rulings bythe Fifth Circuit on the Mirant Debtors’ appeals from the district court’s December 9,2004, decision denying the First Rejection Motion. On January 31, 2007,the district court terminated this proceeding based on the filing of theproposed settlement described below in Proposed Pepco Settlement.

On December 1, 2005,the Mirant Debtors filed a complaint with the Bankruptcy Court seeking torecharacterize the Back-to-Back Agreement as a debt obligation arising prior tothe filing of the Chapter 11 proceedings (the “RecharacterizationComplaint”). The complaint seeks the recovery of all payments made to Pepcounder the Back-to-Back Agreement since the filing of the Chapter 11proceedings. If the Mirant Debtors succeed on the Recharacterization Complaint,Pepco would receive a claim in the bankruptcy proceedings for the amount of anypayments recovered by the Mirant Debtors and for the amount owed under theBack-to-Back Agreement for its remaining term. The Recharacterization Complaintremains pending in the Bankruptcy Court.

Pending a finaldetermination of the Mirant Debtors’ ability to reject the APSA, theBack-to-Back Agreement, and certain other agreements with Pepco, and theresolution of the Recharacterization Complaint, the Plan provides that theMirant Debtors’ obligations under the APSA and the Back-to-Back Agreement areinterim obligations of Mirant Power Purchase and are unconditionally guaranteedby Mirant. If the Mirant Debtors succeed in rejecting or recharacterizing anyof these agreements, 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.Pepco’s damages claim would then be satisfied pursuant to the terms of thePlan. See *Chapter 11 Proceedings*above for furtherdiscussion of the treatment under the Plan of unresolved claims in the Chapter11 proceedings.

If the proposed settlementbetween Mirant and Pepco described below in *Proposed Pepco Settlement*is approved and becomes effective, it will result in the dismissal of allpending litigation between Mirant and Pepco related to the APSA and theBack-to-Back Agreement. Under the settlement, the APSA will be assumed andperformed by Mirant Power Purchase. The Back-to-Back Agreement will be rejectedand terminated as of May 31, 2006, allowing Mirant to avoid the expectedcost of the Back-to-Back Agreement through its stated expiration in 2021. Undercertain conditions described below in *Proposed Pepco Settlement*,however, the settlement allows Mirant to assume and continue to perform, ratherthan reject, the Back-to-Back Agreement, thereby reducing the claim received byPepco under the settlement and the amount that would have to be paid by Mirantto Pepco to satisfy that claim.

*Potential AdjustmentRelated to Panda Power Purchase Agreement.**  *At the time of the acquisition of the MirantMid-Atlantic assets from Pepco in December 2000, Mirant also entered intoan agreement with Pepco that, as subsequently modified, provided that the pricepaid by Mirant for those assets would be adjusted if by April 8, 2005, abinding court order had been entered finding that the Back-to-Back Agreementviolated the Panda PPA as a prohibited assignment, transfer or delegation ofthe Panda PPA or because it caused a prohibited delegation or transfer ofrights, duties or obligations under the Panda 

41

----

PPA that was notseverable from the rest of the Back-to-Back Agreement. Panda initiated legalproceedings in 2000 asserting that the Back-to-Back Agreement violatedprovisions in the Panda PPA prohibiting Pepco from assigning the Panda PPA ordelegating its duties under the Panda PPA to a third party without Panda’sprior written consent. On June 10, 2003, the Maryland Court of Appeals,Maryland’s highest court, ruled that the assignment of certain rights anddelegation of certain duties by Pepco to Mirant under the Back-to-BackAgreement did violate the non-assignment provision of the Panda PPA and wasunenforceable. The court, however, left open the issues whether the provisionsfound to violate the Panda PPA could be severed and the rest of theBack-to-Back Agreement enforced and whether Panda’s refusal to consent to theassignment of the Panda PPA by Pepco to Mirant was unreasonable and violatedthe Panda PPA. Our view is that the June 10, 2003, decision by theMaryland Court of Appeals does not suffice to trigger a purchase priceadjustment under the agreement between Mirant and Pepco. If that court orderwere found to have triggered the purchase price adjustment, the agreementbetween Mirant and Pepco provides that the amount of the adjustment would benegotiated in good faith by the parties or determined by binding arbitration soas to compensate Pepco for the termination of the benefit of the Back-to-BackAgreement while also holding Mirant economically indifferent from such court order.

If the proposed settlementbetween Mirant and Pepco described below in *Proposed Pepco Settlement*is approved and becomes effective, it would result in the termination of anypotential adjustment to the price paid by Mirant for its December 2000acquisition of the Pepco assets related to the Panda PPA with no amount being owed.

*Pepco Avoidance Action.**  *On July 13, 2005, Mirant and several of itssubsidiaries filed a lawsuit against Pepco before the Bankruptcy Courtasserting that Mirant did not receive fair value in return for the purchaseprice paid for the Pepco assets and that the acquisition occurred at a timewhen Mirant was either insolvent or was rendered insolvent as a result of thetransaction. The suit seeks damages for fraudulent transfer under 11 U.S.C. §§544 and 550 and applicable state law and disallowance of claims filed by Pepcoin the Chapter 11 proceedings. On November 3, 2005, the district courtgranted a motion filed by Pepco asking that the suit be heard by the districtcourt rather than the Bankruptcy Court. If the proposed settlementbetween Mirant and Pepco described below in *Proposed Pepco Settlement*is approved and becomes effective, it would result in the release by Mirant andits subsidiaries of all claims asserted against Pepco in the suit filed July 13,2005.

*Proposed Pepco Settlement.*   OnMay 30, 2006, Mirant, Mirant Power Purchase, Old Mirant, varioussubsidiaries of Mirant, and a trust established pursuant to the Plan to whichownership of Old Mirant and Mirant Americas Energy Marketing was transferred(collectively the “Mirant Settling Parties”) entered into a Settlement Agreementand Release (the “Settlement Agreement”) with Pepco and various affiliates ofPepco (collectively the “Pepco Settling Parties”). Once it becomes effective,the Settlement Agreement will fully resolve the contract rejection motions thatremain pending in the bankruptcy proceedings, as well as other matterscurrently disputed between Pepco and Mirant and its subsidiaries. The PepcoSettling Parties and the Mirant Settling Parties will release each other fromall claims known as of May 30, 2006, including the fraudulent transferclaims brought by Old Mirant and several of its subsidiaries against Pepco in July 2005that are described above in *Pepco Avoidance Action*.The Settlement Agreement will become effective once it has been approved by theBankruptcy Court and that approval order has become a final order no longersubject to appeal. On August 9, 2006, the Bankruptcy Court entered anorder approving the Settlement Agreement, but certain holders of unsecuredclaims against Old Mirant in the bankruptcy proceedings appealed that order. OnDecember 26, 2006, the district court affirmed the bankruptcy court orderapproving the settlement, but the claims holders have appealed that ruling tothe Fifth Circuit, and the approval order has not yet become a final order.

Under the SettlementAgreement, Mirant Power Purchase will perform any remaining obligations underthe APSA, and Mirant will guaranty its performance. The Back-to-Back Agreementwill be rejected and terminated effective as of May 31, 2006, unless Mirantexercises an option given to it under the 

42

----

SettlementAgreement to have the Back-to-Back Agreement assumed under certain conditions.If the closing price of Mirant’s stock is less than $16.00 on four businessdays in a 20 consecutive business day period prior to any distribution ofshares to Pepco on its claim, then Mirant can elect to have the Back-to-BackAgreement assumed and assigned to Mirant Power Purchase rather than rejectingit, and the claim received by Pepco will be reduced as described below.

The Settlement Agreementgrants Pepco a claim against Old Mirant in Old Mirant’s bankruptcy proceedingsthat will result in Pepco receiving common stock of Mirant and cash having avalue, after liquidation of the stock by Pepco, equal to $520 million, subjectto certain adjustments. Upon the Settlement Agreement becoming effective,Mirant will distribute up to 18 million shares of Mirant common stock to Pepcoto satisfy its claim and Pepco will liquidate those shares. The shares to bedistributed to Pepco will be determined by Mirant after the SettlementAgreement becomes effective so as to produce upon liquidation total netproceeds as near to $520 million as possible, subject to the overall cap on theshares to be distributed of 18 million shares. If the net proceeds received byPepco from the liquidation of the shares are less than $520 million, Mirantwill pay Pepco cash equal to the difference. If Mirant exercises the option tohave the Back-to-Back Agreement assumed, then the $520 million is reduced to$70 million, Mirant Power Purchase would continue to perform the Back-to-BackAgreement through its expiration in 2021, and Mirant would guarantee itsperformance. The Settlement Agreement allocates the $70 million to variousclaims asserted by Pepco that do not arise from the rejection of theBack-to-Back Agreement, including claims asserted under the Local Area SupportAgreement between Pepco and Mirant Potomac River that are discussed in “PepcoAssertion of Breach of Local Area Support Agreement” in Note 23 to theconsolidated financial statements.

While the appeal filedfrom the Bankruptcy Court’s August 9, 2006, order approving the SettlementAgreement is pending, the parties will continue to perform their obligationsunder the Back-to-Back Agreement until the appeal is resolved and the approvalorder has become a final order. Unless the Back-to-Back Agreement is assumed,Pepco will refund to Mirant Power Purchase all payments received under theBack-to-Back Agreement for energy, capacity or other services delivered after May 31,2006, through the date the Settlement Agreement becomes effective. The appealof the approval order also resulted in Mirant paying Pepco $70 million. The $70million will be repaid to Mirant when a final order is entered either affirmingthe approval order, which would cause the Settlement Agreement to becomeeffective, or determining that the Settlement Agreement cannot be approved.

Upon the finaldistribution of the shares to Pepco, we expect to recognize a gain as a result ofthe rejection of the Back-to-Back Agreement. The amount of the gain willreflect the recorded price risk management liabilities for the Back-to-BackAgreement in the consolidated balance sheet at that date reduced by the amountof cash required to be paid by us in order for Pepco to receive the $520million required under the Settlement Agreement. The closing price of our stockas of December 31, 2006, was $31.57 and the net proceeds at that pricewould have been sufficient to provide the $520 million to Pepco. As of December 31,2006, the fair value of the Back-to-Back Agreement recorded in price riskmanagement liabilities in our consolidated balance sheet totaled $425 million,of which $36 million is classified as current. Thus, the amount of the estimatedcontingent gain is approximately $445 million at December 31, 2006,including estimated refunds of $20 million for payments to Pepco under theBack-to-Back Agreement for periods since May 31, 2006. Until the finaldistribution of the shares to Pepco, the amount of the estimated gain isaffected by changes in the fair value of the Back-to-Back Agreement, the numberof common shares distributed to Pepco and the proceeds received by Pepco fromits liquidation of the common shares.

*Shareholder-Bondholder Litigation*

*Mirant SecuritiesConsolidated Action.**  *Twentylawsuits filed in 2002 against Mirant and four of its officers have beenconsolidated into a single action, In re Mirant Corporation SecuritiesLitigation, before 

43

----

the United StatesDistrict Court for the Northern District of Georgia. In their originalcomplaints, the plaintiffs allege, among other things, that the defendantsviolated federal securities laws by making material misrepresentations andomissions to the investing public regarding Mirant’s business operations andfuture prospects during the period from January 19, 2001, through May 6,2002, due to potential liabilities arising out of its activities in Californiaduring 2000 and 2001. The plaintiffs seek unspecified damages, includingcompensatory damages, and the recovery of reasonable attorneys’ fees and costs.

In November 2002, theplaintiffs filed an amended complaint that added as defendants The SouthernCompany (“Southern”), the directors of Mirant immediately prior to its initialpublic offering of stock and various firms that were underwriters for theinitial public offering by us. In addition to the claims set out in theoriginal complaint, the amended complaint asserts claims under the SecuritiesAct, alleging that the registration statement and prospectus for the initialpublic offering in 2000 of Mirant’s old common stock terminated under the Planmisrepresented and omitted material facts. On July 14, 2003, the districtcourt dismissed the claims asserted by the plaintiffs based on our Californiabusiness activities but allowed the case to proceed on the plaintiffs’ otherclaims. On March 24, 2006, the plaintiffs filed a motion forreconsideration of that ruling, which motion remains pending. On December 11,2003, the plaintiffs filed a proof of claim against Mirant in the Chapter 11proceedings, but they subsequently withdrew their claim in October 2004.On August 29, 2005, the district court, at the request of the plaintiffs,dismissed Mirant as a defendant in this action.

A master separationagreement between Mirant and Southern entered into in conjunction with Mirant’sspin-off from Southern in 2001 obligates Mirant to indemnify Southern for anylosses arising out of any acts or omissions by Mirant and its subsidiaries inthe conduct of the business of Mirant and its subsidiaries. Mirant has filed toreject the separation agreement in the Chapter 11 proceedings. Any damagesdetermined to be owed to Southern arising from the rejection of the separationagreement will be addressed as a claim in the Chapter 11 proceedings under theterms of the Plan. The underwriting agreements between Mirant and the variousfirms added as defendants that were underwriters for the initial publicoffering by the Company in 2000 also provide for Mirant to indemnify such firmsagainst any losses arising out of any acts or omissions by Mirant and itssubsidiaries. The underwriters filed a claim against Mirant in the Chapter 11proceedings that was subordinated to claims of Mirant’s creditors andextinguished under the Plan.

*U.S. Government Inquiries*

*Department of JusticeInquiries.**  *In November 2002,we received a subpoena from the DOJ, acting through the United States Attorney’soffice for the Northern District of California, requesting information aboutour activities and those of our subsidiaries for the period since January 1,1998.The subpoena requested information related to the California energymarkets and other topics, including the reporting of inaccurate information totrade publications that publish natural gas or electricity spot price data. Thesubpoena was issued as part of a grand jury investigation. The DOJ’sinvestigation is based upon the same circumstances that were the subject of aninvestigation by the CFTC that was settled in December 2004, as described****in our Annual Report on Form 10-K for the yearended December 31, 2004, in*Legal Proceedings—OtherGovernmental Proceedings—CFTC Inquiry*. On June 19, 2006, twoformer employees pled guilty to charges of conspiracy to manipulate the priceof natural gas in interstate commerce during the period from July 1, 2000,until November 1, 2000, while they were west region traders for MirantAmericas Energy Marketing. We are discussing the disposition of this matterwith the DOJ. If we are unable to reach a consensual resolution with the DOJ,it is possible that the DOJ could seek indictments against one or more Mirantentities for alleged violations of the Commodity Exchange Act. A consensualresolution of this matter could involve a deferred prosecution agreement andpayment of a fine or penalty. Our current assessment is that the amount of anysuch fine or penalty would not exceed amounts previously accrued.

44

----

*Environmental Matters*

*EPA Information Request.**  *InJanuary 2001, the EPA issued a request for information to Mirantconcerning the implications under the EPA’s NSR regulations promulgated underthe Clean Air Act of past repair and maintenance activities at the PotomacRiver plant in Virginia and the Chalk Point, Dickerson and Morgantown plants inMaryland. The requested information concerns the period of operations thatpredates our subsidiaries’ ownership and lease of those plants. Mirantresponded fully to this request. Under the APSA, Pepco is responsible for finesand penalties arising from any violation associated with operations prior toour subsidiaries’ acquisition or lease of the plants. If a violation isdetermined to have occurred at any of the plants, our subsidiary owning orleasing the plant may be responsible for the cost of purchasing and installingemissions control equipment, the cost of which may be material. Oursubsidiaries owning or leasing the Chalk Point, Dickerson and Morgantown plantsin Maryland will be installing a variety of emissions control equipment onthose plants to comply with the Maryland Healthy Air Act, but that equipmentwill not include all of the emissions control equipment that could be requiredif a violation of the EPA’s NSR regulations is determined to have occurred atone or more of those plants. If such a violation is determined to have occurredafter our subsidiaries acquired or leased the plants or, if occurring prior tothe acquisition or lease, is determined to constitute a continuing violation,our subsidiary owning or leasing the plant at issue could also be subject tofines and penalties by the state or federal government for the period after itsacquisition or lease of the plant, the cost of which may be material, althoughapplicable bankruptcy law may bar such liability for periods prior to January 3,2006, when the Plan became effective for us and our subsidiaries that own orlease these plants.

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

On September 27,2004, Mirant Potomac River, Mirant Mid-Atlantic, the Virginia DEQ, the MDE, theDOJ and the EPA entered into, and filed for approval with the United StatesDistrict Court for the Eastern District of Virginia, a proposed consent decree(the “Original Consent Decree”) that, if approved, would have resolved MirantPotomac River’s potential liability for matters addressed in the NOVspreviously issued by the Virginia DEQ and the EPA. The Original Consent Decreewould have required Mirant Potomac River and Mirant Mid-Atlantic to (1) installpollution control equipment at the Potomac River plant in Virginia and at theMorgantown plant in Maryland leased by Mirant Mid-Atlantic, (2) complywith declining system-wide ozone season NOx emissions caps from 2004 through2010, (3) comply with system-wide annual NOx emissions caps starting in2004, (4) meet seasonal system average emissions rate targets in 2008 and (5) paycivil penalties and perform supplemental environmental projects in and aroundthe Potomac River plant expected to achieve additional environmental benefits.Except for the installation of the controls planned for the Potomac River unitsand the installation of selective catalytic reduction (“SCR”) or equivalenttechnology at Mirant Mid-Atlantic’s Morgantown units 1 and 2 in 2007 and 2008,the Original Consent Decree would not have obligated our subsidiaries toinstall specifically designated technology, but rather to reduce emissionssufficiently to meet the various NOx caps. Moreover, as to the requiredinstallations of SCRs at Morgantown, Mirant Mid-Atlantic may choose not toinstall the technology by the applicable deadlines and leave the units offeither permanently or until such time as the SCRs are installed. The OriginalConsent Decree was subject to the approval of the district court and the BankruptcyCourt. As described below, the Original Consent Decree was not 

45

----

approved and the parties have filed an amended proposedconsent decree that supersedes the Original Consent Decree.

On July 22,2005, the district court granted a motion filed by the City of Alexandriaseeking to intervene in the district court action, although the district courtimposed certain limitations on the City of Alexandria’s participation in theproceedings. On September 23, 2005, the City of Alexandria filed a motionseeking authority to file an amended complaint in the action seeking injunctiverelief and civil penalties under the Clean Air Act for alleged violations byMirant Potomac River of its Virginia Stationary Source Permit to Operate andthe State of Virginia’s State Implementation Plan. Based upon a computermodeling described below in *Mirant Potomac RiverDownwash Study*, the City of Alexandria asserted that emissions fromthe Potomac River plant cause or contribute to exceedances of NAAQS for SO2,NO2 and particulate matter. The City of Alexandria also contended based on itsmodeling analysis that the plant’s emissions of hydrogen chloride and hydrogenfluoride exceed Virginia state standards. Mirant Potomac River disputes theCity of Alexandria’s allegations that it has violated the Clean Air Act andVirginia law. On December 2, 2005, the district court denied the City ofAlexandria’s motion seeking to file an amended complaint.

Inearly May 2006, the parties to the Original Consent Decree and MirantChalk Point entered into and filed for approval with the United States DistrictCourt for the Eastern District of Virginia an amended consent decree (the “AmendedConsent Decree”) that, if approved, will resolve Mirant Potomac River’spotential liability for matters addressed in the NOVs previously issued by theVirginia DEQ and the EPA. The Amended Consent Decree includes the requirementsthat were to be imposed under the terms of the Original Consent Decree asdescribed above. It also defines the rights and remedies of the parties in theevent of a rejection in bankruptcy or other termination of any of the long-termleases under which Mirant Mid-Atlantic leases the coal units at the Dickersonand Morgantown plants. The Amended Consent Decree provides that ifMirant Mid-Atlantic rejects or otherwise loses one or more of its leaseholdinterests in the Morgantown and Dickerson plants and ceases to operate one orboth of the plants, Mirant Mid-Atlantic, Mirant Chalk Point and/or MirantPotomac will (i) provide the EPA, Virginia DEQ and the MDE with thewritten agreement of the new owner or operator of the affected plant or plantsto be bound by the obligations of the Amended Consent Decree and (ii) wherethe affected plant is the Morgantown plant, offer to any and all prospective ownersand/or operators of the Morgantown plant to pay for completion of engineering,construction and installation of the SCRs required by the Amended ConsentDecree. If the new owner or operator of the affected plant or plants does notagree to be bound by the obligations of the Amended Consent Decree, it requiresMirant Mid-Atlantic, Mirant Chalk Point and/or Mirant Potomac to install analternative suite of environmental controls at the plants they continue to own.The district court and the Bankruptcy Courtmust approve the Amended Consent Decree for it to become effective. The City ofAlexandria and certain individuals and organizations have opposed entry of theAmended Consent Order. The Bankruptcy Court approved the Amended Consent Decreeon June 1, 2006. The district court has not yet approved the AmendedConsent Decree.

On April 26, 2006,Mirant Mid-Atlantic and the MDE entered into an agreement to allow MirantMid-Atlantic to implement the consent decree with respect to the Morgantownplant, if the consent decree receives the necessary approvals. Under theagreement, Mirant Mid-Atlantic agreed to certain ammonia and particulate matteremissions limits and to submit testing results to the MDE.

*Mirant Potomac RiverDownwash Study.**  *On September 23,2004, the Virginia DEQ and Mirant Potomac River entered into an order byconsent with respect to the Potomac River plant under which Mirant PotomacRiver agreed to perform a modeling analysis to assess the potential effect of “downwash”from the plant (1) on ambient concentrations of SO2, NO2, CO and PM10 forcomparison to the applicable NAAQS and (2) on ambient concentrations ofmercury for comparison to Virginia Standards of Performance for ToxicPollutants. Downwash is the effect that occurs when aerodynamic turbulence 

46

----

induced by nearbystructures causes emissions from an elevated source, such as a smokestack, tomove rapidly toward the ground resulting in higher ground-level concentrationsof emissions.

The computer modelinganalysis predicted that emissions from the Potomac River plant have thepotential to contribute to localized, modeled instances of exceedances of theNAAQS for SO2, NO2 and PM10 under certain conditions. Based on those results,the Virginia DEQ issued a directive to Mirant Potomac River on August 19,2005, to undertake immediately such action as was necessary to ensureprotection of human health and the environment and eliminate NAAQS violations.On August 24, 2005, power production at all five units of the Potomac Rivergenerating facility was temporarily halted in response to the directive fromthe Virginia DEQ. On August 25, 2005,the District of Columbia Public Service Commission filed an emergency petitionand complaint with the FERC and the DOE to prevent the shutdown of the PotomacRiver facility. The matter remains pending before the FERC and the DOE. On December 20,2005, due to a determination by the DOE that an emergency situation existedwith respect to the reliability of the supply of electricity to centralWashington, D.C., the DOE ordered Mirant Potomac River to generate electricityat the Potomac River generating 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 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 without contributingto any NAAQS exceedances. The DOE required Mirant Potomac River to submit aplan, on or before December 30, 2005, that met these requirements. Theorder further provides that Mirant Potomac River and its customers should agreeto mutually 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 consideringfurther the rehearing requests. 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 operationof the units of the Potomac River generating facility on a reduced basis, butmaking it possible to bring the entire plant into service within approximately28 hours when necessary for reliability purposes. The DOE’s order expires July 1,2007, but Mirant Potomac River expects it will be able to continue to operatethese units after that expiration.

In aletter received December 30, 2005, the EPA invited Mirant Potomac Riverand the Virginia DEQ to work with the EPA to ensure that Mirant Potomac River’soperating plan submitted to the DOE adequately addressed NAAQS issues. The EPAalso asserted in its letter that Mirant Potomac River did not immediatelyundertake action as directed by the Virginia DEQ’s August 19, 2005, letterand failed to comply with the requirements of the Virginia State ImplementationPlan established by that letter. Mirant Potomac River received a second letterfrom the EPA on December 30, 2005, requiring Mirant to provide certainrequested information as part of an EPA investigation to determine the CleanAir Act compliance status of the Potomac River generating facility.

On June 1, 2006,Mirant Potomac River and the EPA executed an ACO by Consent to resolve the EPA’sallegations that Mirant Potomac River violated the Clean Air Act by notimmediately shutting down all units at the Potomac River facility upon receiptof the Virginia DEQ’s August 19, 2005, letter and to assure an acceptablelevel of reliability to the District of Columbia. The ACO (i) specifiescertain operating scenarios and SO2 emissions limits for the Potomac Riverfacility, which scenarios and limits take into account whether one or both ofthe 230kV transmission lines serving Washington, D.C. are out of service; (ii) requiresthe operation of trona injection units to reduce SO2 emissions; and (iii) requiresMirant Potomac River to undertake a model evaluation study to predict ambientair quality impacts from the facility’s operations. In accordance with thespecified operating scenarios, the ACO permits the facility to operate using adaily predictive modeling protocol. This protocol allows Mirant Potomac Riverto schedule the facility’s level of operations based on whether computermodeling predicts a NAAQS 

47

----

exceedance,based on weather and certain operating parameters. On June 2, 2006, theDOE issued a letter modifying its January 6, 2006, order to direct MirantPotomac River to comply with the ACO in order to ensure adequate electricreliability to the District of Columbia. Mirant Potomac River is operating thePotomac River facility in accordance with the ACO and has been able to operateall five units of the facility most of the time under the ACO.

*City of AlexandriaNuisance Suit.**  *On October 7,2005, the City of Alexandria filed a suit against Mirant Potomac River andMirant Mid-Atlantic in the Circuit Court for the City of Alexandria. The suitasserted nuisance claims, alleging that the Potomac River plant’s emissions ofcoal dust, flyash, NOx, SO2, particulate matter, hydrogen chloride, hydrogenfluoride, mercury and oil pose a health risk to the surrounding community andharm property owned by the City. The City sought injunctive relief, damages andattorneys’ fees. On February 17, 2006, the City amended its complaint toadd additional allegations in support of its nuisance claims relating to noiseand lighting, interruption of traffic flow by trains delivering coal to thePotomac River plant, particulate matter from the transport and storage of coaland flyash, and potential coal leachate into the soil and groundwater from thecoal pile. On December 13, 2006, the City withdrew the suit.

*Suit Regarding Chalk PointEmissions.**  *Byletter dated June 15, 2006, four environmental advocacy organizations—EnvironmentalIntegrity Project, Chesapeake Climate Action Network, Patuxent Riverkeeper andEnvironment Maryland Research and Policy Center—notified Mirant and MirantMid-Atlantic that they intended to file suit alleging that Mirant Chalk Pointhad violated the opacity limits set by the permits for Chalk Point unit 3 andunit 4 during thousands of six minute time intervals between January 2002and March 2006. The letter indicated that the organizations intend to filesuit to enjoin the violations alleged, to obtain civil penalties for pastnoncompliance to the extent that liability for these violations was notdischarged by the bankruptcy of Mirant Chalk Point, and to recover attorneys’fees. On August 3, 2006, Mirant, Mirant Mid-Atlantic, and Mirant ChalkPoint filed a complaint in the Bankruptcy Court seeking an injunction barringthe four organizations from filing suit as threatened in the June 15,2006, notice on the grounds that the notice and any claim for civil penaltiesor other monetary relief for alleged violations occurring before January 3,2006, violated the discharge of claims and causes of action granted MirantChalk Point under the Plan. On August 14, 2006, the Bankruptcy Courtentered an order agreed to by the parties enjoining the four organizations fromseeking monetary damages for any alleged violations occurring on or before January 3,2006. As part of that order, the organizations agreed not to file a complaintinitiating litigation concerning the alleged violations until August 30,2006.

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

On August 30, 2006,the four environmental organizations filed suit in the United States DistrictCourt for the District of Maryland against Mirant, Mirant Mid-Atlantic, andMirant Chalk Point asserting that emissions from Chalk Point units 3 and 4 hadviolated opacity limits set under the Clean Air Act and state law on numerousoccasions since January 4, 2006. The plaintiffs sought an injunctionprohibiting further violations by Chalk Point units 3 and 4 of the Clean AirAct, civil penalties of up to $32,500 for each violation of the Clean Air Act,additional civil penalties for mitigation projects, and attorneys’ fees. On September 22,2006, the Mirant defendants filed a motion to dismiss, arguing that under theClean Air 

48

----

Act theMDE’s prosecution of the same alleged violations in the Maryland state courtproceeding and their resolution through the Consent Decree barred theplaintiffs’ suit. On January 3, 2007, the district court granted themotion and dismissed the complaint, and that order has become final.

*Morgantown ParticulateEmissions NOV.**  *On March 3, 2006, Mirant Mid-Atlanticreceived a notice sent on behalf of the MDE alleging that violations ofparticulate matter emissions limits applicable to unit 1 at the Morgantown plant occurred on nineteendays in June and July 2005. The notice advises that the potentialcivil penalty is up to $25,000 per day for each day that unit 1 exceeded theapplicable particulate matter limit. The letter further advises that the MDEhas asked the Maryland Attorney General to file a civil suit under Maryland lawbased upon the alleged violations.

*Morgantown SO2 Exceedances.**  *Mirant Mid-Atlantic received an NOVdated March 8, 2006, asserting that on three days in June 2005 and January 2006,the Morgantown facility exceeded SO2 emissions limitations specified in its airpermit. The NOV indicates that on two of those days the SO2 emissionslimitation was exceeded by two different units of the Morgantown facility eachday. The NOV did not seek a specific penalty amount but noted that theviolations identified could subject Mirant Mid-Atlantic to a civil penalty ofup to $25,000 per day.

*Morgantown EmissionsObservation NOV.**  *OnJune 30, 2006, the MDE issued an NOV to Mirant Mid-Atlantic indicatingthat it had failed to comply with the air permit for the Morgantown facility byoperating the combustion turbines at the facility for more than 168 hourswithout performing an EPA Reference Method 9 observation of stack emissions foran 18-minute period. The NOV did not seek a specific penalty amount butnoted that the violation identified could subject Mirant Mid-Atlantic to acivil penalty of up to $25,000 per day.

*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 failed 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 in violation of Mirant Lovett’s water discharge permit issuedby the State of New York. The plaintiff requests the court to enjoin MirantLovett from 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 attorneys’ fees. On April 20,2005, the district court approved a stipulation agreed to by the plaintiff andMirant Lovett that stays the suit until 60 days after entry of an order by theBankruptcy Court confirming a plan of reorganization for Mirant Lovett becomesfinal and non-appealable.

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

*City of Alexandria Zoning Action*

On December 18, 2004, theCity Council for the City of Alexandria, Virginia (the “City Council”) adoptedcertain zoning ordinance amendments recommended by the City Planning Commissionthat resulted in the zoning status of Mirant Potomac River’s generating plantbeing changed from “noncomplying use” to “nonconforming use subject toabatement.” Under the nonconforming use status, 

49

----

unlessMirant Potomac River applies for and is granted a special use permit for theplant during the seven-year abatement period, the operation of the plant mustbe terminated within a seven-year period, and no alterations that directlyprolong the life of the plant will be permitted during the seven-year period. IfMirant Potomac River were to apply for and receive a special use permit for theplant, the City Council would likely impose various conditions and stipulationsas to the permitted use of the plant and seek to limit the period for which itcould continue to operate.

At its December 18,2004, meeting, the City Council also approved revocation of two special usepermits issued in 1989 (the “1989 SUPs”), one applicable to the administrativeoffice space at Mirant Potomac River’s plant and the other for the plant’stransportation management plan. Under the terms of the approved action, therevocation of the 1989 SUPs was to take effect 120 days after the City Council’saction, 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 Mirant Mid-Atlantic filed a complaint against the Cityof Alexandria and the City Council in the Circuit Court for the City ofAlexandria. The complaint sought to overturn the actions taken by the CityCouncil on December 18, 2004, changing the zoning status of Mirant PotomacRiver’s generating plant and approving revocation of the 1989 SUPs, on the groundsthat those actions violated federal, state and city laws. The complaintasserted, among other things, that the actions taken by the City Councilconstituted unlawful spot zoning, were arbitrary and capricious, constituted anunlawful attempt by the City Council to regulate emissions from the plant, andviolated Mirant Potomac River’s due process rights. Mirant Potomac River andMirant Mid-Atlantic requested the court to enjoin the City of Alexandria andthe City Council from taking any enforcement action against Mirant PotomacRiver or from requiring it to obtain a special use permit for the continuedoperation of its generating plant. On January 18, 2006, the court issued anoral ruling following a trial that the City of Alexandria acted unreasonablyand arbitrarily in changing the zoning status of Mirant Potomac River’sgenerating plant 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 City Council’srevocation of the 1989 SUPs. The City of Alexandria filed a petition with theVirginia Supreme Court seeking to appeal this judgment, and on September 11,2006, the Virginia Supreme Court agreed to hear the appeal.

*New York Tax Proceedings*

Mirant New York, MirantBowline, Mirant Lovett, and Hudson Valley Gas (collectively with Mirant NewYork, Mirant Bowline, and Mirant Lovett, the “New York Companies”) were thepetitioners in various proceedings (“Tax Certiorari Proceedings”) initiallybrought in the New York state courts challenging the assessed values determinedby local taxing authorities for the Bowline and Lovett generating facilitiesand a natural gas pipeline (the “HVG Property”) owned by Hudson Valley Gas.Mirant Bowline had challenged the assessed value of the Bowline generatingfacility and the resulting local tax assessments for tax years 1995 through2006. Mirant Bowline succeeded to rights held by Orange & Rockland forthe tax years prior to its acquisition of the Bowline Plant in 1999 under itsagreement with Orange & Rockland for the purchase of that plant.Mirant Lovett had challenged the assessed value of the Lovett facility for eachof the years 2000 through 2006. Hudson Valley Gas had challenged the assessedvalue of the HVG Property for each of the years 2004 through 2006.

50

----

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

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

On December 13, 2006,we and the New York Companies entered into a settlement agreement (the “SettlementAgreement”) with the Town of Haverstraw (“Haverstraw”), the Town of Stony Point(“Stony Point”), the Haverstraw-Stony Point Central School District (the “SchoolDistrict”), the County of Rockland (the “County”), the Village of Haverstraw (“HaverstrawVillage”), and the Village of West Haverstraw (“West Haverstraw Village” andcollectively with Haverstraw, Stony Point, the School District, the County, andHaverstraw Village, the “Tax Jurisdictions”). The Settlement Agreement wasapproved by the Bankruptcy Court on December 14, 2006, and resolved allpending disputes regarding real property taxes between the New York Companiesand the Tax Jurisdictions. Under the agreement, the New York Companies acceptedthe determinations of assessed value for the Bowline Facility for 1995 through2003 and the Lovett Facility for 2000 through 2003 made by the New York statecourt in its rulings in the Tax Certiorari Proceedings issued in August 2006.The New York Companies and the Tax Jurisdictions agreed to adopt the New Yorkstate court’s assessed values for the Bowline Facility and the Lovett Facilityfor 2003 as the assessed values for each facility for 2004 through 2006. Theparties agreed that the assessed values for the HVG Property for 2004 through2006 should be the values determined previously by Haverstraw. The TaxJurisdictions agreed to cancel penalties on the unpaid taxes owed by the NewYork Companies and to collect interest on those taxes at a rate of 8% per yearfor Mirant Bowline and Mirant Lovett and 12% per year for Hudson Valley Gas.Overall, the New York Companies under the settlement received total refunds of$163 million from the Tax Jurisdictions and paid unpaid taxes to the TaxJurisdictions of $115 million, resulting in the New York Companies receiving anet cash payment in the amount of $48 million. The refunds and unpaid taxeswere paid in early February 2007, and the New York Companies and the TaxJurisdictions are in the process of dismissing all pending litigation relatedto the refunds and the unpaid taxes.

The $163 million of totalrefunds received by the New York Companies was recognized as a gain in thefinancial statements in the fourth quarter of 2006. In addition, the New YorkCompanies had previously accrued a liability based upon the unpaid taxes asbilled by the Tax Jurisdictions. Due to the reductions of the unpaid taxes thatoccurred pursuant to the terms of the Settlement Agreement, the New YorkCompanies also recognized in the fourth quarter of 2006 a reduction ofoperating expenses of approximately $23 million related to 2006 and a gain ofapproximately $71 million related to prior periods.

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

None.

51

----

**PART II**

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

**Common Stock**

Pursuant to the Plan, all shares of old Mirant’scommon stock were cancelled on January 3, 2006, and 276,500,000 sharesof New Mirant common stock were distributed to holders of unsecured claims andequity securities. In addition, we reserved 23,500,000 shares forunresolved claims, of which 21,113,104 have not yet been distributed as of December 31,2006. New Mirant also issued two series of warrants, expiring January 3,2011, that entitle their holders to initially purchase an aggregate of52,941,177 shares of common stock. The Series A and Series Bwarrants entitle the holders to purchase an aggregate of 35,294,118 and 17,647,059 sharesof common stock, respectively. The exercise price of the Series A and Series Bwarrants is $21.87 and $20.54 per share, respectively. On December 31,2006, there were 35,205,678 Series A warrants and 17,635,897 Series Bwarrants yet to be exercised. New Mirant is authorized to issue1,500,000,000 shares of common stock having a par value of $.01 per shareand 100,000,000 shares of preferred stock having a par value of $.01 pershare.

All of the New Mirant common stock was issued pursuantto the Plan in accordance with Section 1145 of the Bankruptcy Code, and wereceived no proceeds from such issuance. The issuance of New Mirant shares ofcommon stock was exempt from the registration requirements of the SecuritiesAct, as amended, and equivalent provisions of state securities laws, inreliance upon Section 1145(a) of the Bankruptcy Code.

Our common stock iscurrently traded on the NYSE under the ticker symbol “MIR”. The closing priceof our stock on December 31, 2006, was $31.57. The following table setsforth the high and low sales prices for our common stock as reported by theNYSE for the periods indicated.

**Price Range of Common Stock**

| **Quarter** | ** ** | ** ** | ** ** | **High** | ** ** | **Low** | ** ** |
|-------------|------------|------------|------------|----------|------------|---------|------------|
| First       |       | $          | 29.00      |     | $          | 23.93   |       |
| Second      |       | $          | 26.86      |     | $          | 23.36   |       |
| Third       |       | $          | 29.59      |     | $          | 26.02   |       |
| Fourth      |       | $          | 32.61      |     | $          | 25.10   |       |

 

**Holders**

As of February 21,2007, there were approximately 88,592 record holders of our common stock, parvalue $.01 per share.

**Dividends**

We will retain any futureearnings to fund our operations and meet our cash and liquidity needs. We havenot paid or declared any cash dividends on our common stock in the last twofiscal years and we do not anticipate paying any quarterly cash dividends inthe foreseeable future.

52

----

**Share Repurchases**

Thefollowing table sets forth information regarding repurchases by us of ourcommon shares on the NYSE during the three-month period ended December 31,2006:

| **Period**                     | ** ** | ** **             | ** ** | **Shares  repurchased** | ** ** | **Average  price paid  per share** | ** ** | **Total number of  shares purchased  as part of publicly  announced plans** | ** ** | **Approximate dollar  value of shares that  may yet be  purchased under  the plans** | ** ** |
|--------------------------------|------------|------------------------|------------|-------------------------|------------|----------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                     | ** ** | **(in millions)** | ** ** | ** **              | ** ** | **(in millions)**                       | ** ** | **(in millions)**                                                                                         | ** ** |
| Oct 1, 2006 - Oct  31, 2006(1) |       |                   | 1.18       |                    |       |                                         | $          | 27.11                                                                                                          |       |                                                                                                                         |       | 1.18 |   |   |   | $ | 67.96 |   |   |
| Nov 1, 2006 - Nov  30, 2006    |       |                   | —     |                    |       |                                         | —     |                                                                                                           |       |                                                                                                                         | —     |   |   |   | $ | 67.96 |   |   |
| Dec 1, 2006 - Dec  31, 2006    |       |                   | —     |                    |       |                                         | —     |                                                                                                           |       |                                                                                                                         | —     |   |   |   | $ | 67.96 |   |   |
| Total                          |       |                   | 1.18       |                    |       |                                         | $          | 27.11                                                                                                          |       |                                                                                                                         |       | 1.18 |   |   |   | $ | 67.96 |   |   |

----

(1)          OnSeptember 28, 2006, we announced a share repurchase plan under which wecan repurchase up to $100 million of common stock on the open market or innegotiated transactions. The plan expires in September 2007.

**SecuritiesAuthorized for Issuance under Equity Compensation Plans**

Thefollowing table sets forth the compensation plans under which our equitysecurities were authorized for issuance as of December 31, 2006:

| **Plan category**                                      | ** ** | ** **             | ** ** | **Number of securities to  be issued upon exercise  of outstanding options,  warrants and rights** | ** ** | **Weighted-average  exercise price of  outstanding options,  warrants and rights** | ** ** | **Number of securities remaining  available for future issuance  under equity compensation  plans (excluding securities to  be issued upon exercise of  outstanding options, warrants  and rights)** | ** ** |
|-------------------------------------------------------------|------------|------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                  | ** ** | **(in millions)** | ** ** | ** **                                                                                                                                           | ** ** | **(in millions)**                                                                                      | ** ** |
| Equity  compensation plans approved by security holders     |       |                   | 4.4        |                                                                                                                                                 |       |                                                                                                        | $          | 25.93                                                                                                                                                                                                                                                                                          |       |   |   | 14.2 |   |   |
| Equity compensation  plans not approved by security holders |       |                   | N/A        |                                                                                                                                                 |       |                                                                                                        | N/A        |                                                                                                                                                                                                                                                                                           |       |   | N/A |   |   |
| Total                                                       |       |                   | 4.4        |                                                                                                                                                 |       |                                                                                                        | $          | 25.93                                                                                                                                                                                                                                                                                          |       |   |   | 14.2 |   |   |

 

Our 2005 Omnibus IncentivePlan for certain employees and directors of Mirant became effective on January 3,2006, and is deemed to have been approved by our stockholders by virtue of itsapproval under the Plan of Reorganization.

53

----

**Stock PerformanceGraph**

The performance graphbelow compares the cumulative total stockholder return on Mirant’s common stockwith the Standard & Poor’s Multi-Utility Index and the Standard &Poor’s 500 Index since the re-issuance of our common stock in connectionwith our emergence from bankruptcy on January 3, 2006. Because all of oldMirant’s outstanding common stock was cancelled upon emergence from bankruptcy,stock performance prior to 2006 does not provide a meaningful comparison forcurrent stockholders and thus has not been provided. The graph assumes that$100 was invested on January 11, 2006, in Mirant’s common stock and eachof the above indices, and that all dividends are reinvested. The stockholderreturn shown below may not be indicative of future performance.

****

**Total Return to Shareholders(Includes reinvestment of dividends)Quarterly Return PercentageQuarter Ending**

| **Company / Index**                                      | ** ** | ** ** | ** ** | **3/31/2006** | ** ** | **6/30/2006** | ** ** | **9/30/2006** | ** ** | **12/31/2006** | ** ** |
|--------------------------------------------------------------------|------------|------------|------------|---------------|------------|---------------|------------|---------------|------------|----------------|------------|
| Mirant  Corporation                                                |       |       | 0.08       | %             |       |          | 7.20       | %             |       |           | 1.90       | % |   |   | 15.60 | % |   |
| S&P 500 Index                                                  |       |       | 0.51       | %             |       |          | (1.44      | )%            |       |           | 5.67       | % |   |   | 6.70 | % |   |
| S&P 500  Multi-Utilities Index                                 |       |       | (3.17      | )%            |       |          | 3.47       | %             |       |           | 4.20       | % |   |   | 10.54 | % |   |
| S&P 500 Independent  Power Producers & Energy Traders |       |       | (1.92      | )%            |       |          | 19.28      | %             |       |           | 7.07       | % |   |   | (0.18 | )% |   |

 

**IndexedReturnsQuarter Ending**

| **Company / Index**                                      | ** ** | ** ** | ** ** | **Base Period  1/11/2006** | ** ** | **3/31/2006** | ** ** | **6/30/2006** | ** ** | **9/30/2006** | ** ** | **12/31/2006** | ** ** |
|--------------------------------------------------------------------|------------|------------|------------|---------------------------------|------------|---------------|------------|---------------|------------|---------------|------------|----------------|------------|
| Mirant  Corporation                                                |       |       | $          | 100                             |       |          | $          | 100.08        |       | $             | 107.29     |           | $          | 109.33 |   |   | $ | 126.38 |   |   |
| S&P 500 Index                                                  |       |       | 100        |                            |       | 100.51        |       | 99.06         |       | 104.68        |       |           | 111.69     |   |   |
| S&P 500  Multi-Utilities Index                                 |       |       | 100        |                            |       | 96.83         |       | 100.19        |       | 104.40        |       |           | 115.41     |   |   |
| S&P 500 Independent  Power Producers & Energy Traders |       |       | 100        |                            |       | 98.08         |       | 116.99        |       | 125.26        |       |           | 125.03     |   |   |
|                                                                    |            |            |            |                                 |            |               |            |               |            |               |            |                |            |  |  |  |  |  |  |  |  |  |

 

54

----

**Item 6.**                        *Selected Financial Data*

The following discussion should be read in conjunctionwith our consolidated financial statements and the notes thereto, which areincluded elsewhere in this Form 10-K. The following table presentsour selected consolidated financial information, which is derived from ourconsolidated financial statements. Prior years have been revised to reflect theimpact of our planned dispositions of the Philippine and Caribbean businessesand six U.S. natural gas-fired intermediate and peaking plants. See Note 3 toour consolidated financial statements for further discussion of ourdiscontinued operations.

From July 14, 2003 (the “Petition Date”), throughemergence, our consolidated financial statements were prepared in accordancewith SOP 90-7. Our Statements of Operations Data for the years ended December 31,2004 and 2003, do not include interest expense on debt that was subject tocompromise subsequent to the Petition Date. Our Statements of Operations Datafor the year ended December 31, 2005, reflects the effects of accountingfor the Plan of Reorganization confirmed on December 9, 2005.

Our Statements of Operations Data for the years ended December 31,2004, 2003 and 2002, include goodwill impairment losses of $582 million, $2.067billion and $697 million, respectively.

OurStatement of Operations Data for the year ended December 31, 2006,reflects significant income tax benefits as discussed in Note 13 to ourconsolidated financial statements. Our Statement of Operations Data for theyear ended December 31, 2002, includes the recognition of $949 million ofprovision for income taxes primarily related to valuation allowances for UnitedStates deferred tax assets.

| ** **                                             | ** ** | **Years Ended December 31,**                      | ** ** |
|--------------------------------------------------------|------------|------------------------------------------------------------------|------------|
| ** **                                             | ** ** | **2006**                                                         | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                             | ** ** | **(in millions except per share data)** | ** ** |
| Statements of Operations  Data:                        |       |                                                             |       |   |   |   |   |   |   |   |   |
| Operating  revenues                                    |       | $                                                                | 3,103      |   | $ | 2,646 |   | $ | 3,248 |   | $ | 3,863 |   | 3,385 |   |
| Income (loss)  from continuing operations              |       | 1,773                                                            |       | (1,390 | ) | 1 |   | (3,884 | ) | (1,840 | ) |
| Income (loss)  from discontinued operations            |       | 91                                                               |       | 99 |   | (477 | ) | 78 |   | (598 | ) |
| Cumulative effect  of changes in accounting principles |       | —                                                           |       | (16 | ) | — |   | (29 | ) | — |   |
| Net Income (loss)                                      |       | 1,864                                                            |       | (1,307 | ) | (476 | ) | (3,835 | ) | (2,438 | ) |
| Basic EPS per common  share from continuing operations |       | $                                                                | 6.22       |   | N/A |   | N/A |   | N/A |   | N/A |   |
|                                                        |            |                                                                  |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

TheConsolidated Balance Sheet Data for years 2006, 2005, 2004 and 2003, segregatespre-petition liabilities subject to compromise from those liabilities that werenot subject to compromise.

| ** **                                                                                                     | ** ** | **Years Ended December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                                                     | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| Balance Sheet Data:                                                                                            |       |                                        |       |   |   |   |   |   |   |   |   |
| Total assets                                                                                                   |       | $                                           | 11,536     |   | $ | 12,912 |   | $ | 11,424 |   | $ | 12,123 |   | $ | 19,423 |   |
| Total long-term  debt                                                                                          |       | 3,275                                       |       | 2,582 |   | 38 |   | 288 |   | 7,408 |   |
| Liabilities  subject to compromise                                                                             |       | 18                                          |       | 18 |   | 9,164 |   | 9,036 |   | — |   |
| Company obligated  mandatorily redeemable securities of a subsidiary holding solely parent  company debentures |       | —                                      |       | — |   | — |   | — |   | 345 |   |
| Stockholders’ equity  (deficit)                                                                           |       | $                                           | 4,443      |   | $ | 3,856 |   | $ | (1,318 | ) | $ | (823 | ) | $ | 2,955 |   |

 

55

----

**Item 7.**                        *Management’s Discussion and Analysis of Results of Operations andFinancial Condition*

This section is intendedto provide the reader with information that will assist in understanding ourfinancial statements, the changes in those financial statements from year toyear and the primary factors contributing to those changes. The followingdiscussion should be read in conjunction with our consolidated financialstatements and the notes accompanying those financial statements.

***Overview***

We are a competitive energycompany that produces and sells electricity in the United States, thePhilippines and the Caribbean. Our continuing operations consist ofpower generation facilities located in the United States and our energy tradingand marketing operations. Our continuing business consists of 10,650 MW locatedin markets that are characterized by low and declining reserve margins.

During the third quarter of2006, we commenced separate auction processes to sell our Philippine andCaribbean businesses and certain of ourU.S. natural gas-fired intermediate and peaking assets. On December 11,2006, we entered into a definitive purchase and sale agreement with aconsortium of The Tokyo Electric Power Company and Marubeni Corporation for thesale of our Philippine business for a purchase price of $3.424 billion, plus aworking capital adjustment at the closing. After the payment of related debt,which is estimated to be $642 million at the closing, the net proceeds toMirant are expected to be $3.121 billion after transaction costs. Thetransaction is expected to close in the second quarter of 2007 after thesatisfaction of certain customary conditions and the return to operation ofboth units at the Sual plant. Upon completion of the transaction, Mirant expectsto record a pre-tax gain of approximately $2 billion.

In 2006, we have recognized a tax benefit in theamount of $721 million related to the pending sale of our Philippine businessin 2007. This benefit has two components: a) $580 million recognized forcontinuing operations related to the release of the valuation allowancepertaining to deferred tax assets previously recorded including the estimatedvalue of the NOLs that will be used to offset the anticipated 2007 taxable gainresulting from the sale; and b) $141 million recognized for our discontinuedoperations related to the value of the additional difference between the bookbasis and the tax basis in the shares of the entity being sold. Each year, ournet U.S. Federal deferred tax assets have been reduced by a valuation allowanceto reflect the amount that was estimated to be recoverable. It is our judgmentbased on available evidence that it is more-likely-than-not that deferred taxassets relating to this transaction will be recoverable in 2007. Management hasconsidered all available positive and negative evidence affecting thesespecific deferred tax assets in making this decision and has determined thatthe valuation allowance related to such deferred tax assets should be releasedin 2006. Inaddition, based on the pending sale of the Philippine business, we no longerintend to distribute earnings in the form of a dividend prior to the completedsale. As a result, we have recognized an additional net tax benefit of $124million in discontinued operations related to the reversal of previouslyaccrued foreign withholding taxes.

On January 15, 2007, we entered into a definitivepurchase and sale agreement with a subsidiary of LS Power Equity Partners I,L.P., LS Power Equity Partners II, L.P. and certain other affiliated funds,(collectively, “LS Power”), for the sale of six U.S. natural gas-fired plantsfor a purchase price of $1.407 billion, which includes estimated workingcapital and certain surplus generating equipment. After the payment of $83million of related debt, the net proceeds are expected to be $1.307 billionafter transaction costs. The transaction is expected to close in the secondquarter of 2007 after the satisfaction of certain customary conditions.

The auction and due diligence processes in respect ofthe sale of the Caribbean business are underway, and the sale of the Caribbeanbusiness is expected to close by mid-2007.

56

----

The primary factors affecting the earnings and cashflows of our continuing operations are the prices for power, emissionsallowances, natural gas, oil 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 1990s hascreated an oversupply situation in most markets which is expected to continueuntil 2008 to 2010. In certain markets in the United States, that excess hasbeen absorbed or is close to being absorbed. Electricity demand has beengrowing and supply has not appreciably increased. Given the substantialtime necessary to permit and construct new power plants, we think that themarkets in the United States in which we operate need to begin the process nowof adding generating capacity to meet growing demand. A number of key ISOs haveimplemented capacity markets as a way to encourage such construction ofadditional generation, but it is not clear whether the incentives offered willresult in the construction of new generation.

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

*HedgingActivities.*   Prior to 2006, we hedged asubstantial portion of our Mid-Atlantic baseload coal-fired generation and ourNew England intermediate oil-fired generation through OTC transactions. As aresult, we achieved a significant increase in our realized gross margin for theyear ended December 31, 2006, as compared to the same period in 2005because our generation was hedged at higher gross margins for this period thanfor the same period in 2005. Our intermediate and peaking generation volumesgenerally were lower in the year ended December 31, 2006, than in 2005,due primarily to lower generation from our oil-fired units as a result of lowerpower prices combined with sharply higher oil prices in 2006.

In 2006 and thus far in 2007, our Mirant Mid-Atlanticsubsidiary entered into financial swap transactions resulting in MirantMid-Atlantic being economically hedged for approximately 92%, 93%, 97% and 38%of its expected on-peak coal-fired baseload generation in 2007, 2008, 2009 and 2010,respectively. The financial swap transactions include new hedges in addition tothe previously disclosed January 2006 hedges. These transactions aresenior unsecured obligations of Mirant Mid-Atlantic and do not require theposting of cash collateral either for initial margin or for securing exposuredue to changes in power prices. As of February 26, 2007, our totalportfolio is economically hedged approximately 83%, 47%, 35% and 14% for 2007,2008, 2009 and 2010, respectively. The corresponding fuel hedges areapproximately 81%, 27%, 15% and 0% for 2007, 2008, 2009 and 2010 respectively.

*NewYork Property Tax Settlement.*   On December 13,2006, we entered into a settlement agreement with certain tax jurisdictionsrelated to property tax assessments at the Bowline and Lovett generatingfacilities that resolves all pending disputes regarding refunds sought by usfor property taxes paid for 1995 through 2003 and unpaid taxes assessed for2003 through 2006. Under the settlement, we were awarded refunds totalingapproximately $163 million for 1995 through 2003, against which were offsetunpaid taxes of approximately $115 million for 2003 through 2006, resulting ina net cash payment in the amount of $48 million. The refunds were received andthe unpaid taxes were paid in early February 2007. As a result of therefunds and the reduction in unpaid taxes under the settlement, we recognized again of approximately $244 million in the fourth quarter of 2006. Of the $244million gain recognized, $163 million is included in reorganization items, net,and $94 million is a reduction in operations and maintenance expense in ourconsolidated statements of operations. These amounts are partially offset by$13 million in interest expense.

*CapitalResources.*   Our business is subject to extensiveenvironmental regulation by federal, state and local authorities. Our costs ofcomplying with environmental laws, regulations and permits are substantial anddifficult to estimate because we cannot always assess what regulations may beadopted or modified in 

57

----

the future or what costsmight be associated with complying with the regulation. To comply with therequirements for SO2 and NOx emissions under the Maryland Healthy Air Act, weanticipate total capital expenditures of approximately $1.6 billion through 2009,including $80 million incurred through 2006. We expect that cash flows fromoperations will be sufficient to fund these capital expenditures.

A portion of our capital resources, in the form ofcash 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.

Our cash flows from financing activities reflect$1.261 billion of repurchases of common stock, third quarter debt issuances andrepayments related to our discontinued operations, first quarter exit financingas part of our bankruptcy emergence and the first quarter payment ofapproximately $1.035 billion, of which $45 million relates to discontinuedoperations, of bankruptcy claims related to outstanding indebtedness.

*Sharerepurchases.*   During the third quarter of 2006,we repurchased 43 million shares of Mirant common stock for an aggregate purchase price of approximately $1.23 billion.To pay for the shares tendered in the offer and related expenses, we utilizedapproximately $315 million of cash on hand at Mirant Corporation andapproximately $915 million of distributions or repayments from oursubsidiaries, including approximately $175 million and $740 million distributedor repaid from Mirant Americas Generation and Mirant Asia-Pacific Limited andits subsidiaries, respectively.

In August 2006, our Board of Directors authorizeda $100 million share repurchase program. Accordingly, we intend, from time totime, until September 30, 2007, as business conditions warrant, topurchase shares of Mirant common stock on the open market or in negotiatedtransactions. We have repurchased 1.18 million shares for an aggregate purchaseprice of $32 million under this plan.

*Use of Proceeds fromPlanned Dispositions.*   Upon completion of thebusiness and asset sales, we plan to continue returning cash to ourshareholders. The amount of cash returned will be based on preserving thecredit profile of the continuing operations, retaining sufficient workingcapital to manage fluctuations in commodity prices and maintaining adequateliquidity for expected cash requirements including, among other things, capitalexpenditures. The sale of the Zeeland and Bosque plants is subject to the termsof the Mirant Americas Generation and Mirant North America indebtedness,including provisions with respect to the mandatory prepayment and/orreinvestment of the sale proceeds and the requirement to secure a credit ratingaffirmation.

58

----

*ConsolidatedFinancial Performance*

Wereported net income of $1.864 billion for the year ended December 31,2006, and net losses of $1.307 billion and $476 million for the yearsended December 31, 2005 and 2004, respectively. The change in net incomeis detailed as follows (dollars in millions):

| ** **                                                                                  | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                                  | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **Increase/  (Decrease)** | ** ** | **2005** | ** ** | **2004** | ** ** | **Increase/  (Decrease)** | ** ** |
| Gross margin                                                                                |       | $                                           | 1,947      |   | $ | 846 |   |   | $ | 1,101 |   |   | $ | 846 |   | $ | 1,089 |   |   | $ | (243 | ) |   |
| Operating expenses:                                                                         |       |                                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Operations and maintenance                                                                  |       | 609                                         |       | 698 |   |   | (89 | ) |   | 698 |   | 718 |   |   | (20 | ) |   |
| Depreciation and amortization                                                               |       | 137                                         |       | 135 |   |   | 2 |   |   | 135 |   | 137 |   |   | (2 | ) |   |
| Impairment losses                                                                           |       | 119                                         |       | 9 |   |   | 110 |   |   | 9 |   | 9 |   |   | — |   |   |
| Loss (gain) on sales of assets, net                                                         |       | (49                                         | )          | 17 |   |   | (66 | ) |   | 17 |   | 49 |   |   | (32 | ) |   |
| Total operating expenses                                                                    |       | 816                                         |       | 859 |   |   | (43 | ) |   | 859 |   | 913 |   |   | (54 | ) |   |
| Operating income (loss)                                                                     |       | 1,131                                       |       | (13 | ) |   | 1,144 |   |   | (13 | ) | 176 |   |   | (189 | ) |   |
| Total other expense (income), net                                                           |       | 99                                          |       | 1,413 |   |   | (1,314 | ) |   | 1,413 |   | (50 | ) |   | 1,463 |   |   |
| Income (loss) from continuing operations before  reorganization items, net and income taxes |       | 1,032                                       |       | (1,426 | ) |   | 2,458 |   |   | (1,426 | ) | 226 |   |   | (1,652 | ) |   |
| Reorganization items, net                                                                   |       | (163                                        | )          | (18 | ) |   | (145 | ) |   | (18 | ) | 227 |   |   | (245 | ) |   |
| Benefit for income taxes                                                                    |       | (578                                        | )          | (18 | ) |   | (560 | ) |   | (18 | ) | (2 | ) |   | (16 | ) |   |
| Income (loss) from continuing  operations                                                   |       | 1,773                                       |       | (1,390 | ) |   | 3,163 |   |   | (1,390 | ) | 1 |   |   | (1,391 | ) |   |
| Income (loss) from discontinued  operations                                                 |       | 91                                          |       | 99 |   |   | (8 | ) |   | 99 |   | (477 | ) |   | 576 |   |   |
| Cumulative effect of changes in accounting principles                                       |       | —                                      |       | (16 | ) |   | 16 |   |   | (16 | ) | — |   |   | (16 | ) |   |
| Net income (loss)                                                                           |       | $                                           | 1,864      |   | $ | (1,307 | ) |   | $ | 3,171 |   |   | $ | (1,307 | ) | $ | (476 | ) |   | $ | (831 | ) |   |

 

*Bankruptcy Considerations*

While inbankruptcy, our financial results were volatile as asset impairments, assetdispositions, restructuring activities, contract terminations and rejections,and claims assessments significantly affected our consolidated financialresults. As a result, our historical financial performance is not indicative ofour financial performance post-bankruptcy.

At December 31, 2006and 2005, amounts related to allowed claims, estimated unresolved claims andprofessional fees associated with the bankruptcy to be settled in cash were $28million and $1.903 billion, respectively, and these amounts were recorded inclaims payable and estimated claims accrual on the accompanying consolidatedbalance sheets. These amounts do not include unresolved claims that are expectedto be settled in common stock or the stock portion of claims that are expectedto be settled with cash and stock. During the year ended December 31,2006, we paid approximately $1.849 billion in cash related to bankruptcyclaims. Of this amount, $1.035 billion represents the principal amount of debtclaims with $990 million reflected in cash flows from financing activities fromcontinuing operations and $45 million reflected in cash flows from financingactivities from discontinued operations. The remaining $814 million isreflected in cash flows from operating activities and represents otherbankruptcy claims and related interest. As of December 31, 2006,approximately 21 million of the shares of Mirant common stock to be distributedunder the Plan of Reorganization (the “Plan”) have not yet been distributed andhave been reserved for distribution with respect to claims that are disputed bythe Mirant Debtors and have yet to be resolved. However, up to 18 million ofthese reserved shares are proposed to be issued in settlement of the Pepcolitigation. See “Item 3. Legal Proceedings, Chapter 11 Proceedings.”

59

----

**Results ofOperations**

The following discussion of our performance isorganized by reportable operating segment, which is consistent with the way wemanage our business. Previously, we managed our business as three operatingsegments: United States, Philippines and Caribbean. In 2006, we commencedseparate auction processes to dispose of our Caribbean and Philippinebusinesses and certain U.S. natural gas-fired assets. The planned sales haveresulted in the reclassification of the revenues and expenses of thesebusinesses and assets to discontinued operations and the reclassification ofthe related assets and liabilities to assets held for sale for all periodspresented. In the fourth quarter of 2006, we re-evaluated the business segmentsof our continuing operations. As a result, we now have four operating segments:Mid-Atlantic, Northeast, California and Other Operations. For selectedfinancial information about our business segments, see Note 20 to ourconsolidated financial statements contained elsewhere in this report.

In the tables below, theMid-Atlantic region includes our Chalk Point, Morgantown, Dickerson and PotomacRiver facilities. The Northeast region includes our Bowline, Canal, Lovett,Kendall, Hillburn, Shoemaker, Martha’s Vineyard, Swinging Bridge, Rio, Mongaupand Wyman facilities. The California region includes our Pittsburg, ContraCosta and Potrero facilities. Other Operations includes proprietary trading andfuel oil management activities and gains and losses related to the contractualarrangement with Pepco with respect to certain PPAs, including Pepco’slong-term PPAs with Panda and Ohio Edison (the “Back-to-Back Agreement”) andTPAs with Pepco.

*OperatingStatistics*

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

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

 

Thefollowing table summarizes power generation volumes by region for the yearsended December 31, 2006, 2005 and 2004 (in gigawatt hours):

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

 

60

----

**2006 versus 2005**

*Gross Margin*

Thefollowing table details gross margin by realized and unrealized margin for theyear ended December 31, 2006 and 2005 (in millions):

| ** **       | ** ** | **Years Ended December 31,** | ** ** |
|------------------|------------|---------------------------------------------|------------|
| ** **       | ** ** | **2006**                                    | ** ** | **2005** | ** ** |
| ** **       | ** ** | **Realized**                                | ** ** | **Unrealized** | ** ** | **Total** | ** ** | **Realized** | ** ** | **Unrealized** | ** ** | **Total** | ** ** |
| Mid-Atlantic     |       |                                        | $          | 834 |   |   |   | $ | 484 |   |   | $ | 1,318 |   |   | $ | 552 |   |   |   | $ | (97 | ) |   | $ | 455 |   |
| Northeast        |       |                                        | 297        |   |   |   | 61 |   |   | 358 |   |   | 216 |   |   |   | (11 | ) |   | 205 |   |
| California       |       |                                        | 112        |   |   |   | 3 |   |   | 115 |   |   | 113 |   |   |   | — |   |   | 113 |   |
| Other Operations |       |                                        | 11         |   |   |   | 107 |   |   | 118 |   |   | (34 | ) |   |   | 92 |   |   | 58 |   |
| Eliminations     |       |                                        | 38         |   |   |   | — |   |   | 38 |   |   | 15 |   |   |   | — |   |   | 15 |   |
| Total            |       |                                        | $          | 1,292 |   |   |   | $ | 655 |   |   | $ | 1,947 |   |   | $ | 862 |   |   |   | $ | (16 | ) |   | $ | 846 |   |

 

***Mid-Atlantic***

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

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

 

***Gross Margin***

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

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

 

61

----

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

Contracted and capacity represents revenue received through RMRcontracts and other installed capacity arrangements, revenues from ancillaryservices and revenue from the Back-to-Back Agreement.

Incremental realized value of hedges represents theactual margin upon the settlement of our power and fuel hedging contracts.

Unrealized gains/losses represent the unrealizedportion of our derivative contracts.

The significantincrease in the gross margin for our Mid-Atlantic operations is primarily dueto the following:

·       anincrease of $581 million related to unrealized gains and losses on hedgingactivities. In 2006, unrealized gains of $484 million are primarily due to$312 million from increased value associated with forward power contracts forfuture periods as a result of decreases in forward power prices in 2006 and$172 million due to the settlement of power and fuel contracts during the yearfor which net unrealized losses had been recorded in prior periods,particularly during the high energy prices of late 2005. In 2005, unrealizedlosses of $97 million were primarily due to increases in power prices as aresult of increases in gas prices;

·       anincrease of $616 million in incremental realized value of hedges of ourgeneration output. In 2006, the incremental realized value of our hedgescontributed $237 million to our gross margin as our power contracts settled atprices higher than market prices for the year. In 2005, our opportunity cost ofhedging was $379 million primarily due to the impact of rising energy prices inthe latter part of 2005 that resulted in the settlement of power contracts atprices lower than market prices for that year; and

·       a decrease of $309 millionin energy primarily related to lower power prices and lower generation volumeon our oil-fired units. Power prices were lower due to significantly lower gasprices in 2006 compared to 2005. Our baseload coal units’ generation decreasedslightly and our 9% total decrease in generation volumes was driven bysignificantly lower volumes generated by our oil-fired units. A sharp decreasein power prices combined with average oil prices that were somewhat higher thanin 2005 resulted in our oil-fired units not being able to dispatch economicallyfor much of the year.

62

----

***Northeast***

OurNortheast segment is comprised of our assets located in New York and NewEngland with a total generation capacity of 3,047 MW. The following tablesummarizes the operations of our Northeast segment for the years endedDecember 31, 2006 and 2005 (in millions):

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

 

***Gross Margin***

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

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

 

The increase ingross margin is primarily due to the following:

·       anincrease of $72 million related to unrealized gains and losses on hedgingactivities. In 2006, unrealized gains of $61 million are primarily due to$50 million from increased value associated with forward power and fuelcontracts for future periods mainly as a result of decreases in forward powerprices in 2006 and $11 million due to the settlement of power and fuelcontracts during the year for which unrealized losses had been recorded inprior periods, particularly during the high energy prices of late 2005. In2005, unrealized losses of $11 million were primarily due to increases in powerprices as a result of increased gas prices and the settlement of contractsduring the year for which unrealized losses had been recorded in prior periods,partially offset by an increase in the value of fuel hedges due to higher fuelprices;

·       anincrease of $180 million in incremental realized value of hedges of ourgeneration output. In 2006, the incremental realized value of our hedgescontributed $125 million to our gross margin as our power contracts settled atprices higher than market prices for the year, partially offset by hedged fuelcosts that were higher than the market. In 2005, our opportunity cost ofhedging was $55 million primarily due to the impact of rising energy prices in thelatter part of 2005 that resulted 

63

----

in the settlement of powercontracts at prices lower than market prices for that year, partially offset bythe favorable impact of hedged fuel costs that were generally lower than themarket as fuel prices increased in 2005; and

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

*Operating Expenses*

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

***California***

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

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

 

***Gross Margin***

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

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

 

64

----

 

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

*Other Expense, net*

The decrease of $35million in other expense, net is primarily due to a gain of $26 million in 2006related to the transfer of Contra Costa unit 8 to PG&E and an increase of$6 million in interest income. See “California Settlement” in Note 23 to ourconsolidated financial statements for further discussion.

***Other Operations***

OtherOperations includes proprietary trading, fuel oil management, and gains andlosses related to our Back-to-Back Agreement and TPAs with Pepco. See “PepcoLitigation” in Note 23 to our consolidated financial statements for furtherdiscussion of the Back-to-Back Agreement. The following table summarizes theoperations of our Other Operations segment for the years ended December 31,2006 and 2005 (in millions): 

| ** **                                                                    | ** ** | **Years Ended December 31,** | ** ** | **Increase/** | ** ** |
|-------------------------------------------------------------------------------|------------|---------------------------------------------|------------|---------------|------------|
| ** **                                                                    | ** ** | **2006**                                    | ** ** | **2005**      | ** ** | **(Decrease)** | ** ** |
| Realized Gross  Margin                                                        |       |                                        | $          | 11            |       |   |   | $ | (34 | ) |   |   | $ | 45 |   |   |
| Unrealized Gross  Margin                                                      |       |                                        | 107        |          |       |   | 92 |   |   |   | 15 |   |   |
| Total Gross  Margin                                                           |       |                                        | 118        |          |       |   | 58 |   |   |   | 60 |   |   |
| Operating  expenses:                                                          |       |                                        |       |          |       |   |   |   |   |   |   |   |   |
| Operations and maintenance                                                    |       |                                        | 80         |          |       |   | 64 |   |   |   | 16 |   |   |
| Depreciation and amortization                                                 |       |                                        | 25         |          |       |   | 33 |   |   |   | (8 | ) |   |
| Impairment losses                                                             |       |                                        | 1          |          |       |   | 9 |   |   |   | (8 | ) |   |
| Loss (gain) on sales of assets, net                                           |       |                                        | (40        | )             |       |   | 19 |   |   |   | (59 | ) |   |
| Total operating  expenses                                                     |       |                                        | 66         |          |       |   | 125 |   |   |   | (59 | ) |   |
| Operating income  (loss)                                                      |       |                                        | 52         |          |       |   | (67 | ) |   |   | 119 |   |   |
| Total other  expense, net                                                     |       |                                        | 128        |          |       |   | 1,414 |   |   |   | (1,286 | ) |   |
| Loss from continuing  operations before reorganization items and income taxes |       |                                        | $          | (76           | )          |   |   | $ | (1,481 | ) |   |   | $ | 1,405 |   |   |

*** ***

***Gross Margin***

Grossmargin increased by $60 million for the year ended December 31, 2006,compared to the same period for 2005 and is detailed as follows (in millions):

| ** **               | ** ** | **Years Ended December 31,** | ** ** | ** ** | ** ** |
|--------------------------|------------|---------------------------------------------|------------|------------|------------|
| ** **               | ** ** | **2006**                                    | ** ** | **2005**   | ** ** | **Increase** | ** ** |
| Energy                   |       |                                        | $          | 71         |       |   |   | $ | 44 |   |   |   | $ | 27 |   |   |
| Contracted and  capacity |       |                                        | (60        | )          |       |   | (78 | ) |   |   | 18 |   |   |
| Unrealized gains         |       |                                        | 107        |       |       |   | 92 |   |   |   | 15 |   |   |
| Total                    |       |                                        | $          | 118        |       |   |   | $ | 58 |   |   |   | $ | 60 |   |   |

 

65

----

The increase ingross margin is primarily due to the following:

·       anincrease of $27 million in energy, primarily related to our proprietary tradingand fuel oil management activities net of cost or market adjustments on our oilinventory during the third and fourth quarters of 2006;

·       anincrease of $18 million in contracted and capacity due to a decrease inrealized losses on the Back-to-Back Agreement and the related hedges of thiscontract primarily due to the expiration of one of the PPAs under thatagreement; and

·       an increase of $15 millionin unrealized gains and losses, which includes an increase of $73 million inunrealized gains on our proprietary trading and fuel oil management activities,partially offset by a decrease of $58 million in unrealized gains on theBack-to-Back Agreement and the related hedges.

*Operating Expenses*

The decrease of $59 millionin operating expenses is primarily due to an increase in gain on sales ofassets. In 2006, we recognized a $40 million gain from the sale of ourremaining claims in the Enron bankruptcy. In 2005, we recognized a $19 millionloss on sale of equipment from our Wyandotte suspended construction project.

*Other Expense, net*

Other expense, netin 2006 includes the interest expense on the debt of Mirant Americas Generationand Mirant North America. The decrease in other expense, net of $1.286 billionis primarily due to the following:

·       in2005, we recognized $1.2 billion of interest on liabilities subject tocompromise for the period from the 2003 petition date through December 2005;and

·       ourgain on sales of investments increased $31 million. In 2006, we recognized again of $54 million related to sales of our investment in ICE and a gain of $19million on the sale of our two New York Mercantile Exchange seats and shares.In 2005, we recognized a gain of $44 million related to the sale of a portionof our investment in ICE.

**Other SignificantConsolidated Statements of Operations Comparison**

*ReorganizationItems, net*

Reorganization items, netfor the years ended December 31, 2006 and 2005, are comprised of thefollowing (in millions):

| ** **                                                     | ** ** | **Years Ended December, 31,** | ** ** |
|----------------------------------------------------------------|------------|----------------------------------------------|------------|
| ** **                                                     | ** ** | **2006**                                     | ** ** | **2005** | ** ** | **Increase/  (Decrease)** | ** ** |
| Gain on the implementation  of the Plan                        |       | $                                            | —     |   | $ | (285 | ) |   | $ | 285 |   |   |   |
| Gain on the New  York property tax settlement                  |       | (163                                         | )          | — |   |   | (163 | ) |   |   |
| Estimated claims  and losses on rejected and amended contracts |       | 2                                            |       | 72 |   |   | (70 | ) |   |   |
| Professional fees  and administrative expense                  |       | —                                       |       | 226 |   |   | (226 | ) |   |   |
| Interest income,  net                                          |       | (2                                           | )          | (31 | ) |   | 29 |   |   |   |
| Total                                                          |       | $                                            | (163       | ) | $ | (18 | ) |   | $ | (145 | ) |   |   |

 

Reorganization items, net decreased by $145 millionfor the year ended December 31, 2006, compared to 2005, primarily relatedto the settlement of the New York State property tax disputes. Under the terms 

66

----

of the settlement, in February 2007we received refunds totaling approximately $163 million for 1995 through 2003and paid unpaid taxes of approximately $115 million for 2003 through 2006. Forthe year ended December 31, 2005, reorganization items, net representamounts that were recorded in the financial statements as a result of thebankruptcy proceedings.

Estimated claims andlosses on rejected and amended contracts relate primarily to rejected energycontracts, such as tolling agreements, gas transportation contracts andelectric transmission contracts.

*Provision (Benefit)for Income Taxes*

The $578 million netbenefit for income taxes for the year ended December 31, 2006, isprimarily due to the $580 million release of the valuation allowance pertainingto deferred tax assets previously recorded including the estimated value of theNOLs that will be used to offset the anticipated 2007 taxable gain resultingfrom the pending sale of the Philippine business in 2007. See Note 13 to theconsolidated financial statements for further discussion.

*DiscontinuedOperations*

During the third quarter of 2006, we commencedseparate auction processes to sell our Philippine and Caribbean businesses andsix intermediate and peaking natural gas-fired plants in the United States.Accordingly, the results of operations related to the planned sales werereclassified to income (loss) from discontinued operations in our consolidatedstatements of operations for all periods presented.

For the year ended December 31, 2006, we reportednet income from discontinued operations of $91 million, which includes thereclassification of the results of operations related to the planneddispositions and income related to the Wichita Falls facility. Included inincome from discontinued operations are the following:

·       animpairment loss of $375 million to write-down the U.S. natural gas-firedassets to estimated fair value;

·       anincome tax benefit of $141 million related to the disposition of the Philippinebusiness; and

·       anet tax benefit of $124 million related to the reversal of previously accruedforeign withholding taxes as a result of the decision, based on the pendingsale of the Philippine business, to no longer distribute any accumulatedearnings in the form of a dividend prior to the closing of the sale.

For the year ended December 31, 2005, we reportednet income from discontinued operations of $99 million, which includes thereclassification of the results of operations related to the planned dispositionsand income related to the Wichita Falls facility and the Wrightsvillegenerating facility.

At December 31, 2005, we had deferred tax assetsof $84 million related to the anticipated future tax benefits ofunrealized foreign exchange losses arising from the U.S. dollar denominatedborrowings of our Philippine entities. In the second quarter of 2006, finalregulations governing the selection and use of a functional currency forPhilippine tax reporting purposes became effective. We have determined thatthese regulations require us to maintain our local statutory filing inU.S. dollars converted to Philippine pesos for Philippine tax reportingpurposes for all tax years ending after December 31, 2004. Accordingly,for 2006, we have recognized an additional income tax provision of$84 million. We also experienced an increase in the income tax provisionof $23 million for the year ended December 31, 2006, related to theeffects of the expiration of the Sual tax holiday in 2005, offset by thereversal of a $12 million tax contingency related to prior tax years.

See Note 3 to our consolidated financial statementsfor additional information related to planned dispositions and discontinuedoperations including updates on outages at our Sual generation facility andclaims by NPC.

67

----

***2005 versus 2004***

Thefollowing table details gross margin by realized and unrealized margin for theyear ended December 31, 2005 and 2004 (in millions):

| ** **       | ** ** | **Years Ended December 31,** | ** ** |
|------------------|------------|---------------------------------------------|------------|
| ** **       | ** ** | **2005**                                    | ** ** | **2004** | ** ** |
| ** **       | ** ** | **Realized**                                | ** ** | **Unrealized** | ** ** | **Total** | ** ** | **Realized** | ** ** | **Unrealized** | ** ** | **Total** | ** ** |
| Mid-Atlantic     |       |                                        | $          | 552 |   |   |   | $ | (97 | ) |   | $ | 455 |   |   | $ | 576 |   |   |   | $ | (75 | ) |   | $ | 501 |   |
| Northeast        |       |                                        | 216        |   |   |   | (11 | ) |   | 205 |   |   | 197 |   |   |   | 31 |   |   | 228 |   |
| California       |       |                                        | 113        |   |   |   | — |   |   | 113 |   |   | 143 |   |   |   | 3 |   |   | 146 |   |
| Other Operations |       |                                        | (34        | ) |   |   | 92 |   |   | 58 |   |   | 1 |   |   |   | 209 |   |   | 210 |   |
| Eliminations     |       |                                        | 15         |   |   |   | — |   |   | 15 |   |   | 4 |   |   |   | — |   |   | 4 |   |
| Total            |       |                                        | $          | 862 |   |   |   | $ | (16 | ) |   | $ | 846 |   |   | $ | 921 |   |   |   | $ | 168 |   |   | $ | 1,089 |   |

 

***Mid-Atlantic***

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

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

 

***Gross Margin***

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

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

 

The decrease in gross margin is primarily due to thefollowing:

·       adecrease of $412 million in incremental realized value of hedges primarilyrelated to the impact of rising energy prices on the realized economic hedgesof our generation output during the 2005 period;

68

----

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

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

***Northeast***

The following table summarizes the operations of ourNortheast segment for the years ended December 31, 2005 and 2004 (inmillions):

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

*** ***

***Gross Margin***

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

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

 

The decrease in gross margin is primarily due to thefollowing:

·       a decrease of $74 million in incremental realized value ofhedges primarily related to the impact of rising energy prices on therealized economic hedges of our generation output during the 2005 period;

·       a decrease of $42 million related to unrealized gains andlosses on hedging activities. In 2005, unrealized losses of $11 millionare primarily due to the settlement of power and fuel contracts during the yearfor which net unrealized gains had been recorded in prior periods. In 2004, the

69

----

settlement of hedges forwhich unrealized losses had been recognized in prior periods resulted in a gainof $17 million. In addition, the impact of rising fuel prices on forward fuelcontracts, less the impact of rising power prices on forward power contracts,resulted in a gain of $14 million; and

·       an increase of $93 millionin energy primarily related to higher market prices for power, partially offsetby higher fuel costs during the year ended 2005 compared to the same period in2004.

*Operating Expenses*

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

***California***

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

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

 

***Gross Margin***

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

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

 

The decrease ingross margin is primarily due to the following:

·       adecrease in contracted and capacity of $13 million related to the expiration ofan RMR contract for one of our California generating facilities in 2004,partially offset by income from tolling agreements on those California assetsnot covered by RMR agreements; and

70

----

·       a decrease of $12 millionin the incremental realized value of hedges is due to favorable price spreadson both power and fuel contracts.

***Other Operations***

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

| ** **                                                                             | ** ** | **Years Ended December 31,** | ** ** | **Increase/** | ** ** |
|----------------------------------------------------------------------------------------|------------|---------------------------------------------|------------|---------------|------------|
| ** **                                                                             | ** ** | **2005**                                    | ** ** | **2004**      | ** ** | **(Decrease)** | ** ** |
| Realized Gross  Margin                                                                 |       |                                        | $          | (34           | )          |   |   | $ | 1 |   |   |   | (35 | ) |   |
| Unrealized Gross  Margin                                                               |       |                                        | 92         |          |       |   | 209 |   |   |   | (117 | ) |   |
| Total Gross  Margin                                                                    |       |                                        | 58         |          |       |   | 210 |   |   |   | (152 | ) |   |
| Operating  expenses:                                                                   |       |                                        |       |          |       |   |   |   |   |   |   |   |   |
| Operations and maintenance                                                             |       |                                        | 64         |          |       |   | 105 |   |   |   | (41 | ) |   |
| Depreciation and amortization                                                          |       |                                        | 33         |          |       |   | 40 |   |   |   | (7 | ) |   |
| Impairment losses                                                                      |       |                                        | 9          |          |       |   | 9 |   |   |   | — |   |   |
| Loss (gain) on sales of assets, net                                                    |       |                                        | 19         |          |       |   | (12 | ) |   |   | 31 |   |   |
| Total operating  expenses                                                              |       |                                        | 125        |          |       |   | 142 |   |   |   | (17 | ) |   |
| Operating income  (loss)                                                               |       |                                        | (67        | )             |       |   | 68 |   |   |   | (135 | ) |   |
| Total other  expense (income), net                                                     |       |                                        | 1,414      |          |       |   | (44 | ) |   |   | 1,458 |   |   |
| Income (loss) from  continuing operations before reorganization items and income taxes |       |                                        | $          | (1,481        | )          |   |   | $ | 112 |   |   |   | $ | (1,593 | ) |   |
|                                                                                        |            |                                             |            |               |            |  |  |  |  |  |  |  |  |  |  |  |

*** ***

***Gross Margin***

Grossmargin decreased by $152 million for the year ended December 31,2005, compared to the same period for 2004 and is detailed as follows (inmillions):

| ** **               | ** ** | **Year Ended December 31,** | ** ** | **Increase/** | ** ** |
|--------------------------|------------|--------------------------------------------|------------|---------------|------------|
| ** **               | ** ** | **2005**                                   | ** ** | **2004**      | ** ** | **(Decrease)** | ** ** |
| Energy                   |       |                                       | $          | 44            |       |   |   | $ | (13 | ) |   |   | $ | 57 |   |   |
| Contracted and  capacity |       |                                       | (78        | )             |       |   | 14 |   |   |   | (92 | ) |   |
| Unrealized gains         |       |                                       | 92         |          |       |   | 209 |   |   |   | (117 | ) |   |
| Total                    |       |                                       | $          | 58            |       |   |   | $ | 210 |   |   |   | $ | (152 | ) |   |

 

The decrease ingross margin is primarily due to:

·       adecrease of $92 million in contracted and capacity, which includes a decreaseof $335 million in amortization on two TPAs into which we entered in connectionwith the acquisition of the Mid-Atlantic facilities from Pepco. Under the TPAs,we agreed to supply Pepco its full load requirement in the District of Columbiaand in Maryland. The Maryland TPA expired in 2004 and the District of ColumbiaTPA expired in early 2005. The decrease related to the TPAs was partiallyoffset by an increase of $243 million in realized losses on the Back-to-BackAgreement;

·       anincrease of $57 million in energy primarily related to an increase in realizedgross margin from our proprietary trading and fuel oil management activities;and

·       a decrease of $117 million related to unrealized gainsand losses resulting from unrealized losses on derivative contracts for ourproprietary trading and fuel oil management activities of $60 million and adecrease of $57 million in unrealized gains on the Back-to-Back Agreement andthe related hedges of this contract.

71

----

*Operating Expenses*

The decrease of $17million in operating expenses is primarily due to a decrease in operations andmaintenance of $41 million, partially offset by an increase of $31 millionin loss (gain) on sales of assets. The decrease in operations and maintenanceis primarily due to a reduction in allocated corporate costs. In 2005, loss onsales of assets included $19 million related to the sale of equipment at ourWyandotte suspended construction project. In 2004, gain on sales of assetsincluded $16 million related to the sale of our remaining Canadian natural gastransportation contracts and certain natural gas marketing contracts.

*Other Expense, net*

The increase in otherexpense (income), net of $1.458 billion is primarily due to the recognition in2005 of $1.4 billion of interest on liabilities that were subject to compromisefor the period from the Petition Date through December 31, 2005. In 2004,the Company recognized a gain of $37 million related to the extinguishment of$83 million of 2.5% convertible debentures due 2021 that were included inliabilities subject to compromise.

**Other SignificantConsolidated Statements of Operations Comparison**

*ReorganizationItems, net*

Reorganizationitems, net decreased by $245 million for the year ended December 31, 2005,compared to the same period in 2004. Reorganization items represent expense,income or gain and loss amounts that were recorded in the financial statementsas a result of the bankruptcy proceedings. For the year ended December 31,2005, this amount included:

| ** **                                                     | ** ** | **Years Ended  December, 31,** | ** ** | **Increase/** | ** ** |
|----------------------------------------------------------------|------------|------------------------------------------|------------|---------------|------------|
| ** **                                                     | ** ** | **2005**                                 | ** ** | **2004**      | ** ** | **(Decrease)** | ** ** |
| Gain on the  implementation of the Plan                        |       | $                                        | (285       | )             | $          | — |   |   | $ | (285 | ) |   |
| Estimated claims  and losses on rejected and amended contracts |       | 72                                       |       | 132           |       |   | (60 | ) |   |
| Professional fees  and administrative expense                  |       | 226                                      |       | 109           |       |   | 117 |   |   |
| Interest income,  net                                          |       | (31                                      | )          | (14           | )          |   | (17 | ) |   |
| Total                                                          |       | $                                        | (18        | )             | $          | 227 |   |   | $ | (245 | ) |   |

 

Estimated claims andlosses on rejected and amended contracts relate primarily to rejected energycontracts, such as tolling agreements, gas transportation and electrictransmission contracts and include a $32 million gain related to the CaliforniaSettlement.

*Provision(Benefit) for Income Taxes*

The benefit forincome taxes increased by $16 million for the year ended December 31,2005, compared to 2004 primarily due to a favorable settlement offoreign taxes.

*DiscontinuedOperations*

For the year ended December 31, 2005, we reportedincome from discontinued operations of $99 million, which includes thereclassification of the results of operations related to the planneddispositions of the Philippine and Caribbean businesses and the six U.S.natural gas-fired plants and income related to the Wichita Falls facility.

For the year ended December 31, 2004, we reporteda loss from discontinued operations of $477 million, which includes thereclassification of the results of operations related to the planneddispositions, income related to the Wichita Falls facility and the Wrightsvillegenerating facility and an impairment 

72

----

charge of $48 million forthe Coyote Springs 2 facility. Our loss from discontinued operations in 2004included a $582 million impairment of the remaining goodwill related to ourPhilippine operations.

At December 31, 2005,we had deferred tax assets of $84 million related to the anticipatedfuture tax benefits of unrealized foreign exchange losses arising from the U.S.dollar denominated borrowings of our Philippine entities. In the second quarterof 2006, final regulations governing the selection and use of a functionalcurrency for Philippine tax reporting purposes became effective. We havedetermined that these regulations require us to maintain our local statutoryfiling in U.S. dollars converted to Philippine pesos for Philippine taxreporting purposes for all tax years ending after December 31, 2004. SeeNote 3 for additional information related to planned dispositions anddiscontinued operations including updates on outages at our Sual generationfacility and claims by NPC.

**Liquidity andCapital Resources**

***Overview***

Our liquidity and capitalrequirements are primarily a function of our debt maturities and debt servicerequirements, capital expenditures, collateral requirements, fuel procurementand power sale contract obligations, legal settlements and working capitalneeds. Net cash flow provided by operating activities totaled $563 million, $33million and $71 million for the years ended December 31, 2006, 2005 and2004, respectively.

***Emergence from Bankruptcy***

In connection with the consummation of the Plan on January 3,2006, all shares of old Mirant’s common stock were cancelled and300 million new shares of common stock were issued, of which276.5 million shares were distributed to holders of unsecured claims andequity securities, and 23.5 million shares were reserved for unresolvedclaims. We also issued two series of warrants, expiring January 3, 2011,that entitle the holders of these warrants to purchase an aggregate ofapproximately 53 million shares of common stock. In addition,approximately 19 million shares were reserved for issuance under theOmnibus Incentive Compensation Plan for employees and directors. Our authorizedcapital stock consists of 1.5 billion shares of common stock and100 million shares of preferred stock. Further, the Plan eliminatedapproximately $5.9 billion of debt and approximately $2.6 billion ofadditional claims and disputes through the distribution or planned distributionof new common stock and $1.9 billion in cash among creditors. At December 31,2006, approximately 21 million shares of common stock remain reserved fordistribution in settlement of unresolved claims. However, up to 18 million ofthese reserved shares are proposed to be issued in settlement of the Pepcolitigation. See Note 23 to our consolidated financial statements—“Chapter 11Proceedings” for further discussion of unresolved claims.

On December 23, 2005,in connection with our emergence from bankruptcy, our subsidiary Mirant NorthAmerica issued $850 million of 7.375% senior unsecured notes due 2013 (the“Old Notes”). The Old Notes were issued in a private placement and were notregistered with the SEC. The funds from this issuance initially were placed inescrow and were released from escrow on January 3, 2006. On August 4,2006, Mirant North America completed an exchange offer for the Old Notes,whereby $849.965 million of senior notes registered under the SecuritiesAct (the “New Notes”) were exchanged for an equal amount of the Old Notes. Theterms of the New Notes are identical in all material respects to the Old Notes,except that the New Notes are registered under the Securities Act and generallyare not subject to transfer restrictions or registration rights. On January 3,2006, Mirant North America also entered into an $800 million seniorsecured revolving credit facility and a $700 million senior secured termloan. At the closing, $200 million drawn under the senior secured termloan was deposited into a cash collateral account to support the issuance of upto $200 million of letters of credit.

73

----

***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 securedrevolving credit facility; (iii) $200 million of letters of creditcapacity under Mirant North America’s $700 million term loan; and (iv) proceedsfrom the sale of the Philippines, Caribbean and certain U.S. natural gas-firedplants. At December 31, 2006, we had approximately $1.027 billion ofavailable cash and cash equivalents and $796 million available under our seniorsecured credit facilities.

Proceeds from the sales of the Zeeland and Bosqueplants, expected to be approximately $500 million, will be reinvested in MirantNorth America, a subsidiary of Mirant Americas Generation, and/or used toretire debt at Mirant North America. Several of the credit facilities and thecapital markets debt of our Philippine and Caribbean subsidiaries contain “changeof control” provisions. Such provisions provide creditors the right to requirethe borrowing entity to repay, in whole or in part, the amount owed by theborrower after the change in control occurs. Such change in control provisionswould become effective upon the consummation of a transaction that triggerssuch provisions, such as a sale of our ownership interests in the respectivesubsidiary that is the obligor under such indebtedness. We expect that, inconnection with all such sales, such indebtedness will be prepaid with theproceeds of long-term financing arranged by the purchasers or that thepurchasers will obtain waivers of the change of control provisions from theexisting lenders.

Our operating cash flows may be affected by, amongother things: (i) demand for electricity; (ii) the difference betweenthe cost of fuel used to generate electricity and the market value of theelectricity generated; (iii) commodity prices (including prices forelectricity, emissions allowances, natural gas, coal and oil); (iv) thecost of ordinary course operations and maintenance expenses; (v) plannedand unplanned outages; (vi) terms with trade creditors; and (vii) cashrequirements for capital expenditures relating to certain facilities (includingthose necessary to comply with environmental regulations).

We and certain of oursubsidiaries, including Mirant Americas Generation and Mirant North America,are holding companies and, as a result, we are dependent upon dividends, distributionsand other payments from our subsidiaries to generate the funds necessary tomeet our obligations. The ability of certain of our subsidiaries to paydividends and distributions is restricted under the terms of their debt orother agreements. In particular, a significant portion of cash from our UnitedStates operations is generated by the power generation facilities of MirantMid-Atlantic. Under the Mirant Mid-Atlantic leveraged leases, MirantMid-Atlantic is subject to a covenant that restricts its right to makedistributions to us. Mirant Mid-Atlantic’s ability to satisfy the criteria setby that covenant in the future could be impaired by factors which negativelyaffect the performance of its power generation facilities, includinginterruptions in operation or curtailment of operations to comply withenvironmental restrictions.

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

*CollateralRequirements.**  *Our asset managementand, to a lesser extent, proprietary trading activities represent a significantneed for liquidity and capital resources. These liquidity requirements areprimarily driven by margin and collateral posting requirements withcounterparties and levels of inventory. As of December 31, 2006, we hadapproximately $227 million of posted cash collateral and $260 millionof letters of credit outstanding primarily to support our asset managementactivities and debt service reserve requirements. Our liquidity requirementsare highly dependent on the level of our hedging activity, 

74

----

forward prices for energy,emissions credits and fuel, commodity market volatility and credit terms withthird parties.

*CapitalExpenditures.**  *Capital expenditures for our continuing operationswere $133 million, $101 million and $90 million for the yearsended December 31, 2006, 2005 and 2004, respectively. Our capitalexpenditures for 2007 are expected to be approximately $826 million forour continuing business, with approximately $573 million of that amount forenvironmental capital expenditures needed to achieve compliance with the SO2and NOx emissions requirements of the Maryland Healthy Air Act. For a moredetailed discussion of environmental expenditures we expect to incur in thefuture, see ‘‘Item 1. Business.’’

*Debt Service.**  *At December 31, 2006, our continuingoperations had approximately $3.3 billion of long-term debt withexpected annual interest expense of approximately $256 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 MirantAmericas Generation for the purpose of paying interest on the Mirant AmericasGeneration senior notes) to pay down its senior secured term loan, in additionto its scheduled amortization of $7 million per year. The percentage offree cash flow that Mirant North America is required to use to pay down itssenior secured term loan may be reduced to 25% upon the achievement by it of anet debt to EBITDA ratio of less than 2:1.

*Mirant Mid-AtlanticOperating Leases*

Mirant Mid-Atlantic leasesthe Morgantown and Dickerson baseload units and associated property through2034 and 2029, respectively. Mirant Mid-Atlantic has an option to extend theleases. Any extensions of the respective leases would be limited to 75% of theeconomic useful life of the facility, as measured from the beginning of theoriginal lease term through the end of the proposed remaining lease term. Weare accounting for these leases as operating leases. While there is variabilityin the scheduled payment amounts over the lease term, we recognize rentalexpense for these leases on a straight-line basis in accordance with theapplicable accounting literature. As of December 31, 2006, the total notionalminimum lease payments for the remaining term of the leases aggregatedapproximately $2.2 billion and the aggregate termination value for theleases was approximately $1.4 billion and generally decreases over time.Rent expenses under the Mirant Mid-Atlantic leases were $96 million, $99million and $103 million for the years ended December 31, 2006, 2005, and2004, respectively. In addition, Mirant Mid-Atlantic is required to post rentreserves in an aggregate amount equal to the greater of the next six months’rent, fifty percent of the next twelve months’ rent or $75 million.

***Use of Proceeds from Planned Dispositions***

We plan to continuereturning cash to our shareholders upon completion of the planned sales of ourPhilippine and Caribbean businesses and the six U.S. natural gas-fired plants.The amount of cash returned will be determined based on the outlook for thecontinuing business (1) to preserve the credit profile of the continuingbusiness, (2) to maintain adequate liquidity for expected cash requirementsincluding, among other things, capital expenditures for the continuing businessand (3) to retain sufficient working capital to manage fluctuations incommodity prices. Proceeds from the sales of the Zeeland and Bosque plants,expected to be approximately $500 million, will be reinvested in Mirant NorthAmerica, a subsidiary of Mirant Americas Generation, and/or used to retire debtat Mirant North America.

75

----

***Cash Flows***

**2006 versus 2005**

*Continuing Operations*

*Operating Activities.**  *Ourcash provided by operating activities is affected by seasonality, changes inenergy prices and fluctuations in our working capital requirements. Cashprovided by operating activities from continuing operations increased$504 million for the year ended December 31, 2006, compared to thesame period in 2005, primarily due to the following:

·       anincrease in realized gross margin of $430 million for the year ended December 31,2006, compared to the same period in 2005. See “Results of Operations”**for additional discussion of our improved performance in2006 compared to the same period in 2005;

·       adecrease in energy trading collateral levels of $819 million in the year ended December 31,2006, compared to the same period in 2005. The change in collateralrequirements is due to the settlement of energy contracts combined with energyprice declines in the year ended December 31, 2006, compared to the sameperiod in 2005. For the year ended December 31, 2006, $592 million ofcash collateral from brokers and counterparties has been returned to us. Forthe year ended December 31, 2005, additional net collateral used tosupport commercial operations was $227 million;

·       anincrease in bankruptcy related claims and expenses of $643 million. In2006 we paid bankruptcy claims of $1.804 billion, of which $814 million isreflected in cash from operations. Our remaining claims payable and estimatedclaims accrual is $28 million at December 31, 2006. We paid$171 million in the year ended December 31, 2005 related toprofessional fees and other expenses associated with the bankruptcyproceedings; and

·       aremittance of $70 million to Pepco in the third quarter of 2006. See Note23 to our consolidated financial statements for further discussion of thesettlement agreement with Pepco;

*Investing Activities.**  *Net cashprovided by investing activities from continuing operations was$11 million for the year ended December 31, 2006, compared to$64 million for the same period in 2005. This difference was primarily dueto the following:

·       adecrease in proceeds from the sales of assets and investments of$22 million. In 2006, we received $143 million in proceeds from thesale of assets and investments, which included $45 million from the saleof bankruptcy claims against Enron and its subsidiaries, $12 million fromthe sale of the Mirant Service Center in Maryland and $58 million fromsales of a portion of our investment in ICE. In 2005, proceeds from sales ofassets and investments were $165 million and included $63 million inproceeds from the sale of Coyote Springs 2, $48 million from the sale of aportion of our investment in ICE, $4 million in additional proceeds fromthe 2004 sale of Bowline gas turbines and $44 million from the sale ofWyandotte’s equipment and turbines; and

·       anincrease of $32 million in capital expenditures for 2006 as compared to2005, primarily due to our environmental capital expenditures in 2006 in theMid-Atlantic.

*Financing Activities.**  *Net cash usedin financing activities from continuing operations was $758 million for theyear ended December 31, 2006, compared to cash provided by financingactivities of $97 million for the same period in 2005. This difference wasprimarily due to the following:

·       thepurchase of 43 million shares of our common stock for approximately $1.23billion pursuant to our tender offer during the third quarter of 2006 and anadditional 1.18 million shares for $32 million under a share repurchase plan inthe fourth quarter of 2006;

76

----

·       anincrease in repayments of long-term debt comprised of the repayment of$465 million on the Mirant North America senior secured revolving creditfacility and $990 million of principal payments for debt settled under thePlan; and

·       an increase in proceedsfrom the issuance of long-term debt of approximately $2 billion. Proceeds fromthe issuance of long-term debt in 2006 included $850 million from theMirant North America debt offering that was released from escrow on January 3,2006, $700 million from the Mirant North America senior secured loan, and$465 million drawn on the Mirant North America senior secured revolvingcredit facility. In 2005, proceeds from the issuance of long-term debtrepresented pre-petition letters of credit being drawn upon by counterpartiesand banks.

*Discontinued Operations*

*Operating Activities.  *Cashprovided by operating activities from discontinued operations increased $26million for the year ended December 31, 2006, compared to the same periodin 2005, primarily due to the following:

·       anincrease of $62 million related to a decrease in restricted cash of our WestGeorgia subsidiary; and

·       adecrease of $26 million due to an increase in payments for interest and taxes,primarily due to the expiration of the Sual tax holiday.

*Investing Activities.**  *Net cash usedin investing activities from discontinued operations was $163 million forthe year ended December 31, 2006, compared to cash provided by investingactivities from discontinued operations of $15 million for the same periodin 2005. This difference was primarily due to the following:

·       thepurchase in 2006 of the remaining 5.15% ownership in the Sual generatingfacility for $35 million and the purchase of the remaining 4.26% interestin Pagbilao facility for $40 million;

·       adecrease of $82 million from the sale of assets and investments, primarilyrelated to the sale of the Wrightsville assets in 2005; and

·*      **$30 million in funding by MirantTrinidad Investments during 2006 for the construction and installation of newgenerating units at Point Lisas, Trinidad.*

*Financing Activities.**  *Net cashprovided by financing activities from discontinued operations was$181 million for the year ended December 31, 2006, compared to cashused in financing activities of $142 million for the same period in 2005. Thisdifference was primarily due to the following:

·       anincrease in proceeds from the issuance of $700 million of long-term debtrelated to the Philippines, $100 million by *Mirant Trinidad Investments*,$180 million by Mirant JPSCO Finance LTD and $9 million by GrandBahama Power Company; partially offset by

·       an increase of$678 million of repayments of long-term debt primarily due to therepayment in 2006 of $551 million of existing debt related to Pagbilao andSual, $186 million by JPS, $73 million by Mirant Trinidad Investments and$56 million by West Georgia.

77

----

**2005 versus 2004**

*ContinuingOperations*

*OperatingActivities.*   Cash used in operating activities fromcontinuing operations increased $144 million for the year ended December 31,2005, compared to the same period in 2004 primarily due to the following:

·       adecrease in cash used due to a $277 million increase in gross margin,excluding unrealized gains and losses and TPA amortization. See “Results ofOperations” for additional discussion;

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

·       anincrease in cash used of $117 million due to an increase in professionalservices and administrative expenses related to the bankruptcy proceedings; and

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

*Investing Activities.*   Netcash provided by investing activities from continuing operations was$64 million for the year ended December 31, 2005, compared to cashused in investing activities from continuing operations of $56 million forthe same period in 2004. The difference was primarily due to the following:

·       in2005, we had capital expenditures of $101 million compared to $90 million forthe same period in 2004; and

·       in2005, proceeds from the sales of assets and investments was $165 million andincluded $63 million from the sale of Coyote Springs, $48 million from the saleof a portion of our investment in ICE, and $44 million from the sale of theWyandotte and Mint Farm suspended construction projects. In 2004, proceeds fromthe sales of assets and investments was $45 million and included $42 million inproceeds from the disposal of three natural gas turbines related to suspendedconstruction projects, partially offset by the payment of $12 million to exitour Canadian natural gas transportation agreements and certain natural gascontracts.

*Financing Activities.*   Netcash provided by financing activities from continuing operations was$97 million for the year ended December 31, 2005, compared to cashprovided by financing activities of $316 million for the same period in2004. Proceeds from the issuance of debt, which represented pre-petitionletters of credit being drawn upon by counterparties and banks, decreased by$218 million for the year ended December 31, 2005, compared to the sameperiod in 2004.

*DiscontinuedOperations*

*Operating Activities.  *Cashprovided by operating activities from discontinued operations increased$106 million for the year ended December 31, 2005, compared to thesame period in 2004 primarily due to the following;

·       in2004 our West Georgia and Shady Hills subsidiaries posted collateral of $24million and $21 million, respectively. These amounts remain outstanding in2005;

·       anincrease of $32 million primarily related to a decrease in prepaid transmissioncost balances; and

*·**      *an increase of$28 million in the gross margin of our Caribbean operations.

*Investing Activities.**  *Net cashprovided by investing activities from discontinued operations was $15 millionfor the year ended December 31, 2005, compared to cash used in investingactivities from discontinued operations of $90 million for the same periodin 2004. This difference was primarily due to the following:

·       in2005, we received $85 million from the sale of our Wrightsville generatingfacility; and

78

----

·       in2004, our Philippine business paid $21 million to acquire an additionalinterest in the Sual project after a minority shareholder exercised its putoption.

*Financing Activities.**  *Net cash usedin financing activities from discontinued operations was $142 million for theyear ended December 31, 2005, compared to $343 million for the sameperiod in 2004. This difference was primarily due to the following:

·       in2005, we had proceeds from the issuance of debt related to our Caribbeanbusiness of $25 million compared to proceeds from the issuance of debt relatedto our Caribbean business of $58 million in 2004. In addition, in 2005, ourCaribbean operations received a net $19 million in proceeds from short-termdebt. In 2004, our Jamaican operations repaid $14 million of short-term debt;

·       in2005, we repaid long-term debt of $159 million related to our Philippineoperations and $37 million of debt related to our Caribbean operations. In2004, we repaid long-term debt of $159 million related to our Philippineoperations and $56 million related to our Caribbean operations; and

·       in2005, cash deposited in the debt service reserves related to our Philippineoperations decreased by $25 million as compared to an increase in cashdeposited in the debt service reserves related to our Philippine operations of$154 million in 2004. In 2005, we paid $16 million of dividends tominority interest holders as compared to $17 million in 2004.

***Total Cash, Cash Equivalents and Credit FacilityAvailability***

At December 31, 2006,we have total cash, cash equivalents, and credit facility availability ofapproximately $1.8 billion. The table below sets forth total cash, cashequivalents and availability of credit facilities of Mirant Corporation and itssubsidiaries at December 31, 2006 and December 31, 2005 (inmillions):

| ** **                                                                                                         | ** ** | **At December 31,  2006** | ** ** | **At December 31,  2005** | ** ** |
|--------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------|------------|-------------------------------------|------------|
| Cash and Cash  Equivalents:                                                                                        |       |                                |       |                                |       |   |   |   |   |
| Mirant Corporation                                                                                                 |       |                                | $          | 367                                 |       |   |   | $ | 354 |   |   |
| Mirant Americas Generation                                                                                         |       |                                | —     |                                |       |   | 129 |   |   |
| Mirant Mid-Atlantic                                                                                                |       |                                | 75         |                                |       |   | 276 |   |   |
| Mirant North America                                                                                               |       |                                | 678        |                                |       |   | 19 |   |   |
| Other                                                                                                              |       |                                | 22         |                                |       |   | 290 |   |   |
| Total cash and  cash equivalents                                                                                   |       |                                | 1,142      |                                |       |   | 1,068 |   |   |
| Less: Cash  restricted due to bankruptcy of New York entities and reserved for working  capital and other purposes |       |                                | 115        |                                |       |   | 14 |   |   |
| Total available cash and cash equivalents                                                                          |       |                                | 1,027      |                                |       |   | 1,054 |   |   |
| Available under  credit facilities                                                                                 |       |                                | 796        |                                |       |   | — |   |   |
| Available under  the DIP Facility                                                                                  |       |                                | —     |                                |       |   | 249 |   |   |
| Total cash, cash  equivalents and credit facilities availability                                                   |       |                                | $          | 1,823                               |       |   |   | $ | 1,303 |   |   |
| Cash and cash  equivalents of discontinued operations                                                              |       |                                | $          | 243                                 |       |   |   | $ | 483 |   |   |

 

Mirant North America’s ability to pay dividends isrestricted under the terms of its debt agreements. At December 31, 2006,Mirant North America had distributed to its parent all available cash that waspermitted to be distributed under the terms of its debt agreements. Aftertaking into account the financial results of Mirant North America for thetwelve months ended December 31, 2006, we expect Mirant North America willbe able to distribute approximately $131 million in April 2007.

79

----

Maintainingsufficient liquidity in our business is crucial in order to mitigate the riskof future financial distress to us. Accordingly, we plan on a prospective basisfor the expected liquidity requirements of our business considering the factorslisted below:

·       expectedcollateral posted in support of our business;

·       effectsof market price volatility on collateral posted for economic hedge transactionsand risk management transactions;

·       effectsof market price volatility on fuel pre-payment requirements;

·       seasonaland intra-month working capital requirements; and

·       otherunforeseen events.

Our capital expendituresfor 2007 and 2008 are expected to be approximately $826 million and $802 million,respectively. This forecast does not assume any construction of new generatingunits in the United States during the forecast period. Instead, the currentcapital expenditure program, which is expected to be funded by operating cashflow, focuses on efficiency, safety, reliability, compliance with existing environmentallaws and contract obligations. To comply with the requirements for SO2 and NOxemissions under the Maryland Healthy Air Act, we anticipate total capital expendituresof approximately $1.6 billion through 2009, including $80 millionincurred through 2006.

***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, weare often required to provide trade credit support to our counterparties ormake deposits with brokers. In addition, we are often required to provide cashcollateral or letters of credit 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 that we default, the counterpartycan draw on a letter of credit or apply cash collateral held to satisfy theexisting amounts outstanding under an open contract. At December 31, 2006,our outstanding issued letters of credit totaled $260 million.

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

| ** **                                                       | ** ** | **At December 31,  2006** | ** ** | **At December 31,  2005** | ** ** |
|------------------------------------------------------------------|------------|-------------------------------------|------------|-------------------------------------|------------|
| Continuing operations:                                           |       |                                |       |                                |       |   |   |   |   |
| Cash collateral  posted—energy trading and marketing        |       |                                | $          | 27                                  |       |   |   | $ | 619 |   |   |
| Cash collateral  posted—debt service and rent reserves |       |                                | —     |                                |       |   | 56 |   |   |
| Cash collateral  posted—other operating activities          |       |                                | 13         |                                |       |   | 11 |   |   |
| Letters of  credit—energy trading and marketing             |       |                                | 100        |                                |       |   | 51 |   |   |
| Letters of  credit—debt service and rent reserves           |       |                                | 84         |                                |       |   | — |   |   |
| Letters of  credit—other operating activities               |       |                                | 15         |                                |       |   | 2 |   |   |
|                                                             |       |                                | 239        |                                |       |   | 739 |   |   |
| Discontinued operations:                                         |       |                                |       |                                |       |   |   |   |   |
| Assets held for  sale—cash collateral posted           |       |                                | 187        |                                |       |   | 301 |   |   |
| Assets held for  sale—letters of credit                     |       |                                | 61         |                                |       |   | 56 |   |   |
| Total                                                            |       |                                | $          | 487                                 |       |   |   | $ | 1,096 |   |   |

 

80

----

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

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

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

| ** **                                                                               | ** ** | **Debt Obligations, Off-Balance Sheet Arrangements  and Contractual  Obligations by Year** | ** ** |
|------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                               | ** ** | **Total**                                                                                                                               | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **>5  years** | ** ** |
| Mirant  Mid-Atlantic operating leases                                                    |       | $                                                                                                                                       | 2,246      |   | $ | 112 |   | $ | 121 |   | $ | 142 |   | $ | 140 |   | $ | 134 |   | $ | 1,597 |   |
| Other operating  leases                                                                  |       | 72                                                                                                                                      |       | 9 |   | 9 |   | 9 |   | 9 |   | 8 |   | 28 |   |
| Long-term  debt                                                                          |       | 5,728                                                                                                                                   |       | 397 |   | 261 |   | 260 |   | 260 |   | 1,063 |   | 3,487 |   |
| Claims payable  and estimated claims accrual                                             |       | 28                                                                                                                                      |       | 28 |   | — |   | — |   | — |   | — |   | — |   |
| Purchase  commitments:                                                                   |       |                                                                                                                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Long-term service agreements                                                             |       | 33                                                                                                                                      |       | 3 |   | 1 |   | 2 |   | 2 |   | 2 |   | 23 |   |
| Fuel and transportation commitments                                                      |       | 418                                                                                                                                     |       | 263 |   | 89 |   | 66 |   | — |   | — |   | — |   |
| PPAs                                                                                     |       | 779                                                                                                                                     |       | 53 |   | 52 |   | 52 |   | 54 |   | 58 |   | 510 |   |
| Other purchase commitments                                                               |       | 223                                                                                                                                     |       | 223 |   | — |   | — |   | — |   | — |   | — |   |
| Total excluding liabilities subject to compromise                                        |       | 9,527                                                                                                                                   |       | 1,088 |   | 533 |   | 531 |   | 465 |   | 1,265 |   | 5,645 |   |
| Liabilities subject to compromise                                                        |       | 18                                                                                                                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Discontinued  operations                                                                 |       | 1,895                                                                                                                                   |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Total debt obligations,  off-balance sheet arrangements and contractual obligations |       | $                                                                                                                                       | 11,440     |   |   |   |   |   |   |   |   |   |   |   |   |   |
|                                                                                          |            |                                                                                                                                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Operating leases are off-balance sheet arrangementsand are discussed in Note 16 to our consolidated financial statementscontained elsewhere in this report. These amounts primarily relate to ourminimum lease payments associated with our lease of the Morgantown andDickerson baseload units.

Long-term debt includes the current portion oflong-term debt and long-term debt on the consolidated balance sheets which arediscussed in Note 10 to our consolidated financial statements containedelsewhere in this report. Long-term debt also includes estimated interest ondebt based on a U.S. Dollar LIBOR curve as of January 2, 2007.

Claims payable and estimated claims accrual primarilyconsists of allowed bankruptcy claims, estimated unresolved bankruptcy claimsthat are to be settled in cash and professional fees associated with thebankruptcy proceedings.

Long-term service agreements represent our totalestimated commitments under our long-term service agreements associated withturbines installed or in storage and are discussed in Note 16 to ourconsolidated financial statements contained elsewhere in this report.

Fuel and transportation commitments primarily relateto long-term coal agreements and other fuel purchase and transportationagreements and are discussed in Note 16 to our consolidated financialstatements contained elsewhere in this report. The fair value of certaincontracts is included in price risk management assets or price risk managementliabilities on our consolidated balance sheets.

81

----

PPAs are discussed in Note 17 to our consolidatedfinancial statements contained elsewhere in this report. These amountsrepresent the estimated commitments under the PPAs that Mirant assumed in theasset purchase and sale agreement for the Pepco generating assets. Theestimated commitment is based on the contractual dependable capacity rate atcontractual prices. These contracts are accounted for as derivatives. The fairvalue of certain agreements at December 31, 2006, is included in pricerisk management liabilities on our consolidated balance sheets.

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.

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

Discontinued operationsinclude the debt and obligations related to our planned dispositions of our Philippineand Caribbean businesses and certain U.S. natural gas-fired assets.

**Critical AccountingPolicies and Estimates**

The accountingpolicies described below are considered critical to obtaining an understandingof our consolidated financial statements because their application requiressignificant estimates and judgments by management in preparing our consolidatedfinancial statements. Management’s estimates and judgments are inherentlyuncertain and may differ significantly from actual results achieved. Managementconsiders an accounting estimate to be critical if the followingconditions apply:

·       theestimate requires significant assumptions; and

·       changesin the estimate could have a material effect on our consolidated results ofoperations or financial condition; or,

·       ifdifferent estimates that could have been selected had been used, there could bea material impact on our consolidated results of operations or financialcondition.

We have discussed theselection and application of these accounting estimates with the AuditCommittee of the Board of Directors and our independent auditors. It ismanagement’s view that the current assumptions and other considerations used toestimate amounts reflected in our consolidated financial statements areappropriate. However, actual results can differ significantly from thoseestimates under different assumptions and conditions. The sections belowcontain information about our most critical accounting estimates, as well asthe effects of hypothetical changes in the material assumptions used to developthe estimates.

***Revenue Recognition and Accounting for Energy Tradingand Marketing Activities***

*Natureof Estimates Required.**  *Weutilize two comprehensive accounting models in reporting our consolidatedfinancial position and results of operations as required by GAAP—an accrualmodel and a fair value model. We determine the appropriate model for ouroperations based on applicable accounting standards.

The accrual model has historically been used toaccount for our generation revenue from the sale of energy, capacity andancillary services and to account for distribution revenue from the sale anddistribution of energy. We recognize revenue when earned and collection isprobable as a result of electric power delivered to customers pursuant tocontractual commitments that specify volume, price and delivery requirements.Sales of energy are based on economic dispatch, or they may be ‘as-ordered’ byan ISO, based on member participation agreements, but without an underlyingcontractual commitment. ISO 

82

----

revenues and revenues forsales of energy based on economic-dispatch are recorded on the basis of MWhdelivered, at the relevant day-ahead or real-time prices. Our distributionrevenue is reflected in income (loss) from discontinued operations in theconsolidated statements of operations.

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

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. We currently defer inception gains and losses in accordance withEITF 02-3. Management considers fair value techniques, valuationadjustments related to credit and liquidity and judgments related to theprobability of completing forecasted transactions to be critical accountingestimates. These estimates are considered significant because they are highlysusceptible to change from period to period and are dependent on manysubjective factors. The fair value of derivative contracts is included in pricerisk management assets and liabilities in our consolidated balance sheets.Transactions that do not qualify for accounting under SFAS No. 133, eitherbecause they are not derivatives or because they qualify for a scope exception,are accounted for under accrual accounting as described above.

*KeyAssumptions and Approach Used.**  *Determiningthe fair value of derivatives involves significant estimates based largely onthe mid-point of quoted prices in active markets. The mid-point may varysignificantly from the bid or ask price for some delivery points. If no activemarket exists, we estimate the fair value of certain derivative contracts usingquantitative pricing models. Fair value estimates involve uncertainties andmatters of significant judgment. Our modeling techniques for fair valueestimation include assumptions for market prices, supply and demand marketdata, correlation and volatility. The degree of complexity of our pricingmodels increases for longer duration contracts, contracts with multiple pricingfeatures, option contracts and off-hub delivery points.

The fair value of price risk management assets andliabilities in our consolidated balance sheets is also affected by ourassumptions as to interest rate, counterparty credit risk and liquidity risk.The nominal value of the contracts is discounted using a forward interest ratecurve based on LIBOR. In addition, the fair value of our derivative contractsis reduced to reflect the estimated risk of default of counterparties on theircontractual obligations to us.

*Effectif Different Assumptions Used.**  *Theamounts recorded as revenue or cost of fuel, electricity and other productschange as estimates are revised to reflect actual results and changes in marketconditions or other factors, many of which are beyond our control. Because weuse derivative financial instruments and have not elected cash flow or fairvalue hedge accounting under SFAS No. 133, certain components of ourfinancial statements, including gross margin, operating income and balancesheet ratios, are at times volatile and subject to fluctuations in valueprimarily due to changes in energy and fuel prices. Due to the complexity ofthe models used to value some of the derivative instruments each period, asignificant change in estimate could have a material impact on our results ofoperations and cash flows at the time contracts are ultimately settled. SeeNote 7 to our consolidated financial statements for further information onfinancial instruments related to energy trading and marketing activities.

For additional informationregarding accounting for derivative instruments, see “Item 7A. Quantitative andQualitative Disclosures about Market Risk*.*”

83

----

***Long-Lived Assets***

**Estimated UsefulLives**

*Natureof Estimates Required.**  *Theestimated useful lives of our long-lived assets are used to computedepreciation expense, determine the carrying value of asset retirementobligations, and estimate expected future cash flows attributable to an assetfor the purposes of 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.

*KeyAssumptions and Approach Used.**  *Estimateduseful lives are the mechanism by which we allocate the cost of long-livedassets over the asset’s service period. We perform depreciation studiesperiodically to update changes in estimated useful lives. The actual usefullife of an asset could be affected by changes in estimated or actual commodityprices, environmental regulations, various legal factors, competitive forcesand our liquidity and ability to sustain required maintenance expenditures andsatisfy asset retirement obligations. We use composite depreciation for groupsof similar assets and establish an average useful life for each group ofrelated assets. In accordance with SFAS No. 144, we cease depreciation onlong-lived assets classified as available for sale. See Note 8 to our consolidatedfinancial statements for additional information related to our property, plantand equipment.

*Effect if DifferentAssumptions Used.**  *Thedetermination of estimated useful lives is dependent on subjective factors suchas expected market conditions, commodity prices and anticipated capitalexpenditures. Since composite depreciation rates are used, the actual usefullife of a particular asset may differ materially from the useful life estimatedfor the related group of assets. In the event the useful lives of significantassets were found to be shorter than originally estimated, depreciation expensemay increase, liabilities recognized for future asset retirement obligationsmay be insufficient and impairments in the carrying value of tangible and intangibleassets may result.

**Asset RetirementObligations**

*Natureof Estimates Required.**  *Weaccount for asset retirement obligations under SFAS No. 143 and underFIN 47*.*SFAS No. 143 and FIN 47 require an entity to recognize the fair valueof a liability for conditional and unconditional asset retirement obligationsin the period in which they are incurred. Retirement obligations associatedwith long-lived assets included within the scope of SFAS No. 143 andFIN 47 are those obligations for which a requirement exists under enactedlaws, statutes and written or oral contracts, including obligations arisingunder the doctrine of promissory estoppel. Asset retirement obligations areestimated using the estimated current cost to satisfy the retirementobligation, increased for inflation through the expected period of retirementand discounted back to present value at our credit-adjusted risk free rate. Wehave identified certain retirement obligations within our power generationoperations in the United States and have a noncurrent liability of $41 millionrecorded as of December 31, 2006. These asset retirement obligations areprimarily related to asbestos abatement at some of our generating facilities,the removal of oil storage tanks, equipment on leased property andenvironmental obligations related to the closing of ash disposal sites.

*KeyAssumptions and Approach Used.**  *Thefair value of liabilities associated with asset retirement obligations isestimated by applying a present value calculation to current engineering costestimates of satisfying the obligations. Significant inputs to the presentvalue calculation include current cost estimates, estimated asset retirementdates and appropriate discount rates. Where appropriate, multiple cost and/orretirement scenarios have been probability weighted.

*Effect if DifferentAssumptions Used.**  *Weupdate liabilities associated with asset retirement obligations as significantassumptions change or as relevant new information becomes available. However, 

84

----

due to changes ininflation assumptions, interest rates and asset useful lives, actual future cashflows required to satisfy asset retirement obligations could differ materiallyfrom the current recorded liabilities.

**Asset Impairments**

*Natureof Estimates Required.**  *We evaluateour long-lived assets, including goodwill and indefinite-lived intangible assetsfor impairment in accordance with applicable accounting guidance. The amount ofan impairment charge is calculated as the excess of the asset’s carrying valueover its fair value, which generally represents the discounted expected futurecash flows attributable to the asset or in the case of assets we expect tosell, at fair value less costs to sell.

***Property, Plant andEquipment and Definite-Lived Intangibles***

SFAS No. 144 requires management to recognize animpairment charge if the sum of the undiscounted expected future cash flowsfrom a long-lived asset or definite-lived intangible is less than the carryingvalue of that asset. We evaluate our long-lived assets (property, plant andequipment) and definite-lived intangibles for impairment whenever indicators ofimpairment exist or when we commit to sell the asset. These evaluations oflong-lived assets and definite-lived intangibles may result from significantdecreases in the market price of an asset, a significant adverse change in theextent or manner in which an asset is being used or in its physical condition,a significant adverse change in legal factors or in the business climate thatcould affect the value of an asset, as well as other economic or operationsanalyses. If the carrying amount is not recoverable, an impairment charge isrecorded.

*KeyAssumptions and Approach Used.**  *Thefair value of an asset is the amount at which the asset could be bought or soldin a current transaction between willing parties, that is, other than in aforced or liquidation sale. Quoted market prices in active markets are the bestevidence of fair value and are used as the basis for the measurement, whenavailable. In the absence of quoted prices for identical or similar assets,fair value is estimated using various internal and external valuation methods.The determination of fair value requires management to apply judgment inestimating future energy prices, environmental and maintenance expenditures andother cash flows. Our estimates of the fair value of the assets includesignificant assumptions about the timing of future cash flows, remaining usefullives and selecting a discount rate that reflects the risk inherent in futurecash flows.

On July 11, 2006, we announced the commencementof separate auction processes to dispose of our Caribbean and Philippinebusinesses. The planned sales resulted in the reclassification of thelong-lived assets related to these businesses as held for sale at December 31,2006. On December 11, 2006, we entered into a purchase and sale agreementwith a consortium of The Tokyo Electric Power Company and Marubeni Corporationfor the sale of our Philippine business for a purchase price of $3.424 billionsubject to a working capital adjustment at the closing. As such, we did notrecord an impairment during the period, as the fair value less cost to sell forthe Philippines exceeded the book carrying value. We received non-bindingindicative bids for the Caribbean assets in November. Based on a review of thebids, it remains more-likely-than-not that the Caribbean business will be soldin a single transaction. We determined that no impairment was necessary in thefourth quarter as bids from potential buyers exceeded the carrying value of theassets.

On August 9, 2006, we announced the planned saleof 3,619 MW of the following intermediate and peaking natural gas-fired plants:Zeeland, West Georgia, Shady Hills, Sugar Creek, Bosque and Apex. The plannedsales resulted in the reclassification of the long-lived assets related tothese plants as held for sale at December 31, 2006. During the thirdquarter of 2006, the Company reviewed each asset independently for impairmentthrough the allocation of the fair value of the portfolio. As a result of thisreview, the Company recorded a loss of $396 million to write down the assets totheir estimated fair value.

85

----

On January 15, 2007, we entered into a definitivepurchase and sale agreement with a subsidiary of LS Power Equity Partners I,L.P., LS Power Equity Partners II, L.P. and certain other affiliated funds,(collectively, “LS Power”), for the sale of the six natural gas-fired plantsdiscussed above for a purchase price of $1.407 billion, which includesestimated working capital at the closing. The purchase and sale agreementassigned a value to the Mirant North America plants as a whole, as well as theMirant Americas plants as a whole. The updated fair values along with changesto the working capital calculation in the draft purchase and sale agreementprovided to the bidders, resulted in a reduction to the impairment loss of $21million, which was recorded in the fourth quarter of 2006. The net 2006impairment loss of $375 million was recorded in discontinued operations in ourconsolidated financial statements of operations during the year to decrease thecarrying value of the assets to their fair value less costs to sell.

During the third quarter of 2006, our estimates ofcash flows related to our impairment analysis of our Lovett and Bowlinegeneration facilities required significant judgment related to the outcome ofproperty tax disputes and future tax assessments for Lovett and Bowline. Ourestimates also required prediction of the likelihood of various outcomes ofunresolved matters related to environmental controls and a reasonable economicreturn for our Lovett generation facility. See Note 4 to our consolidatedfinancial statements where further discussed.

*Effect if DifferentAssumptions Used.*   The estimates and assumptionsused to determine whether an impairment exists are subject to a high degree ofuncertainty. The estimated fair value of an asset would change if differentestimates and assumptions were used in our applied valuation techniques,including estimated undiscounted cash flows, discount rates and remaininguseful lives. Due to the nature of the auction process for the assets held forsale, the ultimate sales price at the end of the auction could differ from ourcurrent estimates of fair value determined through discounted cash flows ornon-binding indicative bids for those assets. If actual results are notconsistent with the assumptions used in estimating future cash flows and assetfair values, we may be exposed to additional losses that could be material toour results of operations. See Notes 3 and 4 to our consolidated financialstatements for additional information on impairments.

***Goodwill and Indefinite-Lived Intangible Assets***

The evaluations ofgoodwill and indefinite-lived intangibles are conducted at least annually andperiodically if indicators of impairment are present in accordance with SFAS No. 142.The results of our impairment testing may be affected by a significant adversechange in the extent or manner in which a reporting unit’s assets are beingused, a significant adverse change in legal factors or in the business climatethat could affect the value of a reporting unit, as well as other economic oroperational analyses. If the carrying amount of the reporting unit is notrecoverable, an impairment charge is recorded. The amount of the impairmentcharge, if an impairment exists, is calculated as the difference between thefair value of the goodwill and its carrying value. We perform our annualassessment of goodwill at October 31 and whenever contrary evidence existsas to the recoverability of goodwill. We impaired our remaining goodwill of$582 million in 2004. At December 31, 2006, our entire goodwill balance of$6 million is included in assets held for sale.

***Equity Method Investments***

Investments accounted forby the equity method are reviewed for impairment in accordance withAPB 18, which requires that a loss in value of an investment that is otherthan a temporary decline should be recognized. We identify and measure otherthan temporary losses in the value of equity investments based upon acomparison of fair value to carrying value. At December 31, 2006, ourentire equity-method investments balance of $224 million is included in assetsheld for sale.

86

----

***Stock-Based Compensation***

*Natureof Estimates Required.**  *Weaccount for stock-based compensation under SFAS No. 123R. SFAS No. 123Rrequires companies to recognize in the income statement the grant-date fairvalue of stock options and other equity-based compensation issued to employees.We consider the assumptions inherent in our valuation and calculation ofcompensation expense critical to the financial statements because theunderlying assumptions are subject to significant judgment and the resultingcompensation expense is a new expense item in 2006 and may be material to ourresults of operations.

*Assumptions and ApproachUsed.**  *TheBlack-Scholes option-pricing model was used to measure the grant-date fairvalue of the stock options. The Black-Scholes model requires certainassumptions concerning implied volatility, dividend yield, expected term, andgrant price. These assumptions have a significant impact on the option’s fairvalue. The expected term and expected volatility often have the most impact onthe fair value of the option. The inputs to the Black-Scholes model that weused for the year ended December 31, 2006, are detailed below:

| ** **                   | ** ** | **Range**     | ** ** | **Weighted Average** | ** ** |
|------------------------------|------------|---------------|------------|---------------------------|------------|
| Expected  volatility         |       | 21 - 37       | %          |                      | 31.64      | % |   |
| Expected  dividends          |       | 0             | %          |                      | 0          | % |   |
| Expected term:               |       |          |       |                      |       |   |   |
| Service condition awards     |       | 5.2 - 6 years |       |                      | 5.9 years  |   |   |
| Performance condition awards |       | 3 years       |       |                      | 3 years    |   |   |
| Risk-free rate               |       | 4.3 - 5.1     | %          |                      | 4.5        | % |   |

 

Pursuant to the Plan, all shares of Mirant’s oldcommon stock were cancelled, and shares of Mirant’s new common stock wereissued. Due to Mirant’s bankruptcy and other factors, historical informationconcerning the stock price volatility for purposes of valuing stock optiongrants was not sufficient indication of expected stock price volatility foroptions granted in the months immediately following Mirant’s emergence frombankruptcy. Therefore, the implied volatility derived from peer group companieswas used as the basis for valuing the stock options granted through September 30,2006. Beginning in the fourth quarter 2006, we re-evaluated the use of impliedvolatility derived from peer group companies and determined that sufficientevidence existed to place exclusive reliance on Mirant’s own implied volatilityof its traded options in accordance with SAB No. 107. Additionally, weassumed there would be no dividends paid over the five-to-six year expectedterm of the awards. Due to the lack of exercise history for the Company, thesimplified method for estimating expected term has been used in accordance withSAB No. 107, to the extent applicable. For performance condition awards,we utilized the contractual term as the expected term. The grant price used inthe Black-Scholes option pricing model is the New York Stock Exchange closingprice of our common stock on the day of grant. The risk-free rate for periodswithin the contractual term of the stock option is based on the U.S. Treasuryyield curve in effect at the time of the grant.

We have determined that all of the awards granted in2006 qualify for equity accounting treatment under SFAS No. 123R. Equityaccounting treatment requires awards to be measured at the grant-date fair valuewith compensation expense recognized over the award’s requisite service period,with no subsequent re-measurement. Compensation cost has been adjusted for anestimated forfeiture rate of 3%. As we accumulate participant history, theforfeiture rate will be adjusted for actual forfeitures. During the year ended December 31,2006, we recognized approximately $16 million of compensation expenserelated to service condition awards and $1 million related to performancecondition awards.

*Effectif Different Assumptions Used.**  *Asa result of the uncertainty, complexity and judgment involved in the valuationof stock options, the assumptions related to share-based payment accountingcould result in material changes to our financial statements if differentassumptions are used. 

87

----

Compensation expenserecognized for stock options would differ to the extent other assumptions wereused in the valuation of options. Generally, as the expected term, expectedvolatility and risk-free rate increase, the option’s fair value increases dueto greater upside potential of the stock. However, as the expected dividendyield increases, the option’s fair value may decrease as option holderstypically do not receive dividends.

See Note 14 to ourconsolidated financial statements for further information on stock-basedcompensation.

***Income Taxes***

*Natureof Estimates Required.**  *Wecurrently record a tax provision for foreign, state and federal income taxesincluding any alternative minimum tax as appropriate. We also recognizedeferred tax assets and liabilities based on the difference between thefinancial statement carrying amounts and the tax basis of the assets andliabilities. When necessary, deferred tax assets are reduced by a valuationallowance to reflect the amount that is estimated to be recoverable. Inassessing the recoverability of our deferred tax assets, we consider whether itis likely that some portion or all of the deferred tax assets will be realized.See Note 13 to our consolidated financial statements for additional informationregarding our deferred tax assets and the application of our NOLs.

*KeyAssumptions and Approach Used.*   The determinationof a valuation allowance requires significant judgment as to the generation oftaxable income during future periods for which temporary differences areexpected to be deductible. In making this determination, management considersall available positive and negative evidence affecting specific deferred taxassets, including our past and anticipated future performance, the reversal ofdeferred tax liabilities and the implementation of tax planning strategies.

Additionally, we have contingent liabilities relatedto tax uncertainties arising in the ordinary course of business. Weperiodically assess our contingent liabilities in connection with these uncertaintiesbased on the latest information available. For those uncertainties where it isprobable that a loss has occurred and the loss or range of loss can bereasonably estimated, a liability is recognized in the financial statements.The recognition of contingent losses for tax uncertainties requires managementto make significant assumptions about the expected outcomes of certain taxcontingencies. See Note 13 to our consolidated financial statements forinformation about our adoption of FIN 48.

*Effectif Different Assumptions Used.  *The ultimateutilization of our remaining NOLs will depend on several factors, including ourfuture financial performance and certain tax elections. Specifically, ourutilization of NOLs will be affected by whether we elect NOL treatmentunder Internal Revenue Code Section (“§”) 382(l)(5) or§ 382(l)(6). We currently anticipate that the treatment under § 382(l)(5) ofthe Internal Revenue Code will apply to Mirant going forward. Under thattreatment, Mirant would have use of its NOLs as long as there is not a changeof ownership (broadly defined as 50 percent change of “five percent”shareholders) within two years of emergence from bankruptcy. The § 382(l)(5) treatmentrequires us to reduce our NOLs by 1.1 billion due to interest accrued on debtsettled with stock for the three years prior to emergence. Under§ 382(l)(6), we would be subject to an annual limitation on use of NOLs.We will make the § 382(l)(5) or § 382(l)(6) election in our2006 annual tax return to be filed in 2007. Given the likelihood that we willelect under 382 (l)(5) we have adjusted various deferred income tax itemsincluding the NOLs.

We continue to be underaudit for multiple years by taxing authorities in various jurisdictions.Considerable judgment is required to determine the tax treatment of particularitems that involves interpretations of complex tax laws. A tax liability hasbeen recorded for certain filing positions with respect to which the outcome isuncertain and the effect is estimable. Such liabilities are based on 

88

----

judgmentand it can take many years between the time liability is recorded and therelated filing position is no longer subject to question.

***Loss Contingencies***

*Natureof Estimates Required.**  *Werecord loss contingencies when it is probable that a liability has beenincurred and the amount can be reasonably estimated. We consider losscontingency estimates to be critical accounting estimates because they entailsignificant judgment regarding probabilities and ranges of exposure, and theultimate outcome of the proceedings is unknown and could have a materialadverse effect on our results of operations, financial condition and cashflows. We currently have loss contingencies related to litigation,environmental matters, tax matters and others.

*KeyAssumptions and Approach Used.**  *Thedetermination of a loss contingency requires significant judgment as to theexpected outcome of each contingency in future periods. In making thedetermination as to potential losses and probability of loss, we consider allavailable positive and negative evidence including the expected outcome ofpotential litigation. We record our best estimate of a loss, or the low end ofour range if no estimate is better than another estimate within a range ofestimates, when the loss is considered probable. As additional informationbecomes available, we reassess the potential liability related to thecontingency and revise our estimates. In our evaluation of legal matters,management holds discussions with applicable legal counsel and relies onanalysis of case law and legal precedents.

*Effect if DifferentAssumptions Used.**  *Revisionsin our estimates of potential liabilities could materially affect our resultsof operations, and the ultimate resolution may be materially different from theestimates that we make.

***Litigation***

See “Item 3. Legal Proceedings” and Note 23 toour consolidated financial statements for further information related to ourlegal proceedings.

We are currently involved in certain legalproceedings. We estimate the range of liability through discussions withapplicable legal counsel and analysis of case law and legal precedents. Werecord our best estimate of a loss, or the low end of our range if no estimateis better than another estimate within a range of estimates, when the loss isconsidered probable. As additional information becomes available, we reassessthe potential liability related to our pending litigation and revise ourestimates. Revisions in our estimates of the potential liability couldmaterially affect our results of operations, and the ultimate resolution may bematerially different from the estimates that we make.

89

----

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

We are exposed to marketrisks associated with commodity prices, interest rates, credit risk and, to alesser extent, foreign currency exchange rates.

**Commodity PriceRisk**

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

The financial performance of our power generationbusiness is influenced by the difference between the variable cost ofconverting a source fuel, such as natural gas, oil or coal, into electricity,and the revenue we receive from the sale of that electricity. The differencebetween the cost of a specific fuel used to generate one MWh of electricity andthe market value of the electricity generated is commonly referred to as the “conversionspread.” Absent the effects of our price risk management activities, theoperating margins that we realize are equal to the difference between theaggregate conversion spread and the cost of operating the facilities thatproduce 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 othergeneration facilities in the regions in which we operate, facility outages,weather and general economic conditions. As a result of these influences, thecost of fuel and electricity prices do not always change in the same magnitudeor direction, which results in conversion spreads for a particular generationfacility widening or narrowing (or becoming negative) over time.

Through our asset management activities, we enter intoa variety of exchange-traded and OTC 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 also utilizesimilar contracts in markets where we have a physical presence to attempt togenerate incremental gross margin.

Derivative energy contracts required to be reflectedat fair value are presented as price risk management assets and liabilities inthe accompanying consolidated balance sheets. The net changes in their marketvalues are recognized in income in the period of change. The fair value of thepower purchase agreements which we account for as derivatives are included inprice risk management assets and liabilities on the accompanying consolidatedbalance sheets at December 31, 2006 and 2005. For a discussion of thelitigation involving the Back-to-Back Agreement, see Note 23 to theconsolidated financial statements. The determination of fair value considersvarious factors, including closing exchange or OTC market price quotations,time value, credit quality, liquidity and volatility factors underlying optionsand contracts.

The volumetric weighted average maturity, or weightedaverage tenor, of the price risk management portfolio, excluding theBack-to-Back Agreement, at December 31, 2006, was eleven months. The netnotional amount, or net short position, of the price risk management assets andliabilities, excluding the Back-to-Back Agreement, at December 31, 2006,was approximately 24 million equivalent MWh.

90

----

Thefollowing table provides a summary of the factors affecting the change in netfair value of the price risk management asset and (liability) accounts in 2006(in millions):

| ** **                                             | ** ** | **Proprietary  Trading** | ** ** | **Asset  Management** | ** ** | **Back-to-  Back  Agreement** | ** ** | **Total** | ** ** |
|--------------------------------------------------------|------------|--------------------------|------------|-----------------------|------------|-------------------------------|------------|-----------|------------|
| Net fair value of  portfolio at December 31, 2005 |       |                     | $          | 41                    |       |                          |       | $         | (188       | ) |   |   | $ | (443 | ) |   | $ | (590 | ) |
| Gains (Losses)  recognized in the period, net          |       |                     | 29         |                  |       |                          | 412        |      |       |   | (8 | ) |   | 433 |   |
| Contracts settled  during the period, net              |       |                     | (23        | )                     |       |                          | 219        |      |       |   | 26 |   |   | 222 |   |
| Back-to-Back  Agreement                                |       |                     | —     |                  |       |                          | —     |      |       |   | — |   |   | — |   |
| Net fair value of  portfolio at December 31, 2006 |       |                     | $          | 47                    |       |                          |       | $         | 443        |   |   |   | $ | (425 | ) |   | $ | 65 |   |

 

Thefair values of our price risk management assets and liabilities, net of creditreserves, as of December 31, 2006, are as follows (in millions):

| ** **                       | ** ** | **Net Price Risk Management** | ** ** |
|----------------------------------|------------|----------------------------------------------|------------|
| ** **                       | ** ** | **Assets**                                   | ** ** | **Liabilities** | ** ** | **Net Fair Value at** | ** ** |
| ** **                       | ** ** | **Current**                                  | ** ** | **Noncurrent** | ** ** | **Current** | ** ** | **Noncurrent** | ** ** | **December 31, 2006** | ** ** |
| Electricity                      |       |                                         | $          | 603 |   |   |   | $ | 99 |   |   |   | $ | (247 | ) |   |   | $ | (8 | ) |   |   | $ | 447 |   |   |
| Back-to-Back  Agreement          |       |                                         | —     |   |   |   | — |   |   |   | (36 | ) |   |   | (389 | ) |   |   | (425 | ) |   |
| Natural Gas                      |       |                                         | 21         |   |   |   | 1 |   |   |   | (26 | ) |   |   | (2 | ) |   |   | (6 | ) |   |
| Oil                              |       |                                         | 83         |   |   |   | — |   |   |   | (10 | ) |   |   | (29 | ) |   |   | 44 |   |   |
| Coal                             |       |                                         | 13         |   |   |   | — |   |   |   | (3 | ) |   |   | — |   |   |   | 10 |   |   |
| Other, including  credit reserve |       |                                         | (5         | ) |   |   | — |   |   |   | — |   |   |   | — |   |   |   | (5 | ) |   |
| Total                            |       |                                         | $          | 715 |   |   |   | $ | 100 |   |   |   | $ | (322 | ) |   |   | $ | (428 | ) |   |   | $ | 65 |   |   |

 

Thefollowing table represents the net price risk management assets and liabilitiesby tenor as of December 31, 2006 (in millions):

| ** **                | ** ** | **Back-to-Back  Agreement** | ** ** | **All Other  Agreements** | ** ** |
|---------------------------|------------|-----------------------------|------------|--------------------------------|------------|
| 2007                      |       |                        | $          | (36                            | )          |   |   | $ | 429 |   |   |
| 2008                      |       |                        | (31        | )                              |       |   | 13 |   |   |
| 2009                      |       |                        | (30        | )                              |       |   | 40 |   |   |
| 2010                      |       |                        | (36        | )                              |       |   | 9 |   |   |
| Thereafter                |       |                        | (292       | )                              |       |   | (1 | ) |   |
| Net (liabilities)  assets |       |                        | $          | (425                           | )          |   |   | $ | 490 |   |   |

 

**Value at Risk**

Our Risk Management Policy prohibits the trading ofcertain products, e.g., natural gas liquids and pulp and paper and containslimits and restrictions related to our asset management and proprietary tradingactivities.

We manage the price risk associated with assetmanagement activities through a variety of methods. Our Risk Management Policyrequires that asset management activities are restricted to only thoseactivities that are risk-reducing in nature. To ensure compliance with thisrestriction, each transaction is classified as either a conversion spreadtransaction or fuel oil management transaction. Each conversion spreadtransaction is tested at the transaction level to ensure that each individualtransaction executed is risk reducing relative to the overall asset position.Fuel oil management activities include management of physical fuel oil burns,physical fuel oil infrastructure and time and product spread positions. Whilethese fuel oil activities are designed primarily to manage the risk associatedwith physical specifications and 

91

----

availability of fuel oilfor the power plants, at any given time the fuel oil portfolio contains openmarket price risk. Each individual fuel oil transaction is not tested for riskreduction, but these activities are tested in aggregate to ensure that theoverall activity is risk reducing. While the net result of these transactionsis risk reducing, the timing of the roll-off could result in volatility in thegross margin results. To ensure that fuel oil management activities arerisk-reducing in aggregate, a VaR limit of $5 million was established in the RiskManagement Policy effective December 14, 2006.

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

Our Risk Management Policy sets a VaR limit withrespect to our proprietary trading activities of $7.5 million. See “CriticalAccounting Policies and Estimates” for accounting treatment for assetmanagement and proprietary trading activities.

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

*Interest Rate Risk*

We have several loans thatprovide for a variable rate of interest. Interest expense on such borrowings issensitive to changes in the market rate of interest.

Ourtotal debt from continuing operations is subject to variable interest ratesthrough either the Mirant North America Term Loan or Revolving credit facility,assuming they are fully drawn, is approximately $1.5 billion. Our total debtrecorded in liabilities held for sale subject to variable interest rates onterm loans is approximately $144 million. A 1% per annum increase in theaverage market rate would result in an increase in our annual interest expenseof approximately $15 million for continuing operations and $2 million fordiscontinued operations.

*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. The Risk Oversight Committee includes theChief Financial Officer and management’s representatives from severalfunctional areas. We measure credit risk as the loss we would record if ourcustomers failed to perform pursuant to the terms of their contractualobligations less the value of collateral held by us, if any, to cover suchlosses. We use published ratings of customers, as well as our internalanalysis, to guide us in the process of setting credit levels, risk limits andcontractual arrangements including master netting agreements. Where externalratings are not available, we rely on our internal assessments of customers.

92

----

*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 and collectionrisk is accounted for when we establish our allowance for bad debts. We managethis risk using the same techniques and processes used in credit risk discussedabove.

*Foreign CurrencyRisk*

From time to time, we have used currency swaps andcurrency forwards to hedge our net investments in certain foreign subsidiaries.Gains or losses on these derivatives are designated as hedges of netinvestments and are offset against the foreign currency translation gains orlosses recorded in OCI relating to these investments. Occasionally, we usecurrency forwards to offset the effect of exchange rate fluctuations onforecasted transactions denominated in a foreign currency. We did not have anyforeign exchange contracts outstanding at December 31, 2006, that aredesignated as hedges of our investments in foreign countries or otherwise.

93

----

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

**MIRANT CORPORATIONAND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS**

| ** **                                                                                    | ** ** | **For the Years Ended December 31,**     | ** ** |
|-----------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                                                                    | ** ** | **2006**                                                          | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                    | ** ** | **(in millions, except per share data)** | ** ** |
| Operating  revenues                                                                           | ** ** |                                                              | **$**      | **3,103** |   |   | $ | 2,646 |   |   | $ | 3,248 |   |   |
| Cost of fuel,  electricity and other products                                                 | ** ** |                                                              | **1,156**  |   |   | 1,800 |   |   | 2,159 |   |   |
| **Gross  Margin**                                                                             | ** ** |                                                              | **1,947**  |   |   | 846 |   |   | 1,089 |   |   |
| **Operating Expenses:**                                                                       |       |                                                              |       |   |   |   |   |   |   |   |   |
| Operations and  maintenance                                                                   | ** ** |                                                              | **609**    |   |   | 698 |   |   | 718 |   |   |
| Depreciation and  amortization                                                                | ** ** |                                                              | **137**    |   |   | 135 |   |   | 137 |   |   |
| Impairment losses                                                                             | ** ** |                                                              | **119**    |   |   | 9 |   |   | 9 |   |   |
| Loss (gain) on  sales of assets, net                                                          | ** ** |                                                              | **(49**    | **)** |   | 17 |   |   | 49 |   |   |
| Total operating expenses                                                                      | ** ** |                                                              | **816**    |   |   | 859 |   |   | 913 |   |   |
| **Operating  Income (Loss)**                                                                  | ** ** |                                                              | **1,131**  |   |   | (13 | ) |   | 176 |   |   |
| **Other Expense (Income), net:**                                                              |       |                                                              |       |   |   |   |   |   |   |   |   |
| Interest expense                                                                              | ** ** |                                                              | **289**    |   |   | 1,404 |   |   | 18 |   |   |
| Gain on sales of  investments, net                                                            | ** ** |                                                              | **(76**    | **)** |   | (45 | ) |   | — |   |   |
| Interest income                                                                               | ** ** |                                                              | **(76**    | **)** |   | (9 | ) |   | (2 | ) |   |
| Other, net                                                                                    | ** ** |                                                              | **(38**    | **)** |   | 63 |   |   | (66 | ) |   |
| Total other expense (income), net                                                             | ** ** |                                                              | **99**     |   |   | 1,413 |   |   | (50 | ) |   |
| **Income  (Loss) From Continuing Operations Before Reorganization Items,  Income Taxes** | ** ** |                                                              | **1,032**  |   |   | (1,426 | ) |   | 226 |   |   |
| Reorganization  items, net                                                                    | ** ** |                                                              | **(163**   | **)** |   | (18 | ) |   | 227 |   |   |
| Provision  (Benefit) for income taxes                                                         | ** ** |                                                              | **(578**   | **)** |   | (18 | ) |   | (2 | ) |   |
| **Income  (Loss) From Continuing Operations**                                                 | ** ** |                                                              | **1,773**  |   |   | (1,390 | ) |   | 1 |   |   |
| **Income  (Loss) From Discontinued Operations, net**                                          | ** ** |                                                              | **91**     |   |   | 99 |   |   | (477 | ) |   |
| **Income  (Loss) Before Cumulative Effect of Changes in Accounting Principles**               | ** ** |                                                              | **1,864**  |   |   | (1,291 | ) |   | (476 | ) |   |
| **Cumulative  Effect of Changes in Accounting Principles**                                    |       |                                                              | —     |   |   | (16 | ) |   | — |   |   |
| **Net  Income (Loss)**                                                                        | ** ** |                                                              | **$**      | **1,864** |   |   | $ | (1,307 | ) |   | $ | (476 | ) |   |
| **Basic EPS:**                                                                                | ** ** |                                                              | ** ** |   |   |   |   |   |   |   |   |
| Basic EPS from  continuing operations                                                         | ** ** |                                                              | **$**      | **6.22** |   |   |   |   |   |   |   |   |
| Basic EPS from  discontinued operations                                                  | ** ** |                                                              | **0.32**   |   |   |   |   |   |   |   |   |
| Basic EPS                                                                                     | ** ** |                                                              | **$**      | **6.54** |   |   |   |   |   |   |   |   |
| **Diluted EPS:**                                                                              | ** ** |                                                              | ** ** |   |   |   |   |   |   |   |   |
| Diluted EPS from  continuing operations                                                  | ** ** |                                                              | **$**      | **5.97** |   |   |   |   |   |   |   |   |
| Diluted EPS from  discontinued operations                                                     | ** ** |                                                              | **0.31**   |   |   |   |   |   |   |   |   |
| Diluted EPS                                                                                   | ** ** |                                                              | **$**      | **6.28** |   |   |   |   |   |   |   |   |
| Average shares  outstanding                                                                   | ** ** |                                                              | **285**    |   |   |   |   |   |   |   |   |
| Effect of  dilutive securities                                                                | ** ** |                                                              | **12**     |   |   |   |   |   |   |   |   |
| Average shares  outstanding assuming dilution                                                 | ** ** |                                                              | **297**    |   |   |   |   |   |   |   |   |

 

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

F-2

----

**MIRANT CORPORATION AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS**

| ** **                                                                                                                                                                                                                                                                                                   | ** ** | **December 31,**  | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------|------------|
| ** **                                                                                                                                                                                                                                                                                                   | ** ** | **2006**               | ** ** | **2005** | ** ** |
| ** **                                                                                                                                                                                                                                                                                                   | ** ** | **(in millions)** | ** ** |
| **ASSETS**                                                                                                                                                                                                                                                                                                   | ** ** |                   |       |   |   |
| **Current Assets:**                                                                                                                                                                                                                                                                                          | ** ** |                   |       |   |   |
| Cash and cash equivalents                                                                                                                                                                                                                                                                                    | ** ** | **$**                  | **1,142**  |   | $ | 1,068 |   |
| Funds on deposit                                                                                                                                                                                                                                                                                             | ** ** | **235**                |       | 1,542 |   |
| Receivables, net                                                                                                                                                                                                                                                                                             | ** ** | **381**                |       | 589 |   |
| Price risk management assets                                                                                                                                                                                                                                                                                 | ** ** | **715**                |       | 602 |   |
| Inventories                                                                                                                                                                                                                                                                                                  | ** ** | **288**                |       | 275 |   |
| Prepaid expenses                                                                                                                                                                                                                                                                                             | ** ** | **142**                |       | 142 |   |
| Assets held for sale                                                                                                                                                                                                                                                                                         | ** ** | **4,972**              |       | 5,584 |   |
| Deferred income taxes                                                                                                                                                                                                                                                                                        | ** ** | **110**                |       | — |   |
| Other                                                                                                                                                                                                                                                                                                        |       | —                 |       | 30 |   |
| Total current assets                                                                                                                                                                                                                                                                                         | ** ** | **7.985**              |       | 9,832 |   |
| **Property, Plant and Equipment, net**                                                                                                                                                                                                                                                                       | ** ** | **2,212**              |       | 2,328 |   |
| **Noncurrent Assets:**                                                                                                                                                                                                                                                                                       | ** ** |                   |       |   |   |
| Intangible assets, net                                                                                                                                                                                                                                                                                       | ** ** | **214**                |       | 225 |   |
| Price risk management assets                                                                                                                                                                                                                                                                                 | ** ** | **100**                |       | 115 |   |
| Deferred income taxes                                                                                                                                                                                                                                                                                        | ** ** | **660**                |       | 132 |   |
| Prepaid rent                                                                                                                                                                                                                                                                                                 | ** ** | **218**                |       | 208 |   |
| Other                                                                                                                                                                                                                                                                                                        | ** ** | **147**                |       | 72 |   |
| Total noncurrent assets                                                                                                                                                                                                                                                                                      | ** ** | **1,339**              |       | 752 |   |
| **Total Assets**                                                                                                                                                                                                                                                                                             | ** ** | **$**                  | **11,536** |   | $ | 12,912 |   |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                                                                                                                                                                                                                                               | ** ** |                   |       |   |   |
| **Current Liabilities:**                                                                                                                                                                                                                                                                                     | ** ** |                   |       |   |   |
| Current portion of long-term debt                                                                                                                                                                                                                                                                            | ** ** | **$**                  | **142**    |   | $ | 3 |   |
| Claims payable and estimated claims accrual                                                                                                                                                                                                                                                                  | ** ** | **28**                 |       | 1,903 |   |
| Accounts payable and accrued liabilities                                                                                                                                                                                                                                                                     | ** ** | **425**                |       | 582 |   |
| Price risk management liabilities                                                                                                                                                                                                                                                                            | ** ** | **322**                |       | 849 |   |
| Liabilities held for sale                                                                                                                                                                                                                                                                                    | ** ** | **2,205**              |       | 2,075 |   |
| Deferred income taxes                                                                                                                                                                                                                                                                                        | ** ** | **49**                 |       | 132 |   |
| Accrued taxes and other                                                                                                                                                                                                                                                                                      | ** ** | **88**                 |       | 202 |   |
| Total current liabilities                                                                                                                                                                                                                                                                                    | ** ** | **3,259**              |       | 5,746 |   |
| **Noncurrent Liabilities:**                                                                                                                                                                                                                                                                                  | ** ** |                   |       |   |   |
| Long-term debt                                                                                                                                                                                                                                                                                               | ** ** | **3,133**              |       | 2,579 |   |
| Price risk management liabilities                                                                                                                                                                                                                                                                            | ** ** | **428**                |       | 458 |   |
| Asset retirement obligations                                                                                                                                                                                                                                                                                 | ** ** | **41**                 |       | 34 |   |
| Pension and post-retirement obligations                                                                                                                                                                                                                                                                      | ** ** | **204**                |       | 208 |   |
| Other                                                                                                                                                                                                                                                                                                        | ** ** | **10**                 |       | 13 |   |
| Total noncurrent liabilities                                                                                                                                                                                                                                                                                 | ** ** | **3,816**              |       | 3,292 |   |
| **Liabilities Subject to Compromise**                                                                                                                                                                                                                                                                        | ** ** | **18**                 |       | 18 |   |
| **Commitments and Contingencies**                                                                                                                                                                                                                                                                            | ** ** |                   |       |   |   |
| **Stockholders’  Equity:**                                                                                                                                                                                                                                                                              | ** ** |                   |       |   |   |
| Preferred stock, par value $.01 per share; authorized  100,000,000 in 2006 issued and 0 outstanding                                                                                                                                                                                                          | ** ** | **—**             |       | — |   |
| Common stock, par value $.01 per share, authorized  1.5 billion shares, issued 300,200,197 and 300,000,000 at  December 31, 2006 and December 31, 2005, respectively, and  outstanding 256,017,187 shares and 300,000,000 at December 31, 2006 and  December 31, 2005, respectively | ** ** | **3**                  |       | 3 |   |
| Treasury stock, at cost 44,183,010 shares and 0  shares at December 31, 2006 and December 31, 2005, respectively                                                                                                                                                                                   | ** ** | **(1,261**             | )          | — |   |
| Additional paid-in capital                                                                                                                                                                                                                                                                                   | ** ** | **11,317**             |       | 11,298 |   |
| Accumulated deficit                                                                                                                                                                                                                                                                                          | ** ** | **(5,598**             | )          | (7,462 | ) |
| Accumulated other comprehensive income                                                                                                                                                                                                                                                                       | ** ** | **(18**                | )          | 17 |   |
| Total stockholders’ equity                                                                                                                                                                                                                                                                              | ** ** | **4,443**              |       | 3,856 |   |
| **Total  Liabilities and Stockholders’ Equity**                                                                                                                                                                                                                                                         | ** ** | **$**                  | **11,536** |   | $ | 12,912 |   |

 

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

F-3

----

**MIRANT CORPORATION AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)**

| ** **                                           | ** ** | ** **             | ** ** | ** **   | ** ** | ** **     | ** ** | ** **      | ** ** | **Accumulated**        | ** ** |
|------------------------------------------------------|------------|------------------------|------------|--------------|------------|----------------|------------|-----------------|------------|------------------------|------------|
| ** **                                           | ** ** | ** **             | ** ** | ** **   | ** ** | **Additional** | ** ** | ** **      | ** ** | **Other**              | ** ** |
| ** **                                           | ** ** | **Common**             | ** ** | **Treasury** | ** ** | **Paid-In**    | ** ** | **Accumulated** | ** ** | **Comprehensive**      | ** ** |
| ** **                                           | ** ** | **Stock**              | ** ** | **Stock**    | ** ** | **Capital**    | ** ** | **Deficit**     | ** ** | **Income (Loss)** | ** ** |
| ** **                                           | ** ** | **(in millions)** | ** ** |
| **Balance,  December 31, 2003**                 |       |                   | $          | 4            |       |           | $          | (2              | )          |                   | $          | 4,918 |   |   |   | $ | (5,679 | ) |   |   | $ | (64 | ) |   |
| Net loss                                             |       |                   | —     |         |       | —         |       |            | —     |                   |       |   | (476 | ) |   |   | — |   |   |
| Other comprehensive income                           |       |                   | —     |         |       | —         |       |            | —     |                   |       |   | — |   |   |   | (19 | ) |   |
| **Balance,  December 31, 2004**                 |       |                   | 4          |         |       | (2             | )          |            | 4,918      |                   |       |   | (6,155 | ) |   |   | (83 | ) |   |
| Net loss                                             |       |                   | —     |         |       | —         |       |            | —     |                   |       |   | (1,307 | ) |   |   | — |   |   |
| Cancellation of pre-reorganization common stock |       |                   | (4         | )            |       | 2              |       |            | (4,918     | )                      |       |   | — |   |   |   | — |   |   |
| Issuance of post-reorganization common stock    |       |                   | 3          |         |       | —         |       |            | 11,298     |                   |       |   | — |   |   |   | — |   |   |
| Other comprehensive loss                             |       |                   | —     |         |       | —         |       |            | —     |                   |       |   | — |   |   |   | 100 |   |   |
| **Balance,  December 31, 2005**                 |       |                   | 3          |         |       | —         |       |            | 11,298     |                   |       |   | (7,462 | ) |   |   | 17 |   |   |
| Net income                                           |       |                   | —     |         |       | —         |       |            | —     |                   |       |   | 1,864 |   |   |   | — |   |   |
| Stock repurchase                                     |       |                   | —     |         |       | (1,261         | )          |            | —     |                   |       |   | — |   |   |   | — |   |   |
| Stock-based compensation                             |       |                   | —     |         |       | —         |       |            | 17         |                   |       |   | — |   |   |   | — |   |   |
| Exercise of warrants                                 |       |                   | —     |         |       | —         |       |            | 2          |                   |       |   | — |   |   |   | — |   |   |
| Other comprehensive income                           |       |                   | —     |         |       | —         |       |            | —     |                   |       |   | — |   |   |   | (25 | ) |   |
| Adoption of SFAS No. 158, net of tax            |       |                   | —     |         |       | —         |       |            | —     |                   |       |   | — |   |   |   | (10 | ) |   |
| **Balance, December 31, 2006**                  | ** ** | ** **             | **$**      | **3**        |       | ** **     | **$**      | **(1,261**      | **)**      | ** **             | **$**      | **11,317** |   | ** ** | ** ** | **$** | **(5,598** | **)** | ** ** | ** ** | **$** | **(18** | **)** | ** ** |

 

**MIRANT CORPORATION AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)**

| ** **                                                   | ** ** | **For the Years Ended  December 31,** | ** ** |
|--------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2006**                                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                                    | ** ** |
| **Net  Income (Loss)**                                       | ** ** | **$**                                                     | **1,864**  |   | $ | (1,307 | ) | $ | (476 | ) |
| **Other comprehensive income  (loss), net of tax**           | ** ** | ** **                                                |       |   |   |   |   |
| Cumulative translation adjustment                            | ** ** | **2**                                                     |       | 74 |   | (17 | ) |
| Unrealized gains on available-for-sale securities            | ** ** | **(27**                                                   | **)**      | 27 |   | — |   |
| Reclassification of investment unrealized gains to  earnings | ** ** | **—**                                                |       | — |   | (7 | ) |
| Unrealized gain on investments                               | ** ** | **—**                                                |       | — |   | 5 |   |
| Other                                                        |       | —                                                    |       | (1 | ) | — |   |
| Other comprehensive income (loss), net of tax                | ** ** | **(25**                                                   | **)**      | 100 |   | (19 | ) |
| **Total Comprehensive Income  (Loss)**                       | ** ** | **$**                                                     | **1,839**  |   | $ | (1,207 | ) | $ | (495 | ) |

 

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

F-4

----

**MIRANT CORPORATIONAND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS**

| ** **                                                                                                       | ** ** | **For the Years Ended  December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                                                                       | ** ** | **2006**                                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                                       | ** ** | **(in millions)**                                    | ** ** |
| **Cash Flows from Operating Activities:**                                                                        | ** ** | ** **                                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income (loss)                                                                                                | ** ** | **$**                                                     | **1,864**  | ** ** | **$** | **(1,307** | **)** | $ | (476 | ) |
| Income (loss) from  discontinued operations                                                                      | ** ** | **91**                                                    |       | 99 |   | (477 | ) |
| Income (loss) from  continuing operations                                                                        | ** ** | **1,773**                                                 |       | (1,406 | ) | 1 |   |
| Adjustments to reconcile income (loss) from  continuing operations to net cash provided by operating activities: |       |                                                      |       |   |   |   |   |
| Amortization of  transition power agreements and other obligations                                               |       | —                                                    |       | (9 | ) | (344 | ) |
| Depreciation and  amortization                                                                                   | ** ** | **147**                                                   |       | 148 |   | 146 |   |
| Impairment losses                                                                                                | ** ** | **119**                                                   |       | 9 |   | 9 |   |
| Cumulative effect  of changes in accounting principles                                                           |       | —                                                    |       | 16 |   | — |   |
| Non-cash  post-petition interest expense                                                                         |       | —                                                    |       | 1,374 |   | — |   |
| Loss (gain) on  sales of assets and investments                                                                  | ** ** | **(125**                                                  | **)**      | (28 | ) | 49 |   |
| Non-cash  reorganization items                                                                                   | ** ** | **1**                                                     |       | 26 |   | 123 |   |
| Price risk  management activities, net                                                                           | ** ** | **(655**                                                  | **)**      | 16 |   | (168 | ) |
| Effect of the Plan  of Reorganization                                                                            |       | —                                                    |       | (285 | ) | — |   |
| Deferred income  taxes                                                                                           | ** ** | **(580**                                                  | **)**      | (4 | ) | 18 |   |
| Stock-based  compensation                                                                                        | ** ** | **17**                                                    |       | — |   | — |   |
| Non-cash gain on  property tax settlement                                                                        | ** ** | **(71**                                                   | **)**      | — |   | — |   |
| Other, net                                                                                                       | ** ** | **(34**                                                   | **)**      | 27 |   | (3 | ) |
| Changes in operating  assets and liabilities:                                                                    |       |                                                      |       |   |   |   |   |
| Receivables, net                                                                                                 | ** ** | **218**                                                   |       | (271 | ) | 220 |   |
| Other current  assets                                                                                            | ** ** | **346**                                                   |       | (431 | ) | (111 | ) |
| Other assets                                                                                                     | ** ** | **(70**                                                   | **)**      | (22 | ) | (1 | ) |
| Accounts payable  and accrued liabilities                                                                        | ** ** | **(203**                                                  | **)**      | 377 |   | (183 | ) |
| Settlement of  claims payable                                                                                    | ** ** | **(814**                                                  | **)**      | — |   | — |   |
| Accrued taxes                                                                                                    | ** ** | **59**                                                    |       | 65 |   | 16 |   |
| Other liabilities                                                                                                | ** ** | **(9**                                                    | **)**      | 13 |   | (13 | ) |
| Total adjustments                                                                                                | ** ** | **(1,654**                                                | **)**      | 1,021 |   | (242 | ) |
| Net cash provided  by (used in) operating activities of continuing operations                                    | ** ** | **119**                                                   |       | (385 | ) | (241 | ) |
| Net cash provided  by operating activities of discontinued operations                                            | ** ** | **444**                                                   |       | 418 |   | 312 |   |
| Net cash provided  by operating activities                                                                       | ** ** | **563**                                                   |       | 33 |   | 71 |   |
| **Cash Flows from Investing Activities:**                                                                        | ** ** | ** **                                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| Capital  expenditures                                                                                            | ** ** | **(133**                                                  | **)**      | (101 | ) | (90 | ) |
| Proceeds from the  sales of assets and other investments                                                         | ** ** | **143**                                                   |       | 165 |   | 45 |   |
| Other investing  activities                                                                                      | ** ** | **1**                                                     |       | — |   | (11 | ) |
| Net cash provided  by (used in) investing activities of continuing operations                                    | ** ** | **11**                                                    |       | 64 |   | (56 | ) |
| Net cash provided  by (used in) investing activities of discontinued operations                                  | ** ** | **(163**                                                  | **)**      | 15 |   | (90 | ) |
| Net cash provided  by (used in) investing activities                                                             | ** ** | **(152**                                                  | **)**      | 79 |   | (146 | ) |
| **Cash Flows from Financing Activities:**                                                                        | ** ** | ** **                                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| Proceeds from  issuance of long-term debt                                                                        | ** ** | **2,017**                                                 |       | 100 |   | 318 |   |
| Repayment of  long-term debt                                                                                     | ** ** | **(475**                                                  | **)**      | (2 | ) | (2 | ) |
| Settlement of debt  under the Plan                                                                               | ** ** | **(990**                                                  | **)**      | — |   | — |   |
| Debt issuance cost                                                                                               | ** ** | **(51**                                                   | **)**      | — |   | — |   |
| Proceeds from the  exercise of warrants                                                                          | ** ** | **2**                                                     |       | — |   | — |   |
| Stock repurchases                                                                                                | ** ** | **(1,261**                                                | **)**      | — |   | — |   |
| Other                                                                                                            |       | —                                                    |       | (1 | ) | — |   |
| Net cash provided  by (used in) financing activities of continuing operations                                    | ** ** | **(758**                                                  | **)**      | 97 |   | 316 |   |
| Net cash provided  by (used in) financing activities of discontinued operations.                                 | ** ** | **181**                                                   |       | (142 | ) | (343 | ) |
| Net cash used in  financing activities                                                                           | ** ** | **(577**                                                  | **)**      | (45 | ) | (27 | ) |
| Effects of  exchange rate changes from discontinued operations                                                   |       | —                                                    |       | (1 | ) | — |   |
| **Net  Increase (Decrease) in Cash and Cash Equivalents**                                                        | ** ** | **(166**                                                  | **)**      | 66 |   | (102 | ) |
| **Cash and  Cash Equivalents, beginning of period**                                                              | ** ** | **1,068**                                                 |       | 1,003 |   | 1,176 |   |
| **Plus:  Cash and Cash Equivalents included in assets held for sale at beginning of  year**                      | ** ** | **483**                                                   |       | 482 |   | 411 |   |
| **Less:  Cash and Cash Equivalents included in assets held for sale at end of year**                             | ** ** | **243**                                                   |       | 483 |   | 482 |   |
| **Cash and  Cash Equivalents, end of period**                                                                    | ** ** | **$**                                                     | **1,142**  |   | $ | 1,068 |   | $ | 1,003 |   |
| **Supplemental Cash Flow Disclosures:**                                                                          | ** ** | ** **                                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| Cash paid for  interest, net of amounts capitalized                                                              | ** ** | **$**                                                     | **372**    |   | $ | 120 |   | $ | 117 |   |
| Cash paid for  income taxes                                                                                      | ** ** | **$**                                                     | **165**    |   | $ | 68 |   | $ | 42 |   |
| Cash paid for  claims and professional fees from bankruptcy                                                      | ** ** | **$**                                                     | **1,908**  |   | $ | 171 |   | $ | 107 |   |

 

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

F-5

----

**MIRANT CORPORATIONAND SUBSIDIARIES**

**NOTES TO CONSOLIDATEDFINANCIAL STATEMENTS**

**December 31,2006, 2005 and 2004**

**1.**                 Descriptionof Business and Organization

Mirant generates revenues primarily through theproduction of electricity in the United States, the Philippines and theCaribbean. As of December 31, 2006, the Company owned or leased 17,522 MWof electric generating capacity. In the third quarter of 2006, the Companycommenced separate auction processes to sell its Philippine (2,203 MW) andCaribbean (1,050 MW) businesses and certain of its U.S. natural gas-firedplants (3,619 MW). See Note 3 for additional information regarding thetreatment of these businesses and assets as discontinued operations as a resultof this decision. Mirant’s continuing operations of 10,650 MW consist of theownership, long-term lease and operation of power generation facilities locatedin markets in the Mid-Atlantic and Northeast regions of the United States andin California, and energy trading and marketing operations in Atlanta, GA.

Mirant Corporation wasincorporated in Delaware on September 23, 2005, and is the successor to acorporation of the same name that was formed in Delaware on April 3, 1993.This succession occurred by virtue of the transfer of substantially all of OldMirant’s assets to New Mirant in conjunction with Mirant’s emergence frombankruptcy protection on January 3, 2006. Old Mirant was then renamedand transferred to a trust that is not affiliated with new Mirant. New Mirantserves as the corporate parent of the business enterprise and, pursuant to thePlan of Reorganization (the “Plan”) that was approved in connection with OldMirant’s emergence from bankruptcy, has no successor liability for anyunassumed obligations of Old Mirant. See Note 12 for additional informationrelated to Mirant’s bankruptcy.

**2.**                 Accountingand Reporting Policies

***Basis of Presentation***

The accompanying consolidated financial statements ofMirant and its wholly-owned subsidiaries have been prepared in accordancewith GAAP.

The accompanying financial statements include theaccounts of Mirant and its wholly-owned and controlled majority-ownedsubsidiaries as well as variable interest entities in which Mirant has aninterest and is the primary beneficiary. The financial statements have beenprepared from records maintained by Mirant and its subsidiaries in theirrespective countries of operation. All significant intercompany accounts andtransactions have been eliminated in consolidation. Investments in minority-ownedcompanies in which Mirant exercises significant influence over operating andfinancial policies are accounted for using the equity method of accounting.Jointly owned affiliates which Mirant does not control, as well as interests invariable interest entities in which Mirant is not the primary beneficiary, alsoare accounted for using the equity method of accounting.

All amounts are presented in U.S. dollars unlessotherwise noted. In accordance with SFAS No. 144, the results ofoperations of the Company’s businesses and assets to be disposed of have beenreclassified to discontinued operations and the associated assets andliabilities have been reclassified to assets and liabilities held for sale forall periods presented. In addition, the accompanying consolidated statements ofcash flows present the cash flows from discontinued operations in each of thethree major categories (operating, investing and financing activities). Theconsolidated statements of cash flows for the years ended December 31,2005 and 2004, were revised to conform to this presentation. See Note 3 foradditional information regarding discontinued operations.

F-6

----

Certain prior periodamounts have been reclassified to conform to the current year financialstatement presentation.

***Use of Estimates***

Thepreparation of 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 consolidated financial statements andthe reported amounts of revenues and expenses during the period. Actual resultscould differ from those estimates. Mirant’s significant estimates include:

·       determiningthe fair value of certain derivative contracts;

·       determiningthe value of Mirant’s asset retirement obligations;

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

·       estimatingthe expected return on plan assets, rate of compensation increases and otheractuarial assumptions used in estimating pension and other postretirementbenefit plan liabilities; and

·       estimating losses to berecorded for contingent liabilities.

***Revenue Recognition***

Mirant recognizesgeneration revenue from the sale of energy and recognizes integrated utilitiesand distribution revenue from the sale and distribution of energy when earnedand collection is probable. The Company recognizes revenue when electric poweris delivered to a customer pursuant to contractual commitments that specifyvolume, price and delivery requirements. Some sales of energy are based oneconomic dispatch, or ‘as-ordered’ by an ISO, based on member participationagreements, but without an underlying contractual commitment. ISO revenues andrevenues for sales of energy based on economic-dispatch are recorded on thebasis of MWh delivered, at the relevant day-ahead or real-time prices. When along-term electric power agreement conveys to the buyer of the electric powerthe right to use the generating capacity of Mirant’s plant, that agreement isevaluated to determine if it is a lease of the generating facility rather thana sale of electric power. Operating lease revenue for the Company’s generatingunits is normally recorded as capacity revenue and included in generationrevenues in the consolidated statements of operations.

***DerivativeFinancial Instruments***

Derivative financialinstruments are recorded in the accompanying consolidated balance sheets atfair value as either assets or liabilities, and changes in fair value arerecognized currently in earnings, unless specific hedge accounting criteria aremet. If the derivative is designated as a fair value 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 OCI and the realized gains and losses related to these derivatives arerecognized in earnings in the same period as the settlement of the underlyinghedged transaction. The assets and liabilities related to derivativeinstruments that have not been designated as hedges for accounting purposes areincluded in price risk management assets and liabilities. For the years ended December 31,2006, 2005 and 2004, the Company did not have any derivative instruments thatit had designated as fair value or cash flow hedges for accounting purposes.Mirant’s derivative financial instruments are categorized by the Company basedon the business objective the instrument is expected to achieve: assetmanagement or proprietary trading. All derivative contracts are recorded atfair value, 

F-7

----

exceptfor a limited number of transactions that qualify for the normal purchases ornormal sales exclusion from SFAS No.133 and therefore qualify for the use ofaccrual 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 and changes in fair value of fuel derivative contracts are reflected incost of fuel, electricity and other products in the accompanying consolidatedstatements of operations. Changes in the fair value and settlements ofcontracts for proprietary trading activities are recorded as generation revenuein the accompanying consolidated statements of operations.

***Concentration of Revenues***

In2006, 2005 and 2004, Mirant earned a significant portion of its operatingrevenue and gross margin from the PJM energy market, where its MirantMid-Atlantic generation facilities are located. Mirant Mid-Atlantic’s revenuesand gross margins as a percentage of Mirant’s total revenues and gross marginfrom continuing operations are as follows:

| ** **    | ** ** | **Years Ended December 31,** | ** ** |
|---------------|------------|---------------------------------------------|------------|
| ** **    | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| Revenues      |       |                                        | 61         | % |   |   | 45 | % |   |   | 31 | % |   |
| Gross margins |       |                                        | 68         | % |   |   | 54 | % |   |   | 46 | % |   |

 

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

As of December 31,2006, approximately 18% and 32% of the employees at locations in the Company’scontinuing operations and discontinued operations, respectively, are subject tocollective bargaining agreements. Approximately 31% of the employees atlocations in the Company’s discontinued operations are covered by collectivebargaining agreements that have expired or will expire within one year.

***Cash and Cash Equivalents***

Mirant considers allshort-term investments with an original maturity of three months or less to becash equivalents.

***Restricted Cash***

Restricted cash isincluded in current and noncurrent assets as funds on deposit and other noncurrentassets in the accompanying consolidated balance sheets. As of December 31,2006, current and noncurrent funds on deposit are $235 million and$6 million, respectively. As of December 31, 2005, current andnoncurrent funds on deposit are $1.5 billion and $5 million, respectively.Restricted cash includes deposits with brokers and cash collateral posted withthird parties to support the Company’s commodity positions as well as a $200million deposit Mirant North America posted under its senior secured term loanto support the issuance of letters of credit. In addition, as of December 31,2005, restricted cash included $853 million of escrowed proceeds from abond offering in December 2005. These amounts were released from escrow onJanuary 3, 2006.

***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. Fuel stock is removed from the inventoryaccount as it is used in the production of electricity. Materials 

F-8

----

andsupplies are removed from the inventory account when they are used for repairs,maintenance or capital projects.

***EmissionsAllowances***

Purchased emissionsallowances are recorded in inventory at the lower of cost or market. Cost iscomputed on an average cost basis. Purchased emissions allowances for SO2 andNOx are removed from inventory and charged to cost of fuel, electricity andother products in the accompanying consolidated statements of operations asthey are utilized against emissions volumes that exceed the allowances grantedto the Company by the EPA.

Emissions allowancesgranted by the EPA related to generation facilities owned by the Company arerecorded at fair value at the date of the acquisition of the facility and areincluded in property, plant and equipment. These emissions allowances aredepreciated on a straight-line basis over the estimated useful life of therespective generation facility, which ranges from 8 to 40 years, and arecharged to depreciation and amortization expense in the accompanyingconsolidated statements of operations.

Emissions allowancesgranted by the EPA related to generation facilities leased by the Company arerecorded at fair value at the commencement of the lease in other intangibleassets. These emissions allowances are amortized on a straight-line basis overthe term of the lease, and are charged to depreciation and amortization expensein the accompanying consolidated statements of operations. In addition theCompany acquired emissions allowances for future periods as part of theCalifornia Settlement agreement. These allowances are included in otherintangible assets and will be amortized over the periods in which they may beutilized.

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

***Property, Plant andEquipment***

Property, plant andequipment are recorded at cost, which includes materials, labor, and associatedpayroll-related and overhead costs and the cost of financingconstruction. The cost of routine maintenance and repairs, such as inspectionsand corrosion removal, and the replacement of minor items of property arecharged to expense as incurred. Certain expenditures incurred during a majormaintenance outage of a generating plant are capitalized, including thereplacement of major component parts and labor and overhead incurred to installthe parts. Depreciation of the recorded cost of depreciable property, plant andequipment is determined using primarily composite rates. Leasehold improvementsare depreciated over the shorter of the expected life of the related equipmentor the lease term. Upon the retirement or sale of property, plant and equipmentthe cost of such assets and the related accumulated depreciation are removedfrom the consolidated balance sheets. No gain or loss is recognized forordinary retirements in the normal course of business since the composite depreciationrates used by Mirant take into account the effect of interim retirements.

F-9

----

***Capitalization of Interest Cost***

Mirantcapitalizes 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. For the years ended December 31,2006, 2005 and 2004, the Company incurred the following interest costs(in millions):

| ** **                                                 | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                 | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| Total interest  costs                                      |       | $                                           | 298        |   | $ | 1,404 |   |   | $ | 18 |   |   |
| Capitalized and  included in construction work in progress |       | (9                                          | )          | — |   |   | — |   |   |
| Interest expense                                           |       | $                                           | 289        |   | $ | 1,404 |   |   | $ | 18 |   |   |

 

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, recordedapproximately $1.4 billion of interest expense in 2005 on liabilitiessubject to compromise.

***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. A goodwillimpairment occurs when the fair value of a reporting unit is less than itscarrying value including goodwill. The amount of the impairment charge, if animpairment exists, is calculated as the difference between the implied fairvalue of the reporting unit goodwill and its carrying value. The Company performsan annual assessment of goodwill at October 31 and whenever contraryevidence exists as to the recoverability of goodwill. The fair value of thereporting unit is calculated using discounted cash flow techniques andassumptions as to business prospects using the best information available. TheCompany had approximately $6 million in goodwill at December 31, 2006,related to Mirant Grand Bahama, which is recorded in assets held for sale onthe consolidated balance sheets.

***Environmental Remediation Costs***

Mirant accrues for costsassociated with environmental remediation when such costs are probable and canbe reasonably estimated. Accruals for estimated losses from environmentalremediation obligations generally are recognized no later than completion ofthe remedial feasibility study. Such accruals are adjusted as furtherinformation develops or circumstances change. The cost of future expendituresfor environmental remediation obligations are discounted to their presentvalue.

***Debt Issuance Costs***

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

F-10

----

***Income Taxes***

Income taxes are accounted for under the asset andliability method. Deferred tax assets and liabilities are recognized for thefuture tax consequences attributable to differences between the financialstatement carrying amounts of existing assets and liabilities and theirrespective tax bases and operating loss and tax credit carryforwards. Deferredtax assets and liabilities are measured using enacted tax rates expected toapply to taxable income in the years in which those temporary differences areexpected to be recovered or settled. The effect on deferred tax assets andliabilities of a change in tax rates is recognized in income in the period thatincludes the enactment date.

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 positiveevidence is necessary to support a conclusion that a valuation allowance is notneeded for all or a portion of deferred tax assets when significant negativeevidence exists. Future performance relating to the sale of the Philippineassets is the most compelling form of positive evidence considered bymanagement in the determination of the future recoverability of a portion ofits net deferred assets.

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

Mirant 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.Recoverability of assets to be held and used is measured by a comparison of thecarrying amount of an asset to the estimated undiscounted future cash flowsexpected to be generated by the asset. If the carrying amount of an assetexceeds its estimated undiscounted future cash flows, an impairment charge isrecognized as the amount by which the carrying amount of the asset exceeds itsfair value. Assets to be disposed of are separately presented in theaccompanying consolidated balance sheets and are reported at the lower of thecarrying amount or fair value less costs to sell, and are not depreciated. Theassets and liabilities of a disposal group classified as held for sale arepresented separately in the appropriate asset and liability sections of theaccompanying consolidated balance sheets.

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

The Company adoptedFIN 47, effective December 31, 2005, related to the costs associatedwith conditional legal obligations to retire tangible, long-lived assets.Conditional asset retirement obligations are recorded at the fair value in theperiod in which they are incurred by increasing the carrying amount of therelated long-lived asset. In each subsequent period, the liability is accretedto its fair value and the capitalized costs are depreciated over the usefullife of the related asset. For the year ended December 31, 2005, theCompany recorded a charge as a cumulative effect of a change in accountingprinciple of approximately $16 million, net of tax, related to theadoption of this accounting standard.

***Foreign Currency Translation***

For internationaloperations in which the Company considers the functional currency to be thelocal currency, the foreign currency is translated into U.S. dollars usingexchange rates in effect at period end for assets and liabilities and averageexchange rates during each reporting period for results of operations. 

F-11

----

Adjustmentsresulting from translation of financial statements of foreign operations arereported in accumulated OCI. For international operations in which the Companyconsiders the functional currency to be the U.S. dollar, transactionsdenominated in currencies other than the U.S. dollar are translated into U.S.dollars. Gains or (losses) on such transactions are recognized in earnings andamounted to $(71) million and $14 million in 2005 and 2004,respectively. There were no gains or losses on such transactions in 2006. Theloss of $71 million in 2005 is primarily related to the legal liquidationof several of the Company’s European subsidiaries in the fourth quarter of2005. This liquidation resulted in the release of the foreign exchangetranslation adjustment from accumulated other comprehensive income for theseentities.

***Earnings (Loss) per Share***

Earnings per share information for periods prior to2006 have not been presented. The Company does not think that this informationis relevant in any material respect for users of its financial statements. SeeNote 19 for further discussion.

Basic earnings (loss) pershare is calculated by dividing net income (loss) applicable to commonstockholders by the weighted average number of common shares outstanding.Diluted earnings (loss) per share is computed using the weighted average numberof shares of common stock and dilutive potential common shares, includingcommon shares from warrants and stock options using the treasury stock method.

***Recently Adopted Accounting Standards***

In December 2004, the FASB issued SFAS No. 123R,which requires companies to recognize in the income statement the grant-datefair value of stock options and other equity-based compensation issued toemployees. Mirant adopted the provisions of SFAS No. 123R on January 1,2006, using the modified prospective transition method. All awards that aregranted, modified or settled after the date of adoption will be measured andaccounted for in accordance with SFAS No. 123R, with no restatementof prior periods.

Under the modified prospective transition method, acompany is required to recognize compensation cost for unvested awards that areoutstanding on the effective date based on the fair value that the Company hadoriginally estimated for purposes of preparing its SFAS No. 123pro forma disclosures. Mirant’s unvested awards of stock-basedcompensation at December 31, 2005, were cancelled pursuant to the Plan.Therefore, there was no cumulative effect recognized upon adoption of SFAS No. 123R.Pre-tax expense related to stock-based compensation was approximately $16million and $1 million, respectively, related to service condition andperformance condition awards for the year ended December 31, 2006. SeeNote 14 for additional information on the Company’s stock-basedcompensation.

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

In April 2006, the FASB issued FSP FIN 46R-6.The variability that is considered in applying FIN 46R affects thedetermination of whether an entity is a VIE, which interests are variableinterests in the entity and which party, if any, is the primary beneficiary ofthe VIE. According to FSP FIN 46R-6, the variability to be consideredshould be based on the nature of the risks of the entity and the purpose forwhich the entity was created. The guidance in FSP FIN 46R-6 isapplicable prospectively to an entity at the time a company first becomesinvolved with such entity and is applicable to all entities previously requiredto be analyzed under FIN 46R when a reconsideration event has occurredbeginning with the first reporting period after June 15, 2006.Retrospective application to the date of the initial application of FIN 46R is 

F-12

----

permitted but notrequired. The Company adopted FSP FIN 46R-6 on July 1, 2006, on aprospective basis. Upon adoption there was no material impact on the Company’sstatements of operations, financial position or cash flows.

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

On September 29, 2006, the FASB issued SFAS No. 158,which requires an employer to recognize the overfunded or underfunded status ofa defined benefit postretirement plan as an asset or liability in its statementof financial position and to recognize changes in that funded status in theyear in which the changes occur through comprehensive income of a businessentity or changes in unrestricted net assets of a not-for-profit organization.SFAS No. 158 also requires an employer to measure the funded status of aplan as of the date of its year-end statement of financial position, withlimited exceptions.

The Company adopted SFAS No. 158 on December 31,2006, and recognized an increase in accounts payable and accrued liabilitiesand other noncurrent liabilities of $16 million related to its underfundeddomestic defined benefit pension plans and underfunded domestic postretirementbenefit plans. See Note 14 for additional information related to the pensionand other postretirement benefit plans of the Company’s continuing business.The Company also recognized an increase in other assets held for sale of $25million and an increase in liabilities held for sale of $16 million related tothe defined benefit pension plans and other postretirement benefit plans of itsforeign subsidiaries. The net after tax impact of adopting SFAS No. 158was a $10 million decrease in Other Comprehensive Income for the year ended December 31,2006.

The requirement to measureplan assets and benefit obligations as of the date of the employer’s fiscalyear-end statement of financial position is effective for the fiscal yearsending after December 15, 2008. The Company currently uses a September 30measurement date each year and will transition to a fiscal year-end measurementdate by December 31, 2008.

***New Accounting Standards Not Yet Adopted***

In February 2006, the FASB issued SFAS No. 155,which allows fair value measurement for any hybrid financial instrument thatcontains an embedded derivative that otherwise would require bifurcation.SFAS No. 155 is effective for all financial instruments acquired,issued or subject to a re-measurement event beginning in the first fiscal yearafter September 15, 2006. At the date of adoption, any difference betweenthe total carrying amount of the existing bifurcated hybrid financialinstrument and the fair value of the combined hybrid financial instrument willbe recognized as a cumulative effect adjustment to beginning retained earnings.The Company will adopt SFAS No. 155 on January 1, 2007. The adoptionof SFAS No. 155 is not expected to have a material impact on the Company’sstatements of operations, financial position or cash flows.

In March 2006, the FASB issued SFAS No. 156,which requires all separately recognized servicing assets and servicingliabilities to be measured initially at fair value and permits, but does notrequire, an entity to measure subsequently those servicing assets orliabilities at fair value. SFAS No. 156 is effective at the beginning ofthe first fiscal year after September 15, 2006. The Company will adoptSFAS No. 156 on January 1, 2007. All requirements for recognition andinitial measurement of servicing assets and servicing liabilities will beapplied prospectively to transactions occurring after the adoption of thisstatement. The 

F-13

----

adoption of SFAS No. 156is not expected to have a material impact on the Company’s statements ofoperations, financial position or cash flows.

On July 13, 2006, the FASB issued FIN 48. FIN 48clarifies the accounting for uncertainty in income taxes recognized in anenterprise’s financial statements in accordance with SFAS No. 109. FIN 48prescribes a recognition threshold and measurement attribute for the financialstatement recognition and measurement of a tax position taken or expected to betaken in a tax return.

The evaluation of a tax position in accordance withFIN 48 is a two-step process. The first step is recognition based on adetermination of whether it is more-likely-than-not that a tax position will besustained upon examination, including resolution of any related appeals orlitigation processes, based on the technical merits of the position. Inevaluating whether a tax position has met the more-likely-than-not recognitionthreshold, the enterprise should presume that the position will be examined bythe appropriate taxing authority having full knowledge of all relevantinformation. The second step is to measure a tax position that meets the more-likely-than-notthreshold. The tax position is measured at the largest amount of benefit thatis greater than 50% likely of being realized upon ultimate settlement.

FIN 48 is effective for fiscal years beginning after December 15,2006. The Company will adopt FIN 48 on January 1, 2007. Upon initialadoption, the provisions of FIN 48 will be applied to all tax positions. Onlytax positions that meet the more-likely-than-not recognition threshold at theeffective date may be recognized or continue to be recognized. The Companyanticipates that the balance sheet reclassification to increase retainedearnings and decrease liabilities as a result of adopting this standard isbetween $50 million and $125 million including discontinued operations.

On June 28, 2006, the FASB ratified the EITF’sconsensus reached on EITF 06-3, which relates to the income statementpresentation of taxes collected from customers and remitted to governmentauthorities. The Task Force affirmed as a consensus on this issue that thepresentation of taxes on either a gross basis or a net basis within the scopeof EITF 06-3 is an accounting policy decision that should be disclosedpursuant to APB 22. A company should disclose the amount of those taxes that isrecognized on a gross basis in interim and annual financial statements for eachperiod for which an income statement is presented if those amounts aresignificant. The Company will adopt EITF 06-3 on January 1, 2007.The adoption of EITF 06-3 is not expected to have a material impact on theCompany’s statements of operations, financial position or cash flows.

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

On September 8, 2006, the FASB issued FSP AUG AIR-1*.* FSP AUG AIR-1 permits the following methods foraccounting for major maintenance activities: direct expense, built-in overhauland deferral. It specifically prohibits accruing in advance for majormaintenance. The guidance in FSP AUG AIR-1 is to be applied to the firstfiscal year beginning after December 15, 2006. The Company will adopt FSPAUG AIR-1 on January 1, 2007. The adoption of FSP AUG AIR-1 isnot expected to have a material impact on the Company’s statements ofoperations, financial position or cash flows given that the Company currentlyuses the deferral or direct expense methods of accounting for major maintenanceactivities.

On September 15, 2006, the FASB issued SFAS No. 157,which establishes a framework for measuring fair value in GAAP and expandsdisclosure about fair value measurements. SFAS No. 157 requires companiesto disclose the fair value of their financial instruments according to a fairvalue hierarchy (i.e., levels 1, 2, and 3, as defined). Additionally, companiesare required to provide enhanced disclosure regarding fair value measurementsin the level 3 category, including a reconciliation of the beginning and 

F-14

----

ending balances separatelyfor each major category of assets and liabilities accounted for at fair value.SFAS No. 157 is effective at the beginning of the first fiscal year after November 15,2007. The Company will adopt SFAS No. 157 on January 1, 2008. At thedate of adoption, the Company will evaluate the fair value of its assets andliabilities according to the hierarchy established by the FASB and present therequired disclosures. It is also expected that the adoption of SFAS No. 157will impact the measurement of certain liabilities to incorporate Mirant’s owncredit standing and the accounting for inception gains and losses currentlybeing deferred under EITF 02-3. The net deferred inception gains andlosses at December 31, 2006, were $1.1 million. The Company has not yetdetermined the impact of SFAS No. 157 on its statements of operations,financial position or cash flows.

On February 15, 2007,the FASB issued SFAS No. 159, which permits an entity to measure manyfinancial instruments and certain other items at fair value by electing a fairvalue option. Once elected, the fair value option may be applied on aninstrument by instrument basis, is irrevocable and is applied only to entireinstruments. SFAS No. 159 also requires companies with trading andavailable-for-sale securities to report the unrealized gains and losses forwhich the fair value option has been elected within earnings for the periodpresented. SFAS No. 159 is effective at the beginning of the first fiscalyear after November 15, 2007. The Company will adopt SFAS No. 159 on January 1,2008. The Company has not yet determined the impact of SFAS No. 159 on itsstatements of operations, financial position or cash flows.

**3.**                 Dispositions

***Overview***

Assets and liabilities held for sale includesdiscontinued operations and other assets that the Company expects to dispose ofin the next year. In the third quarter of 2006, Mirant commenced auctionprocesses to sell the Philippine and Caribbean businesses and six naturalgas-fired intermediate and peaking plants totaling 3,619 MW comprised ofZeeland (903 MW), West Georgia (613 MW), Shady Hills (469 MW), Sugar Creek(561 MW), Bosque (546 MW) and Apex (527 MW).

On December 11, 2006, Mirant entered into adefinitive purchase and sale agreement with a consortium of The Tokyo ElectricPower Company, Incorporated and Marubeni Corporation for the sale of itsPhilippine business for a purchase price of $3.424 billion, plus a workingcapital adjustment at the closing. After the payment of related debt, which isestimated to be $642 million at the closing, the net proceeds to the Companyare expected to be $3.121 billion after transaction costs. The transaction isexpected to close in the second quarter of 2007 after the satisfaction ofcertain customary conditions, and the return to operation of both units at theSual facility.

On January 15, 2007, Mirant entered into adefinitive purchase and sale agreement with a subsidiary of LS Power EquityPartners I, L.P., LS Power Equity Partners II, L.P. and certain otheraffiliated funds, (collectively “LS Power”), for the sale of the six naturalgas-fired plants discussed above for a purchase price of $1.407 billion, whichincludes estimated working capital upon closing. After the payment of $83million of related debt, the net proceeds to Mirant are expected to be $1.307billion after transaction costs. The sale of the Zeeland and Bosque naturalgas-fired plants is subject to the terms of the Mirant North America creditfacilities and senior notes, including the provisions with respect to the useof the proceeds of such sales to repay amounts under the senior term loansand/or reinvest with the sale proceeds. The transaction is expected to close inthe second quarter of 2007 after the satisfaction of certain customary conditionsto closing. See Note 10 for additional information regarding restrictions onthe proceeds from the sale of the gas assets.

The associated assets and liabilities for thePhilippine and Caribbean businesses and the six natural gas-fired intermediateand peaking plants have been reclassified to assets and liabilities held forsale in the consolidated balance sheets.

F-15

----

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

| ** **                         | ** ** | **At December 31,  2006** | ** ** | **At December 31,  2005** | ** ** |
|------------------------------------|------------|-------------------------------------|------------|-------------------------------------|------------|
| **Current Assets:**                | ** ** |                                | ** ** | ** **                          |       |   | ** ** | ** ** |   |
| Cash and Cash  Equivalents         |       |                                | $          | 243                                 | ** ** |   |   | $ | 483 | ** ** |   |
| Funds on Deposit                   |       |                                | 126        | ** **                          |       |   | 187 | ** ** |   |
| Other Current  Assets              |       |                                | 520        | ** **                          |       |   | 502 | ** ** |   |
| Total Current Assets               |       |                                | 889        | ** **                          |       |   | 1,172 | ** ** |   |
| Property, Plant and Equipment, net |       |                                | 3,478      | ** **                          |       |   | 3,687 | ** ** |   |
| **Noncurrent  Assets:**            | ** ** |                                | ** ** | ** **                          |       |   | ** ** | ** ** |   |
| Investments                        |       |                                | 224        | ** **                          |       |   | 227 | ** ** |   |
| Other Noncurrent  Assets           |       |                                | 381        | ** **                          |       |   | 498 | ** ** |   |
| Total Noncurrent Assets            |       |                                | 605        | ** **                          |       |   | 725 | ** ** |   |
| **Total Assets**                   |       |                                | $          | 4,972                               | ** ** |   |   | $ | 5,584 | ** ** |   |
| **Current  Liabilities:**          | ** ** |                                | ** ** | ** **                          |       |   | ** ** | ** ** |   |
| Short-term Debt                    |       |                                | $          | 25                                  | ** ** |   |   | $ | 32 | ** ** |   |
| Current Portion  of Long-term Debt |       |                                | 166        | ** **                          |       |   | 391 | ** ** |   |
| Other Current  Liabilities         |       |                                | 235        | ** **                          |       |   | 282 | ** ** |   |
| Total Current Liabilities          |       |                                | 426        | ** **                          |       |   | 705 | ** ** |   |
| **Noncurrent  Liabilities:**       | ** ** |                                | ** ** | ** **                          |       |   | ** ** | ** ** |   |
| Long-term Debt                     |       |                                | 1,149      | ** **                          |       |   | 728 | ** ** |   |
| Other Noncurrent  Liabilities      |       |                                | 630        | ** **                          |       |   | 642 | ** ** |   |
| Total Noncurrent Liabilities       |       |                                | 1,779      | ** **                          |       |   | 1,370 | ** ** |   |
| **Total  Liabilities**             |       |                                | $          | 2,205                               | ** ** |   |   | $ | 2,075 | ** ** |   |

 

Assets held for sale at December 31,2006, consisted of the planned dispositions discussed above. Assets held forsale at December 31, 2005, consisted of the planned dispositions plus $11million related to the Mirant Service Center in Maryland and the Wichita Fallsfacility. The sale of both facilities closed in the second quarter of 2006, andthe Company recognized a gain of approximately $6 million on the sale of theMirant Service Center. The Company recognized a loss of $11 million in thefourth quarter of 2005 related to the sale of Wichita Falls and recognized noadditional gain or loss upon completion of the sale.

***Variable Interest Entities***

The Company has held a minority equity interest inIlijan, a non-consolidated VIE, since July 2000. The non-consolidated VIEprimarily holds an interest in a generation facility and has total assets ofapproximately $129 million and $116 million at December 31, 2006 and 2005,respectively. It is the Company’s view that its maximum exposure to lossassociated with its interest in the non-consolidated VIE is the Company’scarrying value of its investment in the VIE at December 31, 2006, ofapproximately $63 million. The Company’s investment in Ilijan is included inthe Philippine business, which is subject to a definitive purchase and saleagreement.

Jamaica Public Service Company Limited, an 80% ownedsubsidiary of the Company, purchases power under PPAs, including PPAswith JPPC and JEP. The sole purpose of JPPC and JEP is to generate powerto be sold to Jamaica Public Service Company Limited. The Company has novoting or equity interest in either JPPC or JEP. JPPC owns a 60 MW powerfacility and sells electricity to Jamaica Public 

F-16

----

Service Company Limitedunder a PPA through August 2016. The Company had accounted for thePPA with JPPC as a capital lease since its March 2001 acquisition ofJamaica Public Service Company Limited. JEP owns a 119 MW floating powerfacility and sells electricity to Jamaica Public Service Company Limited undera PPA through February 2026. In March 2006, Jamaica Public ServiceCompany Limited renegotiated an existing 70 MW PPA with JEP to add anadditional 49 MW and to extend the term of the PPA through February 2026.The Company had accounted for the PPA with JEP as a capital lease since its March 2006amendment of the lease and as an operating lease prior to that amendment.

During the third quarter of 2006, the Companyreevaluated its PPAs with JPPC and JEP based on evolvinginterpretations of FIN 46*,* as amended. Asa result of this reevaluation, the Company now consolidates JPPC and JEPbecause they are determined to be VIEs, whereby the Company is consideredthe primary beneficiary. JPPC and JEP have total assets of$118 million and $141 million, respectively, at December 31, 2006. Asa result of the consolidation of JPPC and JEP, the Company recorded an increasein assets held for sale of $86 million and an increase in liabilities held forsale of $86 million.

F-17

----

***Long-Term Debt***

Long-termdebt recorded in liabilities held for sale at December 31, 2006 and 2005,is as follows (in millions):

| ** **                                                              | ** ** | **At  December 31,  2006** | ** ** | **At  December 31,  2005** | ** ** | **Interest Rate** | ** ** | **Secured/  Unsecured** | ** ** |
|-------------------------------------------------------------------------|------------|---------------------------------|------------|---------------------------------|------------|------------------------|------------|-------------------------|------------|
| **Long-term Debt:**                                                     | ** ** |                            | ** ** | ** **                      |       |                   | ** ** | ** **              |       | ** ** | ** ** | ** ** | ** ** |
| Mirant North America:                                                   |       |                            |       |                            |       |                   |       |                    |       |   |   |   |   |
| Mirant Zeeland capital lease, due 2007 to 2012                          |       |                            | $          | 11                              |       |                   |       | $                       | 11         |   |   | 9.5% |   | — |   |
| Other:                                                                  |       |                            |       |                            |       |                   |       |                    |       |   |   |   |   |
| Mirant Sweden International AB (publ), due 2007  to 2012           |       |                            | 700        |                            |       |                   | —     |                    |       | LIBOR + 2.25% |   | Secured |   |
| Mirant Pagbilao project loan, due 2006 to 2007                          |       |                            | —     |                            |       |                   | 99         |                    |       | LIBOR + 2.15% to 10.25% |   | Secured |   |
| Mirant Sual project loan, due 2006 to 2012                              |       |                            | —     |                            |       |                   | 452        |                    |       | 5.95% to 10.56% |   | Secured |   |
| Jamaica Public Service Company Limited, due 2007 to  2030               |       |                            | 169        |                            |       |                   | 230        |                    |       | 7.00% to LIBOR + 7.5% |   | Secured |   |
| Jamaica Public Service Company Limited, due 2016                        |       |                            | 180        |                            |       |                   | —     |                    |       | 11% |   | Unsecured |   |
| Mirant Grand Bahama Limited, due 2007 to 2011                           |       |                            | 10         |                            |       |                   | 12         |                    |       | LIBOR + 1.25% |   | Secured |   |
| Grand Bahama Power Company Limited, due 2007 to 2014                    |       |                            | 50         |                            |       |                   | 43         |                    |       | 5.625% to Bahamian Prime + 1.125% |   | Unsecured |   |
| Mirant Trinidad Investments LLC, due 2016                          |       |                            | 100        |                            |       |                   | 73         |                    |       | 7.017% |   | Secured |   |
| Mirant Curacao Investments, Ltd, due 2007                               |       |                            | 12         |                            |       |                   | 14         |                    |       | 10.15% |   | Secured |   |
| West Georgia Generating Company, due 2007 to 2011                       |       |                            | 83         |                            |       |                   | 95         |                    |       | LIBOR + 3.125% |   | Secured |   |
| Mirant Curacao  Investments—deferred acquisition price, due 2006   |       |                            | —     |                            |       |                   | 3          |                    |       | 9.00% |   | Unsecured |   |
| Jamaica Public Service Company Limited capital lease,  due 2006 to 2016 |       |                            | —     |                            |       |                   | 87         |                    |       | 12.51% |   | — |   |
| Total long-term debt                                                    |       |                            | 1,315      |                            |       |                   | 1,119      |                    |       |   |   |   |   |
| Less: current  portion of long-term debt                                |       |                            | (166       | )                               |       |                   | (391       | )                       |       |   |   |   |   |
| Total long-term  debt, excluding current portion                        |       |                            | $          | 1,149                           |       |                   |       | $                       | 728        |   |   |   |   |   |   |

 

*MirantAsia-Pacific Loan Facility.*   On August 15,2006, Mirant Sweden International AB (publ), as borrower, and MirantAsia-Pacific Limited (together with certain of its subsidiaries), as guarantor,completed the funding of its Mirant Asia-Pacific Loan Facility for Mirant’sPhilippine business. The Mirant Asia-Pacific Loan Facility has a maturity datesix years from the date of the drawing. Interest on the Mirant Asia-PacificLoan Facility is payable at a rate per annum equal to the U.S. Dollar LIBORdetermined for certain interest periods plus an applicable margin set at 2.25%per annum. In connection with the completion of the funding under this facility,the Company repaid $402 million of existing debt at Pagbilao and Sual. Aportion of these funds, together with other funds from the Philippine businesswere distributed or repaid to Mirant Corporation and were used as part of theconsideration for Mirant’s modified “Dutch Auction” share repurchase announcedon July 11, 2006.

The payment obligations of Mirant Sweden InternationalAB (publ) under the Mirant Asia-Pacific Loan Facility are unconditionallyguaranteed by Mirant Asia-Pacific Limited and certain of its direct and 

F-18

----

indirect subsidiaries,referred to as the “subsidiary guarantors”, under a guaranty agreement and willconstitute senior, secured obligations of the subsidiary guarantors. Inconnection with the sale of the Philippine business, the Company expects thatthe Mirant Asia-Pacific Loan Facility will be repaid.

*JamaicaPublic Service Company Notes.*   On July 6,2006, Mirant JPS Finance, a wholly-owned subsidiary of Mirant, issued seniornotes in an aggregate principal amount of $180 million that bear interestat 11% and mature on July 6, 2016. Mirant JPS Finance deposited the grossoffering proceeds into an escrow account for the benefit of the holders of thenotes. After the satisfaction of specified conditions and in connection withthe repayment of Jamaica Public Service Company’s credit facilities with RoyalBank of Trinidad and Tobago Limited, on August 31, 2006, Jamaica PublicService Company Limited assumed all of Mirant JPS Finance’s obligations underthe notes in exchange for the release of the offering proceeds from the escrowaccount. Interest on the notes is payable semiannually. Prior to the assumptionof notes by Jamaica Public Service Company Limited, the notes were generalunsubordinated obligations of Mirant JPS Finance secured by the escrow funds.Upon the assumption of the notes by Jamaica Public Service Company Limited, thenotes are general unsecured obligations of Jamaica Public Service CompanyLimited without recourse to any other Mirant entity. In 2006, Jamaica PublicService Company Limited repaid $186 million of long-term debt. Upon thesale of Jamaica Public Service Company Limited, they will be required to makean offer to purchase such notes at a price equal to 101% of the principalamount thereof; provided, however, that Jamaica Public Service Company will notbe required to make such an offer if a third-party makes an offer to purchasesuch notes on the same terms and purchases all notes validly rendered pursuantto such offer.

On December 18, 2006, Jamaica Public ServiceCompany Limited repaid $20 million of maturing short-term debt and issued $15million of new short-term debt. The $15 million note has an interest rate equalto 12-month LIBOR plus 3% with interest payable on a quarterly basis. Thematurity date is December 18, 2007.

*MirantTrinidad Investments, LLC Notes.*   During thefirst quarter of 2006, Mirant Trinidad Investments issued $100 million of7.017% notes. Interest on the notes is payable semiannually, and the principalis due on February 1, 2016. A significant portion of the net proceeds ofthe offering were used by Mirant Trinidad Investments to repay its$73 million aggregate principal amount of 10.20% notes due January 31,2006. The remaining net proceeds are being used by Mirant Trinidad Investmentsto finance a portion of a PowerGen expansion project. The notes are secured bya pledge and assignment by Mirant Trinidad Investments of its shares of commonstock issued by PowerGen and by certain other collateral. The notes are solelythe obligation of Mirant Trinidad Investments without recourse to any other Mirantentity or to PowerGen. In connection with the sale of Mirant TrinidadInvestments, the holders of the notes will have the right to require MirantTrinidad Investments to purchase all or a portion of such notes at a priceequal to 101% of the principal amount thereof.

*Mirant Grand BahamaLimited Credit Facility.**  *In August 1996,Mirant Grand Bahama Limited entered into a $28 million senior securedcredit facility. The outstanding balance of the facility was $12.4 millionas of December 31, 2005, and was due to mature during 2006. During thefirst quarter of 2006, the term of the facility was extended to August 2011.The senior secured credit facility is an obligation of Mirant Grand BahamaLimited and is non recourse to any other Mirant entities*.*In connection with the sale of the Caribbean business, the Company expects thatthe senior secured credit facility will remain outstanding.

***Other Commitments***

Mirant has commitmentsunder fuel and transportation, long term service agreements and other purchasecommitments with various terms and expiration dates that are related to itsdiscontinued operations. The total of these commitments as of December 31,2006, approximate $555 million.

F-19

----

***Measurement of Assets Held for Sale***

In accordance with SFAS No. 144, an assetclassified as held for sale shall be measured at the lower of carrying value orfair value less costs to sell. The fair value of the Philippine business andthe six U.S. natural gas-fired plants was determined based upon the final salesprice as specified in the respective executed purchase and sale agreements. As furtherexplained below, Mirant is seeking to sell the Caribbean business as a wholeand has determined that no impairment is necessary.

*Philippines.**  *Mirant hasownership interests in three generating facilities in the Philippines: Sual,Pagbilao and Ilijan. Its net ownership interest in these three generatingfacilities is approximately 2,203 MW. Pursuant to the definitive purchase andsale agreement entered into by Mirant with the consortium of The Tokyo ElectricPower Company and Marubeni Corporation on December 11, 2006, Mirant willsell the Philippine business in a single transaction. Upon completion of thetransaction, Mirant expects to record a pre-tax gain of approximately $2billion.

*Caribbean.**  *Mirant’s net ownership interest in the Caribbeanbusiness is 1,050 MW. The ownership includes controlling interests in twovertically integrated utilities: an 80% interest in Jamaica Public ServiceCompany Limited and a 55% interest in Grand Bahama Power Company. Mirant alsoowns a 39% interest in PowerGen, a 26% interest in Curacao Utilities Companyand a $40 million convertible preferred equity interest in Aqualectra, anintegrated water and electric company in Curacao. Mirant is currently seekingto sell the Caribbean business in a single transaction. Mirant’s analysisindicated that no impairment was necessary, as the estimated fair value lesscosts to sell exceeded the book carrying value. Mirant received non-bindingindicative bids for the Caribbean assets in November. Based on a review of thebids, it remains more-likely-than-not that the Caribbean business will be soldin a single transaction. Mirant determined that no impairment was necessary inthe fourth quarter as bids from potential buyers exceeded the carrying value ofthe assets.

*U.S. Natural Gas-FiredPlants.**  *Mirantentered into a definitive purchase and sale agreement with a subsidiary of LSPower Equity Partners I, L.P., LS Power Equity Partners II, L.P. and certainother affiliated funds, (collectively “LS Power”), to sell six U.S. naturalgas-fired intermediate and peaking plants comprised of Zeeland, West Georgia,Shady Hills, Sugar Creek, Bosque and Apex on January 15, 2007. Pursuant tothe definitive purchase sales agreement entered into by Mirant with asubsidiary of LS Power Equity Partners I, L.P., LS Power Equity Partners II,L.P. and certain other affiliated funds, (collectively “LS Power”), the six plants will be sold in a singletransaction. The Company recorded an impairment loss of $396 million in thethird quarter of 2006 to write down the assets to their estimated fair valueless cost to sell. As a result of updated fair values along with changes to theworking capital calculation in the draft purchase and sale agreement providedto the bidders, the Company recorded a reduction to the impairment loss of $21million in the fourth quarter of 2006. The net 2006 impairment loss of $375million was recorded in discontinued operations in the Company’s consolidatedstatements of operations for the year ended December 31, 2006 to decreasethe carrying value of the assets to their fair value less costs to sell.

***Discontinued Operations***

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

In addition to the planned dispositions, discontinuedoperations includes previously completed sales of asset groups. In the firstquarter of 2006, Mirant executed an agreement to sell its 77 MW combined cycleWichita Falls facility in Texas. The sale of the plant was completed on May 4, 2006. In the thirdquarter of 2005, the Company completed the sale of its Wrightsville generatingfacility to Arkansas Electric Cooperative Corporation for $85 million andrecognized a net gain on sales of assets of $2 million.

F-20

----

In the second quarter of 2004, the Company recognizedan impairment charge of $48 million related to its 50% interest in the CoyoteSprings 2 project. In the fourth quarter of 2004, the Company entered into anagreement to sell its 50% interest to Avista Energy. In the first quarter of2005, the Company completed the sale and received proceeds of $63 million andrecognized no additional significant gain or loss on the transaction.

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

| ** **                      | ** ** | **Year Ended December 31, 2006** | ** ** |
|---------------------------------|------------|------------------------------------------------------|------------|
| ** **                      | ** ** | **U.S.**                                             | ** ** | **Philippines** | ** ** | **Caribbean** | ** ** | **Total** | ** ** |
| Operating  revenues             |       | $                                                    | 287        |   |   | $ | 469 |   |   |   | $ | 825 |   |   | $ | 1,581 |   |
| Operating  expenses(1)          |       | 574                                                  |       |   | 187 |   |   |   | 686 |   |   | 1,447 |   |
| Operating income  (loss)        |       | (287                                                 | )          |   | 282 |   |   |   | 139 |   |   | 134 |   |
| Other expense  (income), net(2) |       | 9                                                    |       |   | (46 | ) |   |   | 80 |   |   | 43 |   |
| Net income (loss)               |       | $                                                    | (296       | ) |   | $ | 328 |   |   |   | $ | 59 |   |   | $ | 91 |   |

 

| ** **          | ** ** | **Year Ended December 31, 2005** | ** ** |
|---------------------|------------|------------------------------------------------------|------------|
| ** **          | ** ** | **U.S.**                                             | ** ** | **Philippines** | ** ** | **Caribbean** | ** ** | **Total** | ** ** |
| Operating  revenues |       | $                                                    | 323        |   |   | $ | 488 |   |   |   | $ | 729 |   |   | $ | 1,540 |   |
| Operating  expenses |       | 298                                                  |       |   | 195 |   |   |   | 623 |   |   | 1,116 |   |
| Operating income    |       | 25                                                   |       |   | 293 |   |   |   | 106 |   |   | 424 |   |
| Other expense,  net |       | 102                                                  |       |   | 179 |   |   |   | 44 |   |   | 325 |   |
| Net income(loss)    |       | $                                                    | (77        | ) |   | $ | 114 |   |   |   | $ | 62 |   |   | $ | 99 |   |

 

| ** **               | ** ** | **Year Ended December 31, 2004** | ** ** |
|--------------------------|------------|------------------------------------------------------|------------|
| ** **               | ** ** | **U.S.**                                             | ** ** | **Philippines** | ** ** | **Caribbean** | ** ** | **Total** | ** ** |
| Operating  revenues      |       | $                                                    | 278        |   |   | $ | 481 |   |   |   | $ | 564 |   |   | $ | 1,323 |   |
| Operating  expenses      |       | 322                                                  |       |   | 758 |   |   |   | 493 |   |   | 1,573 |   |
| Operating income  (loss) |       | (44                                                  | )          |   | (277 | ) |   |   | 71 |   |   | (250 | ) |
| Other expense,  net      |       | 56                                                   |       |   | 128 |   |   |   | 43 |   |   | 227 |   |
| Net income (loss)        |       | $                                                    | (100       | ) |   | $ | (405 | ) |   |   | $ | 28 |   |   | $ | (477 | ) |

----

(1)          Includes, for the yearended December 31, 2006, an impairment loss of $375 million in theU.S*.*

(2)          Includes,for the year ended December 31, 2006, income tax benefits of $141 millionand $124 million related to the Philippine disposition.

***Contingencies***

*Sual Outages*

Since July 12, 2006,Mirant Sual has had an unplanned outage of unit 2 of its generationfacility due to a failure of the generator. The generator manufacturer hascontracted to repair the unit 2 generator at a cost of approximately$17 million. The repairs to unit 2 are scheduled to be completed in March 2007.On October 23, 2006, unit 1 at the Sual generation facility had anunplanned outage also as a result of a failure of the generator. Mirant hascontracted with the generator manufacturer to perform repairs to unit 1 at anapproximate cost of $21 million, with repairs expected to be completed in May 2007.Mirant Sual expects to recover through insurance proceeds a substantial portionof the cost of the repairs of units 1 and 2 that exceeds Mirant Sual’sdeductible of $5 million per occurrence.

Mirant Sual has accumulatedsignificant outage allowances under its energy conversion agreement with NPC.On January 11, 2007, Mirant Sual confirmed its agreement with NPC on thenominated capacity for the unused accumulated allowable outage periods throughthe contract year ended in October 2006 

F-21

----

and alsoconfirmed that the 55 allowable outage days per unit for the contract yearbeginning in October 2006 will be used upon the return to service of therespective units. In connection with the present outages, Mirant Sual expectsto utilize accumulated allowable outage days and, thus, earn capacity fees, forunit 1 and unit 2 through April 5, 2007 and October 19, 2006,respectively. For the balance of the outage periods after utilization of theaccumulated outage allowances under the energy conversion agreement, MirantSual will make claims under its business interruption insurance to compensateit for lost capacity and energy fees, subject to deductible periods.

The Company does notexpect that, after taking into account the outage allowances under the energyconversion agreement and the expected insurance proceeds, the reduction incapacity payments and energy fees to it resulting from the outages will have amaterial impact on its consolidated results of operations or financial condition.

Finalizing the sale of thePhilippine business is contingent upon Mirant’s ability to return to operationboth units at the Sual plant.

*NPC Claims*

MirantSual is contracted to sell 1,000 MW of its 1,218 MW capacity to NPCpursuant to an energy conversion agreement. Mirant Sual is entitled to sell the218 MW of excess capacity to Mirant (Philippines) Energy Corporation,which markets the Sual excess capacity to customers agreed or otherwiseapproved by NPC through the energy supply business of Mirant (Philippines)Energy Corporation. Mirant (Philippines) Corporation received a letter from NPCdated March 16, 2006, claiming refunds in the amount of $26 millionrelating to sales of excess capacity from January 2001 to January 2006.Mirant (Philippines) Energy Corporation and NPC signed a ClarificatoryFramework for Sual Power Plant on February 13, 2007, clarifying thedispatch protocol of the Sual excess sale and resolving or withdrawing theclaims of NPC. In connection with such resolution, Mirant (Philippines) EnergyCorporation paid $9 million to NPC.

*Philippine Real Property Taxes*

Real property taxes in thePhilippines are levied by applying the tax rate to a locally determined taxablevalue of the property. Under the Philippine Local Government Code (“LGC”), thetaxable value of property depends on the nature and use of the property. Forland, machinery and equipment owned by commercial and industrial users, thetaxable value of property is assessed at up to 80% of its fair market value.For land, machinery and equipment owned and used by government-owned orcontrolled corporations in the provision of certain services, includingelectricity generation, the taxable value is assessed at up to 10% of the fairmarket value of the property. The local taxing authorities in Pagbilao assessreal property taxes for the Pagbilao generation facility at the 80% assessmentlevel. The local taxing authorities in Sual currently assess real propertytaxes for the Sual generation facility at the 10% level. However, the localtaxing authority in Sual may pass an ordinance or resolution applying anassessment level of up to 80% on future assessments.

Another provision of theLGC provides that machinery and equipment that are actually, directly orexclusively used by government-owned or controlled corporations engaged in thegeneration and transmission of electric power are exempt from real propertytaxes.

Under the energyconversion agreements for Pagbilao and Sual, which were executed under thePhilippine government’s BOT program, NPC is responsible for payment of realproperty taxes. NPC, a government-owned corporation, is the owner of the landon which the Pagbilao and Sual Plants are situated and historically has paidthe real property tax on the land. Mirant’s subsidiaries are currently theowners of record of the machinery, buildings and equipment constituting thePhilippine plants. When the local taxing authorities in Pagbilao and Sualassessed property taxes on the Philippine plants, the Company referred thematter to NPC. NPC has taken the position that it is the beneficial owner ofthe machinery and equipment for purposes of the real property tax because itwill own the Philippine plants when they are 

F-22

----

transferredto NPC pursuant to the energy conversion agreements. NPC has filed petitionsfor exemption with the relevant tax courts, claiming that it is exempt fromreal property taxes on the machinery and equipment that are used to generateelectricity pursuant to the LGC.

In acase filed by NPC, the Philippine Court of Tax Appeals ruled that NPC is notexempt from real property taxes on machinery and equipment and cannot betreated as the owner of the machinery and equipment. Therefore, the machineryand equipment may be assessed at a taxable level of up to 80% of its fairmarket value. The case is now before the Philippine Supreme Court. Absent abinding injunction or restraining order preventing them from acting (such asthe Philippine Supreme Court order discussed below), the local authoritieswould have the right to issue a notice of delinquency to Mirant Sual and MirantPagbilao as the record owners of the respective properties and, if the taxeswere not paid, to levy against the Philippine plants. With respect to the SualPlant, the local taxing authorities in Sual have assessed and been paid alltaxes at the 10% level through December 31, 2005. In February 2006,Mirant Sual received an assessment in the amount of approximately$1.4 million representing the 2006 real property tax on the Sual Plant.Subsequently, Mirant Sual has received letters from the local taxing authoritydemanding payment of the assessed taxes with respect to machinery andequipment, including a final demand letter for the payment of 2006 assessedtaxes in the amount of approximately $1.8 million. Mirant Sual forwarded theassessment and subsequent demand letters to NPC, which is responsible forpaying the tax under its energy conversion agreement. On February 5, 2007,Mirant Sual sent a reply letter to the local taxing authority stating thatthere is a pending case in the local tax court where NPC, as actual direct,exclusive and beneficial owner of the plant is claiming exemption from thepayment of real property taxes.

With respect to thePagbilao Plant, the disputed tax assessments are approximately $85 millionrelated to periods through December 31, 2006. On July 26, 2006, theOffice of the Municipal Treasurer of the Municipality of Pagbilao, the Provinceof Quezon, delivered a Warrant of Levy to Mirant Pagbilao stating that MirantPagbilao is delinquent in the payment of real estate taxes and declaring theproperties at the Pagbilao Plant are to be levied and sold at a public auctionto satisfy the tax delinquency. Mirant Pagbilao referred the Warrant of Levy toNPC and sought an injunction against the Warrant of Levy and any attempted levyand auction of the Pagbilao facility from the Philippine Court of Appeals, theintermediate appeals court in the Philippines. Mirant Pagbilao’s applicationremains pending before the Philippine Court of Appeals. Subsequently, in thecase between NPC and the Pagbilao local government pending before thePhilippine Supreme Court, and on application by NPC, the Philippine SupremeCourt issued an order restraining the Pagbilao local government units andtaxing authorities from executing and implementing the Warrant of Levy or anysimilar issuance with respect to the tax assessments on the Pagbilao Plantuntil the issuance of further orders from the Philippine Supreme Court. Theoutcome of this matter cannot be predicted, nor can there be any assurancesthat the Philippine Supreme Court will not subsequently lift its restrainingorder. However, if Mirant Pagbilao is held liable for payment of the realproperty taxes it shall seek full recovery from NPC or, in the event NPC doesnot pay, from the Government of the Philippines. Payment of NPC’s obligationsto Mirant Sual and Mirant Pagbilao under the energy conversion agreements isguaranteed by the Government of the Philippines.

In 2005, in order toprovide assistance to the local governments while the real property tax matterwas being reviewed by the Philippine courts and to avoid the possibility thatthe local governments might issue a notice of delinquency, Mirant subsidiariesentered into memoranda of agreement with the respective taxing authoritiespursuant to which such authorities agreed not to take any actions in connectionwith real property taxes pending the judicial resolutions of the issue ofavailability of the claimed exemption by NPC. In connection with the memorandaof agreement, Mirant subsidiaries advanced $11 million to the localgovernments towards the disputed tax assessments. The Company may elect to makefurther advances until the matter is finally decided by the courts. Further,the Company intends to seek to recover these advances from NPC or from thelocal governments when the outcome of the dispute is decided by the PhilippineSupreme Court.

F-23

----

**4.**                 Impairmentson Assets Held and Used

In accordance with SFAS No. 144,an asset classified as held and used shall be tested for recoverabilitywhenever events or changes in circumstances indicate that the carrying amountof the asset may not be recoverable. An asset impairment charge must berecognized if the sum of the undiscounted expected future cash flows from along-lived asset is less than the carrying value of that asset. The amount ofany impairment 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.

*Current Year Events*

The Mirant Lovett and Mirant Bowline generationfacilities in New York have been subject to disputes with local tax authoritiesregarding property tax assessments. In addition, Mirant New York and MirantLovett entered into the 2003 Consent Decree to resolve issues related to NSRrequirements under the Clean Air Act related to the Lovett plant. Mirant Lovettis in discussions with the NYSDEC and the New York State Office of the AttorneyGeneral regarding environmental controls under the 2003 Consent Decree.

On August 11, 2006, and August 28, 2006, theNew York state court issued decisions addressing Mirant Bowline’s challenges tothe assessed values of the Bowline facility for the years 1995 to 2003 andMirant Lovett’s challenges to the assessed values of the Lovett facility forthe years 2000 to 2003. Except for 1996, where it found that Mirant Bowline hadfailed to perfect its challenge to the assessed value of the Bowline facility,the New York state court concluded that the value of the Bowline facility andthe Lovett facility in each year was substantially less than the assessed valueset by the taxing authorities.

Under the 2003 Consent Decree, Mirant Lovett isrequired to make an election to install certain environmental controls on units5 and 4 of the Lovett facility or shut down those units by April 30, 2007and April 30, 2008, respectively. On September 19, 2006, MirantLovett sought Bankruptcy Court approval to discontinue operations at units 3and 5 of the Lovett generation facility if an alternative environmentalcompliance mechanism that is agreeable to the State of New York is not approvedby April 30, 2007. On October 18, 2006, the Bankruptcy Court approvedthe Company’s request. On October 19, 2006, Mirant Lovett submittednotices of its intent to discontinue operations at units 3 and 5 of the Lovettfacility on April 30, 2007, to the New York Public Service Commission,NYISO, Orange and Rockland and several other affected transmission anddistribution utilities in New York. Mirant Lovett reserved its rights towithdraw these notices if a viable alternative environmental compliancemechanism is found. See New York State Administrative Claim in Note 23—Litigationand Other Contingencies for additional information.

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

F-24

----

*Asset Grouping*

For purposes of measuringan impairment loss, a long-lived asset or assets must be grouped at the lowestlevel of independent identifiable cash flows. All of the units at Mirant Lovettwere viewed as one group. For Bowline, the Company determined that thesuspended Bowline unit 3 construction project was independent of theoperating Bowline units. In addition, the Company’s analysis and planningaround the operating Bowline units 1 and 2 did not consider the suspendedconstruction project for Bowline unit 3.

*Assumptions andResults*

In its impairment analysis of the Bowline and Lovettgeneration facilities in prior periods, the Company assumed that PILOTagreements covering 2006 and seven subsequent years would be successfullyapproved and implemented. The Company no longer expects such PILOT agreementsto be implemented. The August 2006 decisions and the appeals that followedprompted management to test for recoverability of the asset under SFAS No. 144because additional uncertainty existed related to achieving property taxationlevels that would allow economically feasible operation of the Bowline andLovett generation facilities. As a result of these developments, managementre-reviewed the economic viability of these facilities in the third quarter of2006.

*Lovett.  *TheCompany’s assessment of Lovett under SFAS No. 144 in the third quarter of2006 involved estimating property tax refunds and payments and assuming thatproperty taxes would be negotiated to a reasonable level for future periods.Among the multiple scenarios considered were the shut down of units 3 and 5 by April 30,2007, and unit 4 by April 30, 2008. The Company also considered scenarios that would allow operations past April 2008because the Company continues to work with the State of New York and otherparties to achieve a solution related to environmental controls and to allowLovett to continue to contribute to the reliability of the electric system ofthe State of New York. The sum of the probability weighted undiscounted cashflows for the Lovett generation facility exceeded the Company’s carrying valueat September 30, 2006. As the refunds and taxes owed agreed upon in thesettlement agreement were not materially different from the estimates used inthe impairment analysis, the Company determined that no further analysis wasneeded at December 31, 2006.

*BowlineUnits 1 and 2.**  *TheCompany’s assessment of Bowline units 1 and 2 under SFAS No. 144 in thethird quarter of 2006 involved estimating property tax refunds and payments andassuming that property taxes would be negotiated to levels for future periodsthat would allow Bowline units 1 and 2 to operate until the end of theirremaining economic useful lives. Thesum of the undiscounted cash flows exceeded the Company’s carrying value at September 30,2006, for Bowline units 1 and 2. As the refunds and taxes owed agreed upon inthe settlement agreement were not materially different from the estimates usedin the impairment analysis, the company determined that no further analysis wasneeded at December 31, 2006.

*Bowline Unit 3.*   TheCompany’s assessment of the Bowline unit 3 suspended construction projectassumed that completion of this project was remote. A strategic review of theCompany’s portfolio of assets in 2006 resulted in the conclusion that theBowline 3 project as currently configured and permitted is not economicallyviable. As a result of this conclusion, the Company determined the estimatedvalue of the equipment and project termination liabilities. At December 31,2006, the carrying value of the development and construction costs for Bowlineunit 3 exceeded the estimated undiscounted cash flows from the abandonmentof the project by $120 million, which is reflected in impairment losses onthe consolidated statements of operations for the year ended December 31,2006. On January 15, 2007, the Company entered into a definitive purchaseand sale agreement with a subsidiary of LS Power Equity Partners I, L.P., LSPower Equity Partners II, L.P. and certain other affiliated funds,(collectively “LS Power”), for the sale of six U.S. natural gas-fired assets,which includes some of the equipment at Bowline unit 3. The transaction isexpected to close in the second quarter of 2007. The sale of the equipment at 

F-25

----

Bowline unit 3 issubject to bankruptcy court approval. A hearing on the motion to sell theBowline 3 equipment is scheduled for March 8, 2007.

**5.**                 AccountsReceivable and Notes Receivable

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

| ** **                                                      | ** ** | **At December 31,** | ** ** |
|-----------------------------------------------------------------|------------|-------------------------------|------------|
| ** **                                                      | ** ** | **2006**                      | ** ** | **2005** | ** ** |
| Customer accounts                                               |       | $                             | 316        |   | $ | 698 |   |
| Notes receivable                                                |       | 20                            |       | 4 |   |
| Other                                                           |       | 88                            |       | 24 |   |
| Less: allowance for uncollectibles                              |       | (32                           | )          | (110 | ) |
| Total receivables                                               |       | 392                           |       | 616 |   |
| Less: long-term receivables included in other  long-term assets |       | (11                           | )          | (27 | ) |
| Total current receivables                                       |       | $                             | 381        |   | $ | 589 |   |

 

**6.**                 Inventory

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

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

 

**7.**                 FinancialInstruments

***Commodity Financial Instruments***

The Company manages the risks around fuel supply andpower to be generated from its physical asset positions. Mirant manages theprice risk associated with asset management activities through a variety ofmethods. Mirant’s Risk Management Policy requires that asset managementactivities are restricted to only those activities that are risk-reducing innature. In addition, the Company, through its proprietary trading and fuel oilmanagement activities, attempts to achieve incremental returns by entering intoenergy contracts where it has specific market expertise or physical assetpositions. Proprietary trading and fuel oil management activities increase riskand expose the Company to risk of loss if prices move differently thanexpected. As of December 31, 2006, Mirant’s Risk Management Policy setsVaR limits with respect to the Company’s proprietary trading and fuel oilmanagement activities of $7.5 million and $5 million, respectively.

Mirant enters into a variety of derivative financialand physical instruments to manage its exposure to the prices of the fuel itacquires for generating electricity, as well as the electricity that it sells.These include contractual agreements, such as forward purchase and saleagreements, futures, swaps and option contracts. Futures are traded on nationalexchanges and swaps are typically traded in OTC financial markets. Optioncontracts are traded on both a national exchange and in OTC financial markets.These contractual agreements have varying terms, notional amounts 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 OTC contracts, as well as other contractualarrangements.

F-26

----

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

Thefair values of Mirant’s price risk management assets and liabilities, net ofcredit reserves, at December 31, 2006, are included in the following table(in millions):

| ** **                        | ** ** | **Net Price Risk** | ** ** | **Net Price Risk** | ** ** | **Net Fair**     | ** ** |
|-----------------------------------|------------|------------------------------|------------|------------------------------|------------|-----------------------|------------|
| ** **                        | ** ** | **Management**               | ** ** | **Management**               | ** ** | **Value at**     | ** ** |
| ** **                        | ** ** | **Assets**                   | ** ** | **Liabilities**              | ** ** | **December 31,** | ** ** |
| ** **                        | ** ** | **Current**                  | ** ** | **Noncurrent**               | ** ** | **Current**           | ** ** | **Noncurrent** | ** ** | **2006** | ** ** |
| Electricity                       |       |                         | $          | 603                          |       |                  |       | $ | 99 |   |   |   | $ | (247 | ) |   |   | $ | (8 | ) |   |   | $ | 447 |   |   |
| Back-to-Back  Agreement(1)        |       |                         | —     |                         |       |                  | —     |   |   |   | (36 | ) |   |   | (389 | ) |   |   | (425 | ) |   |
| Natural Gas                       |       |                         | 21         |                         |       |                  | 1          |   |   |   | (26 | ) |   |   | (2 | ) |   |   | (6 | ) |   |
| Oil                               |       |                         | 83         |                         |       |                  | —     |   |   |   | (10 | ) |   |   | (29 | ) |   |   | 44 |   |   |
| Coal                              |       |                         | 13         |                         |       |                  | —     |   |   |   | (3 | ) |   |   | — |   |   |   | 10 |   |   |
| Other, including  credit reserves |       |                         | (5         | )                            |       |                  | —     |   |   |   | — |   |   |   | — |   |   |   | (5 | ) |   |
| Total                             |       |                         | $          | 715                          |       |                  |       | $ | 100 |   |   |   | $ | (322 | ) |   |   | $ | (428 | ) |   |   | $ | 65 |   |   |

----

(1)          contractual arrangementwith Pepco with respect to certain PPAs, including Pepco’s long-term PPA withPanda and Ohio Edison (the “Back-to-Back Agreement”).

Thefollowing table represents the net price risk management assets and liabilitiesby tenor at December 31, 2006 (in millions):

| ** **                | ** ** | **Back-to-Back  Agreement** | ** ** | **All Other  Agreements** | ** ** |
|---------------------------|------------|-----------------------------|------------|--------------------------------|------------|
| 2007                      |       |                        | $          | (36                            | )          |   |   | $ | 429 |   |   |
| 2008                      |       |                        | (31        | )                              |       |   | 13 |   |   |
| 2009                      |       |                        | (30        | )                              |       |   | 40 |   |   |
| 2010                      |       |                        | (36        | )                              |       |   | 9 |   |   |
| Thereafter                |       |                        | (292       | )                              |       |   | (1 | ) |   |
| Net (liabilities)  assets |       |                        | $          | (425                           | )          |   |   | $ | 490 |   |   |

 

The volumetric weighted average maturity, or weightedaverage tenor, of the price risk management portfolio, excluding the Back-to-BackAgreement, at December 31, 2006, was approximately 11 months. The netnotional amount of the price risk management assets and liabilities, excludingthe Back-to-Back Agreement, at December 31, 2006, was a net short positionof approximately 24 million equivalent MWh.

F-27

----

Thefair values of Mirant’s price risk management assets and liabilities, net ofcredit reserves, at December 31, 2005, are included in the following table(in millions):

| ** **                        | ** ** | **Net Price Risk** | ** ** | **Net Price Risk** | ** ** | **Net Fair**     | ** ** |
|-----------------------------------|------------|------------------------------|------------|------------------------------|------------|-----------------------|------------|
| ** **                        | ** ** | **Management**               | ** ** | **Management**               | ** ** | **Value at**     | ** ** |
| ** **                        | ** ** | **Assets**                   | ** ** | **Liabilities**              | ** ** | **December 31,** | ** ** |
| ** **                        | ** ** | **Current**                  | ** ** | **Noncurrent**               | ** ** | **Current**           | ** ** | **Noncurrent** | ** ** | **2005** | ** ** |
| Electricity                       |       |                         | $          | 448                          |       |                  |       | $ | 61 |   |   |   | $ | (704 | ) |   |   | $ | (20 | ) |   |   | $ | (215 | ) |   |
| Back-to-Back  Agreement           |       |                         | —     |                         |       |                  | —     |   |   |   | (26 | ) |   |   | (417 | ) |   |   | (443 | ) |   |
| Natural Gas                       |       |                         | 113        |                         |       |                  | 19         |   |   |   | (112 | ) |   |   | (20 | ) |   |   | — |   |   |
| Oil                               |       |                         | 21         |                         |       |                  | 11         |   |   |   | (5 | ) |   |   | — |   |   |   | 27 |   |   |
| Coal                              |       |                         | 31         |                         |       |                  | 24         |   |   |   | (2 | ) |   |   | (1 | ) |   |   | 52 |   |   |
| Other, including  credit reserves |       |                         | (11        | )                            |       |                  | —     |   |   |   | — |   |   |   | — |   |   |   | (11 | ) |   |
| Total                             |       |                         | $          | 602                          |       |                  |       | $ | 115 |   |   |   | $ | (849 | ) |   |   | $ | (458 | ) |   |   | $ | (590 | ) |   |

 

***Fair Values***

Financial instruments recorded at market or fair valueinclude cash and interest-bearing cash equivalents, derivative financialinstruments and financial instruments used for price risk management purposes.The following methods were used by Mirant to estimate the fair value of allfinancial instruments that are not subject to compromise and not otherwisecarried at fair value on the accompanying consolidated balance sheets:

*Notesand Other Receivables.**  *Thefair value of Mirant’s notes receivable are estimated using interest rates itwould receive currently for similar types of arrangements.

*NotesPayable and Other Long- and Short-Term Debt.**  *The fair valueof Mirant’s notes payable and long- and short-term debt is estimated usingquoted market prices, when available.

Thecarrying or notional amounts and fair values of Mirant’s financial instrumentsat December 31, 2006 and 2005 are as follows (in millions):

| ** **                                                              | ** ** | **December 31, 2006** | ** ** |
|-------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                              | ** ** | **Carrying Amount**        | ** ** | **Fair Value** | ** ** |
| **Liabilities:**                                                        |       |                            |       |   |   |   |   |   |   |
| Notes payable and  long- and short-term debt—Continuing Operations |       |                            | $          | 3,275 |   |   |   | $ | 3,338 |   |   |
| **Other:**                                                              |       |                            |       |   |   |   |   |   |   |
| Notes and other  receivables—Continuing Operations                 |       |                            | 13         |   |   |   | 13 |   |   |
|                                                                         |            |                                 |            |  |  |  |  |  |  |  |  |

 

| ** **                                                              | ** ** | **December 31, 2005** | ** ** |
|-------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                              | ** ** | **Carrying Amount**        | ** ** | **Fair Value** | ** ** |
| **Liabilities:**                                                        |       |                            |       |   |   |   |   |   |   |
| Notes payable and  long- and short-term debt—Continuing Operations |       |                            | $          | 2,582 |   |   |   | $ | 2,582 |   |   |
| **Other:**                                                              |       |                            |       |   |   |   |   |   |   |
| Notes and other  receivables—Continuing Operations                 |       |                            | 27         |   |   |   | 27 |   |   |
|                                                                         |            |                                 |            |  |  |  |  |  |  |  |  |

 

F-28

----

**8.**                 Property,Plant and Equipment, net

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

| ** **                                                                               | ** ** | **At December 31,** | ** ** | **At December 31,** | ** ** | **Depreciable**        | ** ** |
|------------------------------------------------------------------------------------------|------------|-------------------------------|------------|-------------------------------|------------|------------------------|------------|
| ** **                                                                               | ** ** | **2006**                      | ** ** | **2005**                      | ** ** | **Lives (years)** | ** ** |
| Production                                                                               |       |                          | $          | 2,506                         |       |                   |       | $ | 2,444 |   |   |   | 14  to 36 |   |   |
| Construction work  in progress                                                           |       |                          | 195        |                          |       |                   | 80         |   |   |   | — |   |   |
| Other                                                                                    |       |                          | 208        |                          |       |                   | 201        |   |   |   | 2 to  12 |   |   |
| Suspended  construction projects                                                         |       |                          | 8          |                          |       |                   | 174        |   |   |   | — |   |   |
| Less: accumulated  depreciation, depletion and amortization and provision for impairment |       |                          | (705       | )                             |       |                   | (571       | ) |   |   |   |   |   |
| Total property, plant  and equipment, net                                                |       |                          | $          | 2,212                         |       |                   |       | $ | 2,328 |   |   |   |   |   |   |

 

Property, plant and equipment, net of $3.5 billion and$3.7 billion has been reclassified to assets held for sale in the Company’sconsolidated balance sheets at December 31, 2006 and 2005, respectively.See Note 3 for additional information on assets held for sale.

Suspended construction projects decreased in 2006 dueto the transfer of Contra Costa unit 8 to PG&E pursuant to a Settlement andRelease of Claims Agreement and the impairment loss of $120 million related toBowline unit 3. See California Settlement in Note 23 for additional informationregarding the CC8 assets. See Note 4 for further discussion related toimpairments of long-lived assets.

Depreciation of the recorded cost of property, plantand equipment is recognized on a straight-line basis over the estimated usefullives of the assets. Mirant does not depreciate its suspended constructionproject costs or property, plant and equipment that has been reclassified toassets held for sale. The Company received emissions allowances in theacquisition of the Pepco assets for both SO2 and NOx emissions and the right tofuture allowances. The acquired allowances related to owned facilities areincluded in production assets above, and are depreciated over the average lifeof the related assets.

Mirant 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. For additionalinformation on impairments see Note 4.

**9.**                 IntangibleAssets, net

Followingis a summary of intangible assets at December 31, 2006 and 2005 (inmillions):

| ** **                     | ** ** | ** **                                     | ** ** | **At December 31, 2006** | ** ** | **At December 31, 2005** | ** ** |
|--------------------------------|------------|------------------------------------------------|------------|-----------------------------------------|------------|-----------------------------------------|------------|
| ** **                     | ** ** | **Weighted Average  Amortization  Lives** | ** ** | **Gross  Carrying  Amount**             | ** ** | **Accumulated  Amortization**           | ** ** | **Gross  Carrying  Amount** | ** ** | **Accumulated  Amortization** | ** ** |
| Trading rights                 |       |                                           | 26 years   |                                    |       |                                    | $          | 27 |   |   |   | $ | (3 | ) |   |   | $ | 27 |   |   |   | $ | (2 | ) |   |
| Development  rights            |       |                                           | 37.5 years |                                    |       |                                    | 62         |   |   |   | (9 | ) |   |   | 62 |   |   |   | (7 | ) |   |
| Emissions  allowances          |       |                                           | 32 years   |                                    |       |                                    | 151        |   |   |   | (25 | ) |   |   | 151 |   |   |   | (21 | ) |   |
| Other intangibles              |       |                                           | 26.5 years |                                    |       |                                    | 14         |   |   |   | (3 | ) |   |   | 17 |   |   |   | (2 | ) |   |
| Total other  intangible assets |       |                                           |       |                                    |       |                                    | $          | 254 |   |   |   | $ | (40 | ) |   |   | $ | 257 |   |   |   | $ | (32 | ) |   |

 

F-29

----

Other intangible assets, net of $51 million and $58million related to assets to be sold have been reclassified to assets held forsale in the Company’s consolidated balance sheets at December 31, 2006 and2005, respectively. See Note 3 for additional information on assets held forsale.

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

Development rights represent the right to expandcapacity at certain acquired generating facilities. The existinginfrastructure, including storage facilities, transmission interconnections andfuel delivery systems and contractual rights acquired by Mirant, provide theopportunity 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 consolidated balance sheets.

Substantially all of Mirant’s other remainingintangible assets are subject to amortization and are being amortized on astraight-line basis over their estimated useful lives, ranging from 8 to 40years.

Amortization expense wasapproximately $8 million for the years ended December 31, 2006, 2005and 2004. Assuming no future acquisitions, dispositions or impairments ofintangible assets, amortization expense is estimated to continue at this levelfor each of the next five years.

**10.**          Long-TermDebt

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

| ** **                                            | ** ** | **At  December 31,  2006** | ** ** | **At  December 31,  2005** | ** ** | **Interest Rate** | ** ** | **Secured/  Unsecured** | ** ** |
|-------------------------------------------------------|------------|---------------------------------|------------|---------------------------------|------------|------------------------|------------|-------------------------|------------|
| **Long-term Debt:**                                   | ** ** |                            | ** ** | ** **                      |       |                   | ** ** | ** **              |       | ** ** | ** ** | ** ** | ** ** |
| Mirant Americas  Generation:                          |       |                            |       |                            |       |                   |       |                    |       |   |   |   |   |
| Senior notes:                                         |       |                            |       |                            |       |                   |       |                    |       |   |   |   |   |
| Due 2011                                              |       |                            | $          | 850                             |       |                   |       | $                       | 850        |   |   | 8.30% |   | Unsecured |   |
| Due 2021                                              |       |                            | 450        |                            |       |                   | 450        |                    |       | 8.50% |   | Unsecured |   |
| Due 2031                                              |       |                            | 400        |                            |       |                   | 400        |                    |       | 9.125% |   | Unsecured |   |
| Unamortized debt premium/discount                     |       |                            | (4         | )                               |       |                   | (4         | )                       |       |   |   |   |   |
| Mirant North America:                                 |       |                            |       |                            |       |                   |       |                    |       |   |   |   |   |
| Term loan, due 2007 to 2013                           |       |                            | 693        |                            |       |                   | —     |                    |       | LIBOR  + 1.75% |   | Secured |   |
| Notes, due 2013.                                      |       |                            | 850        |                            |       |                   | 850        |                    |       | 7.375% |   | Unsecured |   |
| Capital leases,  due 2007 to 2015                     |       |                            | 36         |                            |       |                   | 36         |                    |       | 7.375%  - 8.19% |   |   |   |
| Total Mirant Corporation                              |       |                            | 3,275      |                            |       |                   | 2,582      |                    |       |   |   |   |   |
| Less: current  portion of long-term debt              |       |                            | (142       | )                               |       |                   | (3         | )                       |       |   |   |   |   |
| Total long-term  debt, excluding current portion |       |                            | $          | 3,133                           |       |                   |       | $                       | 2,579      |   |   |   |   |   |   |

 

Pursuant to the Plan,Mirant’s wholly-owned subsidiary, Mirant Americas Generation, reinstated$1.7 billion of senior notes maturing in 2011, 2021 and 2031. During 2006,approximately $1.3 billion and $1.1 billion of long-term debt was reclassifiedto liabilities held for sale on the Company’s consolidated balance sheets at December 31,2006 and December 31, 2005, respectively. See Note 3 for additionalinformation on liabilities held for sale.

F-30

----

***Senior Secured Credit Facilities***

Mirant North America, a wholly-owned subsidiary ofMirant Americas Generation, entered into senior secured credit facilities in January 2006,which are comprised of an $800 million six-year senior secured revolvingcredit facility and a $700 million seven-year senior secured term loan.The full amount of the senior secured revolving credit facility is availablefor cash draws or for the issuance of letters of credit. On January 3,2006, Mirant North America drew $465 million under its senior secured revolvingcredit facility. All amounts were repaid during the first quarter of 2006. Thesenior secured term loan was fully drawn at closing and amortizes in 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 January 2013. At the closing, $200 million drawnunder the senior secured term loan was deposited into a cash collateral accountto support the issuance of up to $200 million of letters of credit. As of December 31,2006, there were approximately $198 million of letters of credit outstandingunder the term loan and $6 million outstanding under the revolver. The seniorsecured credit facilities are obligations of Mirant North America and therespective guarantors and are not recourse to any other Mirant entities.

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

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

***Senior Notes***

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

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

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 

F-31

----

35% of the originalprincipal amount of the notes with the proceeds of certain equity offerings ata redemption price of 107.375% of the principal amount of the notes, togetherwith accrued and unpaid interest, if any, to the date of redemption. Under theterms of the notes, the occurrence of a change of control will be a triggeringevent requiring Mirant North America to offer to purchase all or a portion ofthe notes at a price equal to 101% of their principal amount, together withaccrued and unpaid interest, if any, to the date of purchase. In addition,certain asset dispositions or casualty events will be triggering events whichmay require Mirant North America to use the proceeds from those assetdispositions or casualty events to make an offer to purchase the notes at 100%of their principal amount, together with accrued and unpaid interest, if any,to the date of purchase if such proceeds are not otherwise used, or committedto be used, within certain time periods, to repay senior secured indebtedness,to repay indebtedness under the senior secured credit facilities (with acorresponding reduction in commitments) or to invest in capital assets relatedto its business.

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

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

| 2007       |   | $     | 142    |   |
|------------|--------|-------|--------|--------|
| 2008       |   | 10    |   |
| 2009       |   | 11    |   |
| 2010       |   | 11    |   |
| 2011       |   | 861   |   |
| Thereafter |   | 2,240 |   |
| Total      |   | $     | 3,275  |   |

 

Other than for 2007, theannual scheduled maturities above do not include estimates of Mirant NorthAmerica’s required payments of its senior secured term loan based on itsEBITDA.

***Capital Leases***

Long-term debt includes acapital lease by Mirant Chalk Point. At December 31, 2006 and 2005, thecurrent portion of the long-term debt under this capital lease was$3 million and $3 million, respectively. The amount outstanding underthe capital lease, which matures in 2015, is $34 million with an 8.19%annual interest rate. This lease is of an 84 MW peaking electric powergeneration facility. Depreciation expense related to this lease was approximately$2 million for each of the years ended December 31, 2006, 2005 and2004. The annual principal payments under this lease are approximately$3 million in 2007 through 2010, $4 million in 2011 and $18 millionthereafter. The gross amount of assets under the capital lease, recorded inproperty, plant and equipment, net as of December 31, 2006 and 2005, was$24 million. The related accumulated depreciation was $10 million and $8million as of December 31, 2006 and 2005, respectively.

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

The principal sources of liquidity for the Company’sfuture operations and capital expenditures are expected to be: (i) existingcash on hand and cash flows from the operations of the Company’s subsidiaries; (ii) borrowingsunder Mirant North America’s $800 million six-year senior securedrevolving credit facility; and (iii) $200 million of letters ofcredit capacity under Mirant North America’s $700 million term loan.

F-32

----

The Company and certain of its subsidiaries, includingMirant Americas Generation and Mirant North America, are holding companies andas a result, such subsidiaries are dependent upon dividends, distributions andother payments from their respective subsidiaries to generate the fundsnecessary to meet their obligations. The ability of certain of the Company’ssubsidiaries to pay dividends and distributions is restricted under the termsof their debt or other agreements. In particular, a substantial portion of thecash from the Company’s United States operations is generated by MirantMid-Atlantic. The Mirant Mid-Atlantic leveraged leases contain a number ofcovenants, including limitations on dividends, distributions and otherrestricted payments. Under its leveraged leases, Mirant Mid-Atlantic is notpermitted to make any dividends, distributions and other restricted paymentsunless (1) it satisfies the fixed charge coverage ratio on a historicalbasis for the last period of four fiscal quarters, (2) it is projected tosatisfy the fixed charge coverage ratio for the next two periods of four fiscalquarters, and (3) no significant lease default or event of default hasoccurred and is continuing. In the event of a default under the leveragedleases or if the restricted payments test is not satisfied, the cash of MirantMid-Atlantic would not be able to be distributed. Based on the Company’scalculation of the fixed charge coverage ratios under the leveraged leases asof December 31, 2006, Mirant Mid-Atlantic meets the required 1.7 to 1.0ratio for restricted payments, both on a historical and projected basis.

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

**11.**          Investments

For the years ended December 31, 2006 and 2005,the Company completed the sales of investments described below. The relatedgains are recorded in gain on sale of investments, net in the consolidatedstatements of operations.

*EquityInvestment in ICE.*   In the fourth quarter of2005, the Company sold a portion of its investment in ICE for $48 millionand realized a gain of $44 million.In 2006 the Company sold its remaining investment in ICE for $58 millionand realized a gain of $54 million.

*New York MercantileExchange Seats.**  *In late1998 and early 1999, the Company acquired two seats on the New York MercantileExchange for approximately $1.2 million, which were recorded as an investmentin the consolidated balance sheet at December 31, 2005. In the fourthquarter of 2006, the Company sold its investment for $20 million and recognizeda gain of $19 million, which is recorded in gain on sales of investments, neton the Company’s consolidated statement of operations.

**12.**          BankruptcyRelated Disclosures

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

F-33

----

At December 31, 2006 and 2005, amounts related toallowed claims, estimated unresolved claims and professional fees associatedwith the bankruptcy that are to be settled in cash were $28 million and $1.903billion, respectively, and these amounts were recorded in claims payable andestimated claims accrual on the accompanying consolidated balance sheets. Theseamounts do not include unresolved claims that will be settled in common stockor the stock portion of claims that are expected to be settled with cash andstock. During the year ended December 31, 2006, the Company paidapproximately $1.849 billion in cash related to bankruptcy claims. Of thisamount approximately $990 million is reflected in cash flows from financingactivities from continuing operations and $45 million from discontinuedoperations and represents the principal amount of debt claims. The remaining$814 million is reflected in cash flows from operating activities andrepresents other bankruptcy claims and interest. As of December 31, 2006,approximately 21 million of the shares of Mirant common stock to be distributedunder the Plan have not yet been distributed and have been reserved fordistribution with respect to claims that are disputed by the Mirant Debtors andhave yet to be resolved. See Note 23—for further discussion of the Chapter 11proceedings.

***Financial Statements of Subsidiaries in Bankruptcy***

Mirant’s New Yorksubsidiaries remain in bankruptcy and include the following entities: MirantLovett, Mirant Bowline, Mirant NY-Gen, Mirant New York and Hudson ValleyGas Corporation. Consolidated financial statements of Mirant’s New Yorksubsidiaries are set forth below:

**MirantNew York SubsidiariesCondensed Consolidated Statements of Operations Data (in millions)**

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

----

(1)          In2006, reorganization items, net is related to the pre-petition gain on the NewYork Property Tax Settlement.

F-34

----

**MirantNew York SubsidiariesCondensed Consolidated Balance Sheets Data (in millions)**

| ** **                                           | ** ** | **At December 31,** | ** ** |
|------------------------------------------------------|------------|-------------------------------|------------|
| ** **                                           | ** ** | **2006**                      | ** ** | **2005** | ** ** |
| Assets-affiliate                                     |       | $                             | 104        |   | $ | 149 |   |
| Assets-nonaffiliate                                  |       | 223                           |       | 35 |   |
| Property, plant  and equipment, net                  |       | 366                           |       | 502 |   |
| Total assets                                         |       | $                             | 693        |   | $ | 686 |   |
| Liabilities not subject  to compromise:              |       |                          |       |   |   |
| Liabilities-affiliate                                |       | $                             | 28         |   | $ | 36 |   |
| Liabilities-nonaffiliate                             |       | 65                            |       | 177 |   |
| Liabilities  subject to compromise—affiliate    |       | 62                            |       | 62 |   |
| Liabilities  subject to compromise—nonaffiliate |       | 18                            |       | 18 |   |
| Member’s equity                                 |       | 520                           |       | 393 |   |
| Total liabilities  and member’s equity          |       | $                             | 693        |   | $ | 686 |   |

 

**MirantNew York SubsidiariesCondensed Consolidated Statements of Cash Flows Data(in millions)**

| ** **                                                                                | ** ** | **Years Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                                | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| Net cash provided by  (used in):                                                          |       |                                        |       |   |   |   |   |   |   |
| Operating activities                                                                      |       |                                        | $          | 17 |   |   | $ | (18 | ) | $ | (46 | ) |
| Investing activities                                                                      |       |                                        | 72         |   |   | (4 | ) | 41 |   |
| Financing activities                                                                      |       |                                        | 9          |   |   | 23 |   | 5 |   |
| Net increase in  cash and cash equivalents                                                |       |                                        | 98         |   |   | 1 |   | — |   |
| Cash and cash  equivalents, beginning of period        |       |                                        | 1          |   |   | — |   | — |   |
| Cash and cash  equivalents, end of period                                                 |       |                                        | $          | 99 |   |   | $ | 1 |   | $ | — |   |

 

***Liabilities Subject to Compromise***

The Company’s liabilitiessubject to compromise, which relate to its New York subsidiaries that remain inbankruptcy, are $18 million at December 31, 2006 and 2005.

F-35

----

***Reorganization Items, net***

Reorganizationitems, net represents expense, income and gain or loss amounts that wererecorded in the financial statements as a result of the bankruptcy proceedings.In 2006, reorganization items, net relate to refunds received from various NewYork tax jurisdictions for the settlement of the property tax dispute relatedto the New York subsidiaries. Reorganization items, net for the years ended December 31,2006, 2005 and 2004, are comprised of the following (in millions):

| ** **                                                        | ** ** | **Years Ended December 31,** | ** ** |
|-------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                        | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| Gain on the  implementation of the Plan                           |       | $                                           | —     |   | $ | (285 | ) | $ | — |   |
| Gain on New York  property tax settlement                         |       | (163                                        | )          | — |   | — |   |
| Estimated claims  and losses on rejected and amended contracts(1) |       | 2                                           |       | 72 |   | 132 |   |
| Professional fees  and administrative expense                     |       | —                                      |       | 226 |   | 109 |   |
| Interest income,  net                                             |       | (2                                          | )          | (31 | ) | (14 | ) |
| Total                                                             |       | $                                           | (163       | ) | $ | (18 | ) | $ | 227 |   |

----

(1)          Estimated claims andlosses on rejected and amended contracts relate primarily to rejected energycontracts, such as tolling agreements, gas transportation and electrictransmission contracts.

***Interest Expense***

The Statement ofOperations Data for the year ended December 31, 2004, does not includeinterest expense on debt that was subject to compromise subsequent to thePetition Date. In the third quarter of 2005, the Company determined that it wasprobable that contractual interest on liabilities subject to compromise fromthe Petition Date would be incurred for certain claims expected to be allowedunder the Plan. As a result, the Company recorded interest expense ofapproximately $1.4 billion in 2005 on liabilities subject to compromise.This amount represents interest from the Petition Date through the effectivedate of the Plan. The interest amount was calculated based on the provisions ofthe Plan. The $1.4 billion expense amount included approximately$450 million related to Mirant Americas Generation senior notes maturingin 2011, 2021 and 2031, which were reinstated under the confirmed Plan.

**13.**          IncomeTaxes

Income or loss from continuing operations beforeincome taxes for the periods ended December 31, 2006, 2005 and 2004amounted to $1.195 billion of pre-tax income, $1.408 billion of pre-tax lossand $1 million of pre-tax loss, respectively.

Theprovision (benefit) for income taxes from continuing operations is as follows(in millions):

| ** **                               | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------|------------|---------------------------------------------|------------|
| ** **                               | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| Current income  tax provision (benefit)  |       | $                                           | 2          |   | $ | (4 | ) | $ | (18 | ) |
| Deferred income  tax provision (benefit) |       | (580                                        | )          | (14 | ) | 16 |   |
| Benefit for income taxes                 |       | $                                           | (578       | ) | $ | (18 | ) | $ | (2 | ) |

 

F-36

----

Areconciliation of the Company’s federal statutory income tax provision to theeffective income tax provision for continuing operations adjusted forrestructuring items for the years ended December 31, 2006, 2005 and 2004is as follows (in millions):

| ** **                                                                                      | ** ** | **Years Ended December, 31,** | ** ** |
|-------------------------------------------------------------------------------------------------|------------|----------------------------------------------|------------|
| ** **                                                                                      | ** ** | **2006**                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| Provision  (benefit) for income taxes based on United States federal statutory income  tax rate |       | $                                            | 418        |   | $ | (492 | ) | $ | — |   |
| State and local  income tax (benefit), net of federal income taxes                              |       | 77                                           |       | 69 |   | (5 | ) |
| Discontinued  Operations                                                                        |       | (91                                          | )          | (27 | ) | (246 | ) |
| Return to  Provision Adjustments:                                                               |       |                                         |       |   |   |   |   |
| Professional fees during bankruptcy                                                             |       | 65                                           |       | — |   | — |   |
| Previously deferred intercompany gain                                                           |       | 22                                           |       | — |   | — |   |
| Foreign reorganization gain                                                                     |       | 83                                           |       | — |   | — |   |
| Other                                                                                           |       | 50                                           |       | — |   | — |   |
| Anticipated  effect of 382(1)(5)                                                                |       | 297                                          |       | — |   | — |   |
| Taxes accrued on  foreign earnings                                                              |       | 16                                           |       | 31 |   | 64 |   |
| Netherlands NOL  write-off                                                                      |       | —                                       |       | 164 |   | — |   |
| Reorganization  adjustments                                                                     |       | —                                       |       | (91 | ) | — |   |
| Change in  deferred tax asset valuation allowance                                               |       | (1,513                                       | )          | 260 |   | 161 |   |
| Other  differences, net                                                                         |       | (2                                           | )          | 68 |   | 24 |   |
| Tax benefit                                                                                     |       | $                                            | (578       | ) | $ | (18 | ) | $ | (2 | ) |

 

Thetax effects of temporary differences between the carrying amounts of assets andliabilities in the consolidated financial statements and their respective taxbases which give rise to deferred tax assets and liabilities for continuingoperations are as follows (in millions):

| ** **                                                                        | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                        | ** ** | **2006**              | ** ** | **2005** | ** ** |
| **Deferred Tax Assets:**                                                          |       |                  |       |   |   |
| Employee benefits                                                                 |       | $                     | 30         |   | $ | 43 |   |
| Reserves                                                                          |       | 80                    |       | 223 |   |
| Operating and  capital loss carryforwards                                         |       | 1,333                 |       | 1,560 |   |
| Tax basis in  excess of book basis in foreign investments expected to be realized |       | 335                   |       | — |   |
| Property and  intangible assets                                                   |       | 146                   |       | 475 |   |
| Energy marketing  and risk management contracts                                   |       | —                |       | 170 |   |
| Other                                                                             |       | 59                    |       | 282 |   |
| Subtotal                                                                          |       | 1,983                 |       | 2,753 |   |
| Valuation  allowance                                                              |       | (1,115                | )          | (2,628 | ) |
| Net deferred tax assets                                                           |       | $                     | 868        |   | $ | 125 |   |
| **Deferred  Tax Liabilities:**                                                    |       |                  |       |   |   |
| Energy marketing  and risk management contracts                                   |       | (92                   | )          | — |   |
| Taxes accrued on  foreign earnings                                                |       | (15                   | )          | — |   |
| Other                                                                             |       | (40                   | )          | (125 | ) |
| Net deferred tax liabilities                                                      |       | (147                  | )          | (125 | ) |
| Net deferred  taxes                                                               |       | $                     | 721        |   | $ | — |   |

 

The ultimate utilization of the Company’s remainingNOLs will depend on several factors, including the Company’s future financialperformance and certain tax elections. Specifically, Mirant’s utilization of 

F-37

----

NOLs will be affected bywhether the Company elects NOL treatment under Internal Revenue Codesection (“§”) 382(l)(5) or § 382(l)(6). The Companycurrently anticipates that the treatment under § 382(l)(5) of theInternal Revenue Code will apply to Mirant going forward. Under that treatment,Mirant would have use of its NOLs as long as there is not a change of ownership(broadly defined as 50 percent change of “five percent” shareholders)within two years of emergence from bankruptcy. The § 382(l)(5) treatmentrequires us to reduce the Company’s NOLs by $ 1.1 billion due to interestaccrued on debt settled with stock for the three years prior to emergence.Under § 382(l)(6), the Company would be subject to an annual limitation onuse of NOLs. Mirant will make the § 382(l)(5) or § 382(l)(6) electionin its 2006 annual tax return to be filed in 2007. Given the likelihood thatMirant will elect under 382 (l)(5) the Company has adjusted variousdeferred income tax items including the NOLs.

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 determination of a valuation allowancerequires significant judgment as to the generation of taxable income duringfuture periods for which temporary differences are expected to be deductible.In making this determination, management considers all available positive andnegative evidence affecting specific deferred tax assets, including its pastand anticipated future performance, the reversal of deferred tax liabilitiesand the implementation of tax planning strategies.

The company expects to recognize a gain from the saleof its Philippine business in 2007 at the time that transaction is closed andsales proceeds are received. As required by applicable accounting principles,an enterprise that anticipates the realization of a pretax gain must recognizethe benefit or detriment of the deferred tax assets and liabilities associatedwith the transaction in the year in which it becomes more likely than not thatthe gain will be realized. The Company has recognized in 2006 a tax benefit inthe amount of $721 million related to the pending sale of its Philippinebusiness in 2007. This benefit has two components: a) $580 million recognizedfor continuing operations related to the release of the valuation allowancepertaining to deferred assets previously recorded including the estimated valueof the NOLs that will be used to offset the anticipated 2007 taxable gainresulting from the sale; and b) $141 million recognized for the Company’sdiscontinued operations related to the value of the additional difference betweenthe book basis and the tax basis in the shares of the entity being sold. Eachyear, Mirant’s net U.S. Federal deferred tax assets have been reduced by avaluation allowance to reflect the amount that was estimated to be recoverable.It is management’s judgment based on available evidence that it ismore-likely-than-not that deferred tax assets relating to this transaction willbe recoverable in 2007. Management has considered all available positive andnegative evidence affecting these specific deferred tax assets in making thisdecision and has determined the valuation allowance related to such deferredtax assets should be released in 2006. In addition, based on the pending sale of the Philippinebusiness, the Company no longer intends to distribute earnings in the form of adividend prior to the completed sale. As a result, Mirant has recognized anadditional net tax benefit of $124 million in discontinued operations relatedto the reversal of previously accrued foreign withholding taxes.

In the case of the pending sale of the Company’sPhilippine business, the practical effect of the difference in the recognitionstandard for the gain on the sale and that for the associated tax attributes isto cause the tax benefits associated with the sale to be taken into account in2006 (prior to when the gain on the sale is taken into account). As a result,in 2007 when the Company expects to recognize the gain from the sale of thePhilippine business, the transaction will be reflected as fully taxable.

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. Futureperformance relating to the sale of the Philippine assets is the mostcompelling form of positive evidence considered by management in thedetermination of the future recoverability of a portion of its net deferredassets. In 2006, the Company recognized a decrease of $1,513 million in itsvaluation allowance related to 

F-38

----

its net deferred taxassets. In 2005, the Company recognized an increase of $260 million in itsvaluation allowance related to its net deferred tax assets.

As of December 31, 2006, the Company hasapproximately $3.1 billion of U.S. federal NOL carryforwards for financialreporting purposes with expiration dates from 2022 to 2026. Similarly, there isan approximate aggregate amount of $5.2 billion of state NOL carryforwardswith various expiration dates (based on the application of apportionment factorsand other state tax limitations).

Additionally, the Companyhas contingent liabilities related to tax uncertainties arising in the ordinarycourse of business. Mirant periodically assesses its contingent liabilities inconnection with these uncertainties based on the latest information available.For those uncertainties where it is probable that a loss has occurred and theloss or range of loss can be reasonably estimated, a liability is recognized inthe financial statements. The recognition of contingent losses for taxuncertainties requires management to make significant assumptions about theexpected outcomes of certain tax contingencies. On January 1, 2007, theCompany will change its method of determining tax contingencies upon adoptionof FIN 48. Upon initial adoption, the provisions of FIN 48 will be applied toall tax positions. Only tax positions that meet the more-likely-than-notrecognition threshold at the effective date may be recognized or continue to berecognized. The Company anticipates that the adoption of FIN 48 willresult in a decrease in accrued liabilities and liabilities held for salethat together will be approximately $50 million to $125 million. Thedecreases in accrued liabilities and liabilities held for sale will result inan increase of retained earnings of the same amount.

**14.**          EmployeeBenefit Plans

***Pension Plans***

Mirant offers pension benefits to its non-union andunion employees through various defined benefit and defined contributionpension plans. These benefits are based on pay, service history and age atretirement. Defined benefit pensions are not provided for non-union employeeshired after April 1, 2000, who participate in a profit sharingarrangement. Most pension benefits are provided through tax-qualified plansthat are funded in accordance with ERISA and Internal Revenue Servicerequirements. Certain executive pension benefits that cannot be provided by thetax-qualified plans are provided through unfunded non-tax-qualified plans. Themeasurement date for the defined benefit plans is September 30 for eachyear presented.

As discussed in Note 2, SFAS No. 158 was adoptedas of December 31, 2006. SFAS No. 158 is designed to improvefinancial reporting by requiring an employer to recognize the overfunded orunderfunded status of pension, retiree medical, and other postretirementbenefit plans in its balance sheets rather than merely disclosing the fundedstatus in the financial statement footnotes. The Company adopted SFAS No. 158on December 31, 2006, and recognized an increase in other noncurrentliabilities of $21 million related to its underfunded domestic defined benefitpension plans.

F-39

----

Thefollowing table shows the obligations and funded status for the defined benefitpension plans of Mirant’s continuing operations (in millions):

| ** **                                    | ** ** | **Tax-  Qualified** | ** ** | **Non-Tax Qualified** | ** ** |
|-----------------------------------------------|------------|---------------------|------------|----------------------------|------------|
| ** **                                    | ** ** | **2006**            | ** ** | **2005**                   | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Change in benefit obligation:**             |       |                |       |                       |       |   |   |   |   |   |   |   |
| Benefit  obligation, beginning of year        |       | $                   | 245        |                       | $          | 202 |   |   | $ | 12 |   |   | $ | 9 |   |   |
| Service cost                                  |       | 10                  |       | 9                          |       |   | — |   |   | — |   |   |
| Interest cost                                 |       | 13                  |       | 11                         |       |   | 1 |   |   | 1 |   |   |
| Benefits paid                                 |       | (7                  | )          | (6                         | )          |   | — |   |   | — |   |   |
| Actuarial (gain) loss                         |       | (17                 | )          | 29                         |       |   | (4 | ) |   | 2 |   |   |
| Benefit obligation, end of year               |       | $                   | 244        |                       | $          | 245 |   |   | $ | 9 |   |   | $ | 12 |   |   |
| **Change in plan assets:**                    |       |                |       |                       |       |   |   |   |   |   |   |   |
| Fair value of  plan assets, beginning of year |       | $                   | 109        |                       | $          | 89 |   |   | $ | — |   |   | $ | — |   |   |
| Return on plan assets                         |       | 11                  |       | 11                         |       |   | — |   |   | — |   |   |
| Employer contributions                        |       | 38                  |       | 15                         |       |   | — |   |   | — |   |   |
| Benefits paid                                 |       | (7                  | )          | (6                         | )          |   | — |   |   | — |   |   |
| Fair value of plan assets, end of year        |       | $                   | 151        |                       | $          | 109 |   |   | $ | — |   |   | $ | — |   |   |
| **Funded Status:**                            |       |                |       |                       |       |   |   |   |   |   |   |   |
| Funded status at  measurement date            |       | $                   | (93        | )                          | $          | (136 | ) |   | $ | (9 | ) |   | $ | (12 | ) |   |

 

The accumulated benefit obligation exceeded the fairvalue of plan assets at year-end 2006 for all pension plans. The totalaccumulated benefit obligation as of September 30, 2006, was $210 million.

Therates assumed in the actuarial calculations for measuring year-end pensionobligations as of their respective measurement dates are listed in the tablebelow. The discount rate is based on the Moody’s Aa Corporate Bond Rate as of September 30.

| ** **                      | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------|------------|----------|------------|----------|------------|
| Discount rate                   |       | 5.66     | %          | 5.36     | %          |
| Rate of compensation  increases |       | 3.70     | %          | 3.82     | %          |

 

Amountsrecognized in the consolidated balance sheet at December 31, 2006, underSFAS No. 158 (in millions):

| ** **                                             | ** ** | **Tax-Qualified** | ** ** | **Non-Tax Qualified** | ** ** |
|--------------------------------------------------------|------------|-------------------|------------|----------------------------|------------|
| Noncurrent  liabilities                                |       |              | $          | (93                        | )          |   |   | $ | (9 | ) |   |
| Total amount  recognized at measurement date           |       |              | $          | (93                        | )          |   |   | $ | (9 | ) |   |
| Total amount recognized  on consolidated balance sheet |       |              | $          | (93                        | )          |   |   | $ | (9 | ) |   |
|                                                   |       |              |       |                       |       |   |   |   |   |

 

F-40

----

Amountsrecognized in the consolidated balance sheet at December 31, 2005, underprior accounting rules are as follows (in millions):

| ** **                                                               | ** ** | **Tax-  Qualified** | ** ** | **Non-Tax   Qualified** | ** ** |
|--------------------------------------------------------------------------|------------|---------------------|------------|------------------------------|------------|
| Funded status at  measurement date                                       |       |                | $          | (136                         | )          |   |   | $ | (12 | ) |   |
| Unrecognized  prior service cost                                         |       |                | 3          |                         |       |   | 2 |   |   |
| Unrecognized net  actuarial loss                                         |       |                | 37         |                         |       |   | 6 |   |   |
| Net  prepaid/(accrued) pension benefit cost                              |       |                | (96        | )                            |       |   | (4 | ) |   |
| Intangible asset                                                         |       |                | —     |                         |       |   | (2 | ) |   |
| Additional  liability recognized in accumulated other comprehensive loss |       |                | —     |                         |       |   | (3 | ) |   |
| Total liability  recognized                                              |       |                | (96        | )                            |       |   | (9 | ) |   |
| Fourth quarter  funding                                                  |       |                | 3          |                         |       |   | — |   |   |
| Total liability  recognized on consolidated balance sheet                |       |                | $          | (93                          | )          |   |   | $ | (9 | ) |   |

 

Amountsrecognized in accumulated other comprehensive income at December 31, 2006,under SFAS No. 158 (in millions):

| ** **                                                   | ** ** | **Tax-  Qualified** | ** ** | **Non-Tax   Qualified** | ** ** |
|--------------------------------------------------------------|------------|---------------------|------------|------------------------------|------------|
| Net loss                                                     |       |                | $          | (17                          | )          |   |   | $ | (1 | ) |   |
| Prior service  credit                                        |       |                | (3         | )                            |       |   | (3 | ) |   |
| Total amounts included  in accumulated other cumulative loss |       |                | $          | (20                          | )          |   |   | $ | (4 | ) |   |

 

*Expectedamortization payments.*   The estimated net lossand prior service cost for the defined benefit pension plans that will beamortized from accumulated other comprehensive income into net periodic benefitcost over the next fiscal year are $0.2 and $0.5 million, respectively.

Thecomponents of the net periodic cost of Mirant’s pension plans for the yearsended December 31, 2006, 2005 and 2004 are shown below (in millions):

| ** **                      | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------|------------|---------------------------------------------|------------|
| ** **                      | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| Service cost                    |       | $                                           | 10         |   |   | $ | 9 |   |   |   | $ | 10 |   |   |
| Interest cost                   |       | 14                                          |       |   | 12 |   |   |   | 11 |   |   |
| Expected return  of plan assets |       | (10                                         | )          |   | (8 | ) |   |   | (7 | ) |   |
| Net  amortization(1)            |       | 2                                           |       |   | — |   |   |   | — |   |   |
| Net periodic pension  cost      |       | $                                           | 16         |   |   | $ | 13 |   |   |   | $ | 14 |   |   |

----

(1)          Amount includesunrecognized transition obligation or asset, prior service cost and actuarialgains or losses.

Therates assumed in the actuarial calculations for measuring pension cost eachyear were as follows:

| ** **                      | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------|------------|----------|------------|----------|------------|
| Discount rate                   |       | 5.36     | %          | 5.73     | %          |
| Rate of  compensation increase  |       | 3.82     | %          | 3.00     | %          |
| Expected return on plan  assets |       | 8.50     | %          | 8.50     | %          |

 

In determining the long-term rate of return forplan assets, historical markets and current market factors such as inflationand interest rates are evaluated before long-term capital marketassumptions are 

F-41

----

determined andconsideration of diversification and portfolio rebalancing is given. Peer dataand historical returns are reviewed to check for reasonableness andappropriateness.

Thefollowing table shows the target allocation and percentage of fair value ofplan assets by asset category for Mirant’s qualified pension plans for 2006 and2005:

| ** **      | ** ** | **2006**               | ** ** | **2005**                                                             | ** ** |
|-----------------|------------|------------------------|------------|----------------------------------------------------------------------|------------|
| ** **      | ** ** | **Target  Allocation** | ** ** | **Percent of  Fair Value  of  Plan Assets** | ** ** | **Target  Allocation** | ** ** | **Percent of  Fair Value of  Plan Assets** | ** ** |
| U.S. Stocks     |       |                   | 55         | %                                                                    |       |   | 56 | % |   |   | 55 | % |   |   | 54 | % |   |
| Non-U.S. Stocks |       |                   | 15         |                                                                 |       |   | 14 |   |   |   | 15 |   |   |   | 16 |   |   |
| Fixed income    |       |                   | 30         |                                                                 |       |   | 30 |   |   |   | 30 |   |   |   | 30 |   |   |
| Total           |       |                   | 100        | %                                                                    |       |   | 100 | % |   |   | 100 | % |   |   | 100 | % |   |

 

For the qualified pension plans, Mirant uses a mix ofequities and fixed income investments in an attempt to maximize the long-termreturn of plan assets for a prudent level of risk. Risk tolerance isestablished through consideration of plan liabilities, plan funded status andcorporate financial condition. Equity investments are diversified across U.S.and non-U.S. stocks. For U.S. stocks, Mirant employs both a passive and active approachby investing in an index that mirrors the Russell 1000 Index and an activelymanaged small cap fund. For non-U.S. stocks, Mirant is invested in the InvescoInternational Equity Fund that is benchmarked against the EAFE Index. Fixedincome investments include a passive bond market index fund which seeks toreplicate the Lehman Brothers Aggregate Bond Index. Investment risk ismonitored on an ongoing basis through quarterly portfolio reviews and annualpension liability measurements.

During2007, Mirant expects to contribute approximately $22 million to thedomestic qualified pension plans and approximately $0.2 million to thedomestic non-tax-qualified pension plans. Additionally, Mirant expects thefollowing benefits to be paid from the pension plans (in millions):

| **Projected Benefit Payments to  Plan Participants** | ** ** | ** ** | ** ** | **Tax-  Qualified** | ** ** | **Non-Tax  Qualified** | ** ** |
|--------------------------------------------------------------------------|------------|------------|------------|---------------------|------------|------------------------|------------|
| 2007                                                                     |       |       | $          | 6.9                 |       |                   |       | $ | 0.2 |   |   |
| 2008                                                                     |       |       | 7.5        |                |       |                   | 0.3        |   |   |
| 2009                                                                     |       |       | 7.9        |                |       |                   | 0.3        |   |   |
| 2010                                                                     |       |       | 8.5        |                |       |                   | 0.3        |   |   |
| 2011                                                                     |       |       | 9.3        |                |       |                   | 0.3        |   |   |
| 2012 through 2016                                                        |       |       | 68.2       |                |       |                   | 2.0        |   |   |

 

***Other Postretirement Benefits***

Mirant also provides certain medical care and lifeinsurance benefits for eligible retired employees which are accounted for on anaccrual basis using an actuarial method that recognizes the net periodic costsas employees render service to earn the postretirement benefits. Themeasurement date for these domestic other postretirement benefit plans is September 30for each year presented.

As discussed in Note 2, SFAS No. 158 was adoptedas of December 31, 2006. SFAS No. 158 is designed to improvefinancial reporting by requiring an employer to recognize the overfunded orunderfunded status of pension, retiree medical, and other postretirementbenefit plans in its balance sheets rather than merely disclosing the fundedstatus in the financial statement footnotes. The Company adopted SFAS No. 158on December 31, 2006, and recognized a decrease in other noncurrentliabilities of $5 million related to its other postretirement benefit plans.

F-42

----

During the fourth quarter of 2006, Mirant amended thepostretirement benefit plan covering nonunion employees to eliminate allemployer provided subsidies through a gradual phase-out by 2011. Since thisaction occurred after the measurement date, it is not reflected in the figuresshown for year-end 2006, but will be recognized during the first quarter offiscal 2007 as a plan curtailment. As a result, Mirant expects to recognize areduction in other postretirement liabilities of approximately $32 million.

Thefollowing table shows the obligations and funded status for otherpostretirement benefit plans of Mirant (in millions):

| ** **                             | ** ** | **Years Ended  December 31,** | ** ** |
|----------------------------------------|------------|-----------------------------------------|------------|
| ** **                             | ** ** | **2006**                                | ** ** | **2005** | ** ** |
| **Change in benefit obligation:**      |       |                                    |       |   |   |
| Benefit  obligation, beginning of year |       | $                                       | 127        |   | $ | 135 |   |
| Service cost                           |       | 4                                       |       | 4 |   |
| Interest cost                          |       | 7                                       |       | 8 |   |
| Amendments                             |       | (17                                     | )          | (33 | ) |
| Actuarial (gain) loss                  |       | (11                                     | )          | 16 |   |
| Benefits paid                          |       | (3                                      | )          | (3 | ) |
| Benefit obligation, end of year        |       | $                                       | 107        |   | $ | 127 |   |
| **Change in plan assets:**             |       |                                    |       |   |   |
| Employer contributions                 |       | $                                       | 3          |   | $ | 3 |   |
| Benefits paid                          |       | (3                                      | )          | (3 | ) |
| Fair value of plan assets, end of year |       | $                                       | —     |   | $ | — |   |
| **Funded Status:**                     |       |                                    |       |   |   |
| Funded status at  measurement date     |       | $                                       | (107       | ) | $ | (127 | ) |

 

Weightedaverage rates assumed in the actuarial calculations for other postretirementbenefit obligations as of their respective measurement dates were as follows:

| ** **                               | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|
| Discount rate                            |       | 5.66     | %          | 5.36     | %          |
| Rate of  compensation increases          |       | 3.00     | %          | 3.00     | %          |
| Assumed medical  inflation for next year |       |     |       |     |       |
| Before age 65                            |       | 9.00     | %          | 10.00    | %          |
| After age 65                             |       | 11.00    | %          | 12.50    | %          |
| Assumed ultimate  medical inflation rate |       | 5.00     | %          | 5.00     | %          |
| Year in which ultimate  rate is reached  |       | 2011     |       | 2011     |       |

 

An annual increase or decrease in the assumed medicalcare cost trend rate of 1% would correspondingly increase or decrease the totalaccumulated benefit obligation at December 31, 2006, by $0.2 million.

F-43

----

Amountsrecognized in the consolidated balance sheet at December 31, 2006, underSFAS No. 158 are as follows (in millions):

| ** **                                     | ** ** | **December 31,** | ** ** |
|------------------------------------------------|------------|-----------------------|------------|
| ** **                                     | ** ** | **2006**              | ** ** |
| Current  liabilities                           |       |                  | $          | (4 | ) |   |
| Noncurrent  liabilities                        |       |                  | (103       | ) |   |
| Total amount  recognized at measurement date   |       |                  | (107       | ) |   |
| Employer  contributions after measurement date |       |                  | 1          |   |   |
| Total amount recognized  at year-end           |       |                  | $          | (106 | ) |   |

 

Amountsrecognized in the consolidated balance sheet at December 31, 2005, underprior accounting rules are as follows (in millions):

| ** **                                         | ** ** | **December 31,** | ** ** |
|----------------------------------------------------|------------|-----------------------|------------|
| ** **                                         | ** ** | **2005**              | ** ** |
| Funded status at  measurement date                 |       |                  | $          | (127 | ) |   |
| Unrecognized net  actuarial loss                   |       |                  | 57         |   |   |
| Unrecognized  prior service credit                 |       |                  | (35        | ) |   |
| Employer  contributions after measurement date     |       |                  | 1          |   |   |
| Net prepaid/(accrued)  postretirement benefit cost |       |                  | $          | (104 | ) |   |

 

Amountsrecognized in accumulated other comprehensive income at December 31, 2006,under SFAS No. 158 are as follows (in millions):

| ** **                                                     | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                     | ** ** | **2006**              | ** ** |
| Net loss                                                       |       |                  | $          | (43 | ) |   |
| Prior service  cost                                            |       |                  | 48         |   |   |
| Total amounts included  in accumulated other cumulative income |       |                  | $          | 5 |   |   |

 

*Expectedamortization payments.*   The estimated net lossand prior service credit for other postretirement benefit plans that will beamortized from accumulated other comprehensive income into net periodic benefitcost over the next fiscal year are $3 and $(7) million, respectively.These expected amortizations are based on the plans as they existed at themeasurement date and, as such, do not reflect the effects of the gradualphase-out of retiree welfare subsidies for nonunion employees beginning in2007.

Thecomponents of the net expense for Mirant’s postretirement benefit plans duringthe years ended December 31, are shown below (in millions):

| ** **                          | ** ** | **Years Ended  December 31,** | ** ** |
|-------------------------------------|------------|-----------------------------------------|------------|
| ** **                          | ** ** | **2006**                                | ** ** | **2005** | ** ** | **2004** | ** ** |
| Service cost                        |       |                                    | $          | 4 |   |   |   | $ | 4 |   |   |   | $ | 4 |   |   |
| Interest cost                       |       |                                    | 7          |   |   |   | 8 |   |   |   | 7 |   |   |
| Net amortization                    |       |                                    | (1         | ) |   |   | 2 |   |   |   | 1 |   |   |
| Net postretirement  benefit expense |       |                                    | $          | 10 |   |   |   | $ | 14 |   |   |   | $ | 12 |   |   |

 

F-44

----

The weighted average ratesassumed in the actuarial calculations for Mirant’s postretirement benefit costsduring each year are shown below:

| ** **                                  | ** ** | **December 31,** | ** ** |
|---------------------------------------------|------------|-----------------------|------------|
| ** **                                  | ** ** | **2006**              | ** ** | **2005** | ** ** |
| Discount rate                               |       | 5.36                  | %          | 5.73 | % |
| Rate of  compensation increases             |       | 3.00                  | %          | 3.00 | % |
| Assumed medical  inflation for current year |       |                  |       |   |   |
| Before age 65                               |       | 10.00                 | %          | 11.00 | % |
| After age 65                                |       | 12.50                 | %          | 14.00 | % |
| Assumed ultimate  medical inflation rate    |       | 5.00                  | %          | 5.00 | % |
| Year in which ultimate  rate is reached     |       | 2011                  |       | 2011 |   |

 

An annual increaseor decrease in the assumed medical care cost trend rate of 1% wouldcorrespondingly increase or decrease the aggregate of the service and interestcost components of the annual postretirement benefit cost in 2006 byapproximately $0.3 million.

In 2007, Mirant expects tocontribute approximately $4 million to pay other postretirement benefits forretired domestic employees. Additionally, Mirant expects the following netbenefits to be paid from the postretirement benefit plans (in millions):

| **Projected Benefit Payments to   Plan Participants** | ** ** | ** ** | ** ** | **Before  Medicare  Subsidy** | ** ** | **Medicare  Subsidy** | ** ** |
|--------------------------------------------------------------------------------|------------|------------|------------|-------------------------------|------------|-----------------------|------------|
| 2007                                                                           |       |       | $          | 4.0                           |       |                  |       | $ | 0.0 |   |   |
| 2008                                                                           |       |       | 4.7        |                          |       |                  | 0.0        |   |   |
| 2009                                                                           |       |       | 5.2        |                          |       |                  | 0.1        |   |   |
| 2010                                                                           |       |       | 5.7        |                          |       |                  | 0.1        |   |   |
| 2011                                                                           |       |       | 6.0        |                          |       |                  | 0.1        |   |   |
| 2012 through 2016                                                              |       |       | 37.4       |                          |       |                  | 1.0        |   |   |

 

***EmployeeSavings Plan***

The Company maintains adefined contribution employee savings plan with a profit sharing arrangementwhereby employees may contribute a portion of their base compensation to theemployee savings plan, subject to limits under the Internal Revenue Code. TheCompany provides a matching contribution each payroll period equal to 75% ofthe employee’s contributions up to 6% of the employee’s pay for that period(match levels vary by bargaining unit). Under the profit sharing arrangement,the Company contributes a quarterly fixed contribution of 3% of eligible payand may make an annual discretionary contribution for those employees notaccruing a benefit under the defined benefit pension plan. Expenses recognizedfor the matching and profit sharing contributions were as follows (in millions):

| ** ** | ** ** | **Matching** | ** ** | **Profit  Sharing  Arrangement** | ** ** |
|------------|------------|--------------|------------|----------------------------------|------------|
| 2006       |       |         | $          | 5                                |       |   |   | $ | 3 |   |   |
| 2005       |       |         | 5          |                             |       |   | 4 |   |   |
| 2004       |       |         | 5          |                             |       |   | 2 |   |   |

 

***Stock-based Compensation***

The Mirant Corporation2005 Omnibus Incentive Plan for certain employees and directors of Mirantbecame effective on January 3, 2006. The Omnibus Incentive Plan providesfor the granting of 

F-45

----

nonqualified stock options, incentive stock options,stock appreciation rights, restricted stock, restricted stock units,performance shares, performance units, cash-based awards, other stock-basedawards, covered employee annual incentive awards and non-employee directorawards. Under the Omnibus Incentive Plan, 18,575,851 shares of Mirantcommon stock are available for issuance to participants. Shares covered by anaward are counted as used only to the extent that they are actually issued. Anyshares related to awards that terminate by expiration, forfeiture, cancellationor otherwise without the issuance of such shares will be available again forgrant under the Omnibus Incentive Plan. The Company had both service conditionand performance condition forms of stock-based compensation at December 31,2006.

In the first quarter of2006, the Company made grants of stock options, restricted stock, andrestricted stock units totaling 3.3 million. In addition, the Company grantedan additional 300,000 awards related to the hiring of new employees during2006. These grants vest based on a required length of service with the Company.

On October 5, 2006,the Compensation Committee of the Board of Directors of Mirant Corporationapproved the implementation of a special bonus plan to reward participants forsuccessful completion of the Company’s planned business and asset sales as wellas to provide certain participants with an incentive to remain with theCompany. The grants consisted of cash and restricted stock units. On November 13,2006, the Company’s Compensation Committee, pursuant to the Company’s 2005Omnibus Incentive Plan, awarded certain equity grants to five executivemanagement members. The grants consist of options to acquire the Company’scommon stock and restricted stock units. These grants are consideredperformance condition awards, as the payout under the November 13, 2006,awards is based on achieving certain target amounts related to the sales of theCompany’s Philippines and Caribbean businesses and the six gas-fired plants inthe United States. The achievement of the target amounts was deemed probable onthe date of grant and at December 31, 2006.

As discussed in Note 2,SFAS No. 123R was adopted by the Company during the first quarter of 2006,using the modified prospective transition method. For the year ended December 31,2006, the Company recognized approximately $16 million and $1 million,respectively, of expense related to service condition and performance conditionstock-based compensation. These amounts are included in operations andmaintenance expense in the consolidated statements of operations.

As of December 31, 2006, there was approximately$25 million and $11 million of total unrecognized compensation cost related tonon-vested share-based compensation granted through service condition andperformance condition awards, respectively. That cost is expected to berecognized on a straight-line basis over a weighted-average period of1.2 years.

Prior to the Company’sadoption of SFAS No.123R, Mirant accounted for stock-based employeecompensation plans under the intrinsic-value method of accounting forrecognition, but disclosed fair value pro forma information. Under that method,compensation expense for employee stock options is measured on the date ofgrant only if the current market price of the underlying stock exceeds theexercise price. The following table illustrates the effect on net income forthe years ended December 31, 2005 and 2004, if the fair-value-based methodhad been applied to all outstanding and unvested stock-based awards(in millions):

| ** **                                                                                                                                              | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                                                                                              | ** ** | **2005**                                    | ** ** | **2004** | ** ** |
| Net loss, as  reported                                                                                                                                  |       | $                                           | (1,307     | ) | $ | (476 | ) |
| Deduct: Total  stock-based employee compensation expense determined under fair-value-based  method for all awards, net of related tax effects |       | (3                                          | )          | (12 | ) |
| Pro forma net loss                                                                                                                                      |       | $                                           | (1,310     | ) | $ | (488 | ) |

 

F-46

----

Pursuant to the Plan, allshare-based payment awards issued prior to the Company’s emergence frombankruptcy were cancelled. As a result, the presentation of information abovefor the periods ending December 31, 2005 and 2004, is not comparable tothe information that follows for the period ending December 31, 2006,because the instruments in existence at December 31, 2005 and 2004, do notexist at December 31, 2006. Additionally, the Company’s pre-bankruptcycapital structure differed significantly from the Company’s post-emergencecapital structure, further degrading comparability between the pre-emergenceand post-emergence periods.

***Stock Options***

The fair value of stockoptions is estimated on the date of grant using a Black-Scholes option-pricingmodel based on the assumptions noted in the following table. Due to the Company’sbankruptcy and other factors, historical information concerning the Company’sstock price volatility for purposes of valuing stock option grants is notsufficient. Therefore, the implied volatility derived from peer group companieswas used as the basis for valuing the stock options granted through September 30,2006. Beginning in the fourth quarter 2006, the Company re-evaluated the use ofimplied volatility derived from peer group companies and determined thatsufficient evidence existed to place exclusive reliance on Mirant’s own impliedvolatility of its traded options in accordance with SAB No. 107. Due tothe lack of exercise history for the Company, the simplified method forestimating expected term has been used in accordance with SAB No. 107,to the extent applicable. For performance condition awards, the Companyutilized the contractual term as the expected term. The risk-free rate forperiods within the contractual term of the stock option is based on the U.S.Treasury yield curve in effect at the time of the grant. The table belowincludes significant assumptions used in valuing the Company’s stock options:

| ** **                   | ** ** | **Range**     | ** ** | **Weighted  Average** | ** ** |
|------------------------------|------------|---------------|------------|-----------------------|------------|
| Expected  volatility         |       | 21 - 37%      |       | 31.6%                 | ** ** |
| Expected  dividends          |       | 0%            |       | 0%                    | ** ** |
| Expected term                |       |          |       |                  |       |
| Service condition awards     |       | 5.2 - 6 years |       | 5.9 years             | ** ** |
| Performance condition awards |       | 3 years       |       | 3 years               | ** ** |
| Risk-free rate               |       | 4.3 - 5.1%    |       | 4.5%                  | ** ** |

 

*ServiceCondition Awards*

During 2006, Mirant madeawards of approximately 3 million nonqualified stock options. Theseoptions were granted with a 10-year term. Approximately 1.1 millionoptions vest in three equal installments on each of the first, second and thirdanniversaries of the grant date. Approximately 41,000 options vest one yearfrom the grant date. The remaining 1.8 million options vest 25% six monthsfrom the grant date, and 25% on each of the first, second and thirdanniversaries of the grant date. The granted options provide for acceleratedvesting if there is a change of control (as defined in the Omnibus IncentivePlan) or, in certain circumstances, as a result of a termination of employment.Approximately 525,000 options vested during the year. Of the total options thatvested during the year ended December 31, 2006, approximately 87,000became exercisable as a result of the termination of certain employees.

F-47

----

The weighted averagegrant-date fair value of stock options granted during the year ended December 31,2006, was $10.42. A summary of option activity under the Omnibus Incentive Planas of December 31, 2006, and changes during the year then ended ispresented below:

| ** **                                                   | ** ** | ** ** | ** ** | ** **         | ** ** | **Weighted**            | ** ** | ** **    | ** ** |
|--------------------------------------------------------------|------------|------------|------------|--------------------|------------|-------------------------|------------|---------------|------------|
| ** **                                                   | ** ** | ** ** | ** ** | ** **         | ** ** | **Average**             | ** ** | ** **    | ** ** |
| ** **                                                   | ** ** | ** ** | ** ** | ** **         | ** ** | **Remaining**           | ** ** | **Aggregate** | ** ** |
| ** **                                                   | ** ** | ** ** | ** ** | **Weighted**       | ** ** | **Contractual**         | ** ** | **Intrinsic** | ** ** |
| ** **                                                   | ** ** | **Number** | ** ** | **Average**        | ** ** | **Term**                | ** ** | **Value**     | ** ** |
| **Stock Options**                                       | ** ** | ** ** | ** ** | **of Shares** | ** ** | **Exercise Price** | ** ** | **(years)**   | ** ** | **(in thousands)** | ** ** |
| Outstanding at  beginning of the year                   |       | —     |       |               | —     |                    |       |          | —     |   |   |   | — |   |   |
| Changes during the year  to date:                            |       |       |       |               |       |                    |       |          |       |   |   |   |   |   |   |
| Granted                                                      |       | 2,987,936  |       |               | $          | 24.89                   |       |          |       | — |   |   |   | — |   |   |
| Exercised or converted                                       |       | (23,287    | )          |               | $          | 25.05                   |       |          |       | — |   |   |   | — |   |   |
| Forfeited                                                    |       | (162,930   | )          |               | $          | 24.96                   |       |          |       | — |   |   |   | — |   |   |
| Expired                                                      |       | —     |       |               | —     |                    |       |          | —     |   |   |   | — |   |   |
| Outstanding at  the end of the year                          |       | 2,801,719  |       |               | $          | 24.89                   |       |          |       | 9.2 |   |   |   | $ | 18,720 |   |   |
| Exercisable or  convertible at the end of the year |       | 501,669    |       |               | $          | 24.83                   |       |          |       | 9.1 |   |   |   | $ | 3,379 |   |   |
|                                                              |            |            |            |                    |            |                         |            |               |            |  |  |  |  |  |  |  |  |  |  |

 

On November 13, 2006,Mirant made awards of approximately 830,000 nonqualified stock options to fivemembers of executive management. These options were granted with a 3-yearterm and cliff vest in approximately 18 months on June 30, 2008, providedthat the Company achieves the performance target amounts by December 31,2007. The granted options provide for accelerated vesting if there is a changeof control (as defined in the Omnibus Incentive Plan) or, in certaincircumstances, as a result of a termination of employment. The weighted averagegrant date fair value of performance condition stock options granted during theyear ended December 31, 2006, was $6.08. A summary of option activity forperformance condition awards under the Omnibus Incentive Plan as of December 31,2006, and changes during the year ended is presented below:

| ** **                                                   | ** ** | ** ** | ** ** | ** **         | ** ** | **Weighted**            | ** ** | ** **    | ** ** |
|--------------------------------------------------------------|------------|------------|------------|--------------------|------------|-------------------------|------------|---------------|------------|
| ** **                                                   | ** ** | ** ** | ** ** | ** **         | ** ** | **Average**             | ** ** | ** **    | ** ** |
| ** **                                                   | ** ** | ** ** | ** ** | ** **         | ** ** | **Remaining**           | ** ** | **Aggregate** | ** ** |
| ** **                                                   | ** ** | ** ** | ** ** | **Weighted**       | ** ** | **Contractual**         | ** ** | **Intrinsic** | ** ** |
| ** **                                                   | ** ** | **Number** | ** ** | **Average**        | ** ** | **Term**                | ** ** | **Value**     | ** ** |
| **Stock Options**                                       | ** ** | ** ** | ** ** | **of Shares** | ** ** | **Exercise Price** | ** ** | **(years)**   | ** ** | **(in thousands)** | ** ** |
| Outstanding at  beginning of the year                   |       | —     |       |               | —     |                    |       |          | —     |   |   |   | — |   |   |
| Changes during the year  to date:                            |       |       |       |               |       |                    |       |          |       |   |   |   |   |   |   |
| Granted                                                      |       | 830,000    |       |               | $          | 28.89                   |       |          |       | — |   |   |   | — |   |   |
| Exercised or converted                                       |       | —     |       |               | —     |                    |       |          | —     |   |   |   | — |   |   |
| Forfeited                                                    |       | —     |       |               | —     |                    |       |          | —     |   |   |   | — |   |   |
| Expired                                                      |       | —     |       |               | —     |                    |       |          | —     |   |   |   | — |   |   |
| Outstanding at  the end of the year                          |       | 830,000    |       |               | $          | 28.89                   |       |          |       | 2.9 |   |   |   | $ | 2,224 |   |   |
| Exercisable or  convertible at the end of the year |       | —     |       |               | —     |                    |       |          | —     |   |   |   | — |   |   |
|                                                              |            |            |            |                    |            |                         |            |               |            |  |  |  |  |  |  |  |  |  |  |

 

Cash received from the exercise of stock options underthe Omnibus Incentive Plan for the year ended December 31, 2006, wasapproximately $583,000 and no tax benefit was realized during the year thenended.

F-48

----

***Non-Vested Sharesand Share Units***

*ServiceCondition Awards*

The Company alsoissued approximately 392,000 non-vested share units and 205,000 non-vestedshares to certain employees and directors during the year ended December 31,2006 under the Omnibus Incentive Plan. Approximately 34,000 of the share unitsand 205,000 of the shares vest in three equal installments on each of thefirst, second and third anniversaries of the grant date. Approximately 8,000 ofthe share units vest one year from the grant date. Approximately 350,000 shareunits vest 25% six months from the grant date, and 25% on each of the first,second and third anniversaries of the grant date. The granted non-vested shareunits and non-vested shares provide for accelerated vesting if there is achange of control (as defined in the Omnibus Incentive Plan) or, in certaincircumstances, as a result of a termination of employment. Approximately105,000 share units vested during the year ended December 31, 2006. Of thetotal share units that vested during the year ended December 31, 2006,approximately 17,000 of the share units became fully vested as a result of thetermination of certain employees.

The grant date fairvalue of the non-vested shares and non-vested share units is equal to theCompany’s closing stock price on the grant date. A summary of the status of theCompany’s non-vested shares and non-vested share units for service conditionawards as of December 31, 2006, and changes during the year ending December 31,2006, is presented below:

 

| **Non-Vested Shares and Non-Vested Share Units** | ** ** | ** ** | ** ** | **Number  of Shares** | ** ** | **Weighted  Average   Grant  Date Fair  Value** | ** ** |
|---------------------------------------------------------------------------|------------|------------|------------|----------------------------|------------|-----------------------------------------------------------|------------|
| Outstanding at  beginning of the year                                     |       | —     |       |                       | —     |                                                      |       |
| Changes during the year  to date:                                         |       |       |       |                       |       |                                                      |       |
| Granted                                                                   |       | 597,596    |       |                       | $          | 24.89                                                     |       |   |
| Vested                                                                    |       | (104,991   | )          |                       | $          | 24.84                                                     |       |   |
| Forfeited                                                                 |       | (32,586    | )          |                       | $          | 24.96                                                     |       |   |
| Expired                                                                   |       | —     |       |                       | —     |                                                      |       |
| Outstanding at the end  of the year                                       |       | 460,019    |       |                       | $          | 24.90                                                     |       |   |

 

F-49

----

*Performance Condition Awards*

The Company issued 283,554non-vested share units during the year ended December 31, 2006, under theOmnibus Incentive Plan. Approximately 140,000 were awarded on October 31,2006, to certain key employees and approximately 143,000 on November 13,2006, to five members of executive management. The non-vested share units cliffvest in approximately 18 months on June 30, 2008, provided that theCompany achieves the performance target amounts by December 31, 2007. Thegranted non-vested share units provide for accelerated vesting if there is achange of control (as defined in the Omnibus Incentive Plan) or, in certaincircumstances, as a result of a termination of employment. The grant date fairvalue of the non-vested shares and non-vested share units for performancecondition awards is equal to the Company’s closing stock price on the grantdate. A summary of the status of the Company’s non-vested shares and non-vestedshare units for performance condition awards as of December 31, 2006, andchanges during the year ending December 31, 2006, is presented below:

| **Non-Vested Shares and Non-Vested Share Units** | ** ** | ** ** | ** ** | **Number  of Shares** | ** ** | **Weighted  Average   Grant  Date Fair  Value** | ** ** |
|---------------------------------------------------------------------------|------------|------------|------------|----------------------------|------------|-----------------------------------------------------------|------------|
| Outstanding at  beginning of the year                                     |       | —     |       |                       | —     |                                                      |       |
| Changes during the year  to date:                                         |       |       |       |                       |       |                                                      |       |
| Granted                                                                   |       | 283,554    |       |                       | $          | 29.23                                                     |       |   |
| Vested                                                                    |       | —     |       |                       | —     |                                                      |       |
| Forfeited                                                                 |       | —     |       |                       | —     |                                                      |       |
| Expired                                                                   |       | —     |       |                       | —     |                                                      |       |
| Outstanding at the end  of the year                                       |       | 283,554    |       |                       | $          | 29.23                                                     |       |   |

 

**15.**          Asset Retirement Obligations

Effective January 1,2003, the Company adopted SFAS No. 143, which requires an entity torecognize the fair value of a liability for an asset retirement obligation inthe period in which it is incurred. Additionally, effective December 31,2005, the Company adopted FIN 47, which expands the scope of assetretirement obligations to be recognized to include asset retirement obligationsthat may be uncertain as to the nature or timing of settlement. Upon initialrecognition of a liability for an asset retirement obligation or a conditionalasset retirement obligation, an entity shall capitalize an asset retirementcost by increasing the carrying amount of the related long-lived asset by thesame amount as the liability. Over time, the liability is accreted to itspresent value each period, and the capitalized cost is depreciated over theuseful life of the related asset. Retirement obligations associated withlong-lived assets included within the scope of SFAS No. 143 andFIN 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.

The Company identifiedcertain asset retirement obligations within its power generation operations.These asset retirement obligations are primarily related to asbestos abatementin facilities on owned or leased property and other environmental obligationsrelated to fuel storage facilities, wastewater treatment facilities, closing ofash disposal sites and closing of owned pipelines.

Asbestos abatement is themost significant type of asset retirement obligation identified for recognitionin the Company’s adoption of FIN 47. The EPA has regulations in placegoverning the removal of asbestos. Due to the nature of asbestos, it can bedifficult to ascertain the extent of contamination in older acquired facilitiesunless substantial renovation or demolition takes place. Therefore, the Companyincorporated certain assumptions based on the relative age and size of itsfacilities to estimate the current cost for asbestos abatement. However, theactual abatement cost could differ from the estimates used to measure the assetretirement obligation. As a result, these amounts will be subject to revisionwhen actual abatement activities are undertaken.

F-50

----

Thefollowing table sets forth the balances of the asset retirement obligations asof January 1, 2005, and the additions and accretion of the assetretirement obligations for the years ended December 31, 2006 and 2005. Theasset retirement obligations are included in noncurrent liabilities in theconsolidated balance sheets (in millions):

| ** **                                                                             | ** ** | **For the Years Ended  December 31,** | ** ** |
|----------------------------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                                             | ** ** | **2006**                                                  | ** ** | **2005** | ** ** |
| Beginning balance  January 1                                                      |       |                                                      | $          | 34 |   |   |   | $ | 11 |   |   |
| Liabilities  recognized upon adoption of SFAS No. 143                        |       |                                                      | —     |   |   |   | — |   |   |
| Revisions to cash  flows for liabilities recognized upon adoption of SFAS No. 143 |       |                                                      | —     |   |   |   | (5 | ) |   |
| Liabilities  recognized upon adoption of FIN 47                                        |       |                                                      | —     |   |   |   | 27 |   |   |
| Liabilities  recorded in the period                                                    |       |                                                      | 5          |   |   |   | — |   |   |
| Liabilities  settled during the period                                                 |       |                                                      | (1         | ) |   |   | — |   |   |
| Accretion expense                                                                      |       |                                                      | 3          |   |   |   | 1 |   |   |
| Ending balance,  December 31                                                      |       |                                                      | $          | 41 |   |   |   | $ | 34 |   |   |

 

Thefollowing represents, on a pro forma basis, the amount of the liability forasset retirement obligations as if FIN 47 had been applied during allperiods affected (in millions):

| ** **                                                                                  | ** ** | **For the Years Ended  December 31,** | ** ** |
|---------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                                                                  | ** ** | **2005**                                                  | ** ** | **2004** | ** ** |
| Beginning balance  January 1                                                           |       |                                                      | $          | 36 |   |   |   | $34 |   |   |
| Revisions to cash  flows for liabilities recognized upon adoption of SFAS No. 143 |       |                                                      | (5         | ) |   |   | — |   |   |
| Accretion expense                                                                           |       |                                                      | 3          |   |   |   | 2 |   |   |
| Ending balance,  December 31                                                           |       |                                                      | $          | 34 |   |   |   | $ | 36 |   |   |
|                                                                                             |            |                                                           |            |  |  |  |  |  |  |  |  |

 

**16.**          Commitmentsand Contingencies

Mirant has made firmcommitments to buy materials and services in connection with its ongoingoperations and has made financial guarantees relative to some of itsinvestments.

***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 cash collateral or letters of credit for access to the transmissiongrid, to participate in power pools, to fund debt service reserves and forother operating activities. Trade credit support includes cash collateral,letters of credit and financial guarantees. In the event of default by theCompany, the counterparty can draw on a letter of credit or apply cashcollateral held to satisfy the existing amounts outstanding under an open contract.The Company’s outstanding issued letters of credit totaled $260 million as of December 31,2006.

F-51

----

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

| ** **                                                       | ** ** | **At December 31,** | ** ** |
|------------------------------------------------------------------|------------|-------------------------------|------------|
| ** **                                                       | ** ** | **2006**                      | ** ** | **2005** | ** ** |
| Continuing operations:                                           |       |                          |       |   |   |
| Cash collateral  posted—energy trading and marketing        |       | $                             | 27         |   | $ | 619 |   |
| Cash collateral  posted—debt service and rent reserves |       | —                        |       | 56 |   |
| Cash collateral  posted—other operating activities          |       | 13                            |       | 11 |   |
| Letters of  credit—energy trading and marketing             |       | 100                           |       | 51 |   |
| Letters of  credit—debt service and rent reserves           |       | 84                            |       | — |   |
| Letters of  credit—other operating activities               |       | 15                            |       | 2 |   |
|                                                             |       | 239                           |       | 739 |   |
| Discontinued operations:                                         |       |                          |       |   |   |
| Assets held for  sale—cash collateral posted           |       | 187                           |       | 301 |   |
| Assets held for  sale—letters of credit                     |       | 61                            |       | 56 |   |
| Total                                                            |       | $                             | 487        |   | $ | 1,096 |   |

 

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

***Commitments***

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

| **Fiscal Year Ending:**         | ** ** | ** ** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|-------------------------------------------|------------|------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| Mirant  Mid-Atlantic operating leases     |       | $          | 112        |     | $          | 121      |       | $        | 142        |     | $          | 140      |       | $              | 134        |      |       | $ | 1,597 |   |   | $ | 2,246 |   |
| Other operating  leases                   |       | 9          |       | 9        |       | 9        |       | 9        |       | 8        |       |     | 28         |           |       | 72        |       |
| Power purchase  agreements (Note 17) |       | 53         |       | 52       |       | 52       |       | 54       |       | 58       |       |     | 510        |           |       | 779       |       |
| Fuel and  transportation commitments      |       | 263        |       | 89       |       | 66       |       | —   |       | —   |       |     | —     |           |       | 418       |       |
| Long-term  service agreements             |       | 3          |       | 1        |       | 2        |       | 2        |       | 2        |       |     | 23         |           |       | 33        |       |
| Other purchase  commitments               |       | 223        |       | —   |       | —   |       | —   |       | —   |       |     | —     |           |       | 223       |       |
| Total payments                            |       | $          | 663        |     | $          | 272      |       | $        | 271        |     | $          | 205      |       | $              | 202        |      |       | $ | 2,158 |   |   | $ | 3,771 |   |

 

***OperatingLeases***

Mirant Mid-Atlantic leases the Morgantown andDickerson baseload units and associated property through 2034 and 2029,respectively. Mirant Mid-Atlantic has an option to extend the leases. Anyextensions of the respective leases would be limited to 75% of the economic usefullife of the facility, as measured from the beginning of the original lease termthrough the end of the proposed remaining lease term. The Company is accountingfor these leases as operating leases and recognizes rent expense on astraight-line basis. Rent expenses totaled $96 million, $99 million and $103million for the years ended December 31, 2006, 2005 and 2004,respectively, which are included in operations and maintenance expense in theaccompanying consolidated statements of operations. As of December, 31, 2006and 2005, 

F-52

----

the Company has paidapproximately $314 million and $304 million, respectively, of lease payments inexcess of rent expense recognized.

As of December 31, 2006, the total notionalminimum lease payments for the remaining terms of the leases aggregatedapproximately $2.2 billion and the aggregate termination value for theleases was approximately $1.4 billion and generally decreases over time.Mirant Mid-Atlantic leases the Morgantown and the Dickerson baseload units fromthird party owner lessors. These owner lessors each own the undivided interestsin these baseload generating facilities. The subsidiaries of the institutionalinvestors who hold the membership interests in the owner lessors are calledowner participants. Equity funding by the owner participants plus transactionexpenses paid by the owner participants totaled $299 million. The issuanceand sale of pass through certificates raised the remaining $1.2 billionneeded 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 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 lease facilities andits rights under the related lease and other financing documents.

Significant disputes arose between the Mirant Debtorsand the owner lessors and the indenture trustee for the Mirant Mid-Atlanticleveraged leases regarding among other things, whether or not the leveragedlease transactions constituted a “lease” (or “leases”) within the meaning ofsection 365 of the Bankruptcy Code, or instead evidenced a financingarrangement. On November 30, 2005, the Company entered into a settlementagreement with the Morgantown and Dickerson facilities’ owner lessors and theindenture trustee as part of a resolution of disputed matters in the Chapter 11proceedings. Pursuant to this settlement agreement and the Plan, the Companymade several payments including a settlement payment of $6.5 million eachto the owner lessors and the indenture trustee, $2.9 million asrestoration payments under the leases, and a reimbursement of legal and consultingfees of approximately $22 million. With the exception of $6.5 millionpaid to the indenture trustee in January 2006, the remaining amounts werepaid in December 2005. The total costs of $38 million have beenrecorded in reorganization items, net in the consolidated statements ofoperations.

Mirant has commitmentsunder other operating leases with various terms and expiration dates. Minimumlease payments under non-cancelable operating leases approximate$9 million in 2007, 2008, 2009 and 2010, $8 million in 2011 and$28 million thereafter.

***Fuel andTransportation Commitments***

In April 2002, Mirant entered into a long-termfuel purchase agreement. The fuel supplier converts coal feedstock received atthe Company’s Morgantown facility into a synthetic fuel. Under the terms of theagreement, Mirant is required to purchase a minimum of 2.4 million tons offuel per annum through December 2007. Minimum purchase commitments becameeffective upon the commencement of the synthetic fuel plant operation at theMorgantown facility in July 2002. The purchase price of the fuel varieswith the delivered cost of the coal feedstock. Based on current coal prices, asof December 31, 2006, total estimated commitments under this agreementwere $312 million.

In addition to the coalcommitment described above, Mirant has approximately $82 million in coalpurchase commitments related to an arrangement whereby the synthetic fuelsupplier sells the coal to the Company. As of December 31, 2006, Miranthas approximately $24 million in other purchase commitments under fuelpurchase and transportation agreements, which are in effect through 2029.

F-53

----

***Long-TermService Agreements***

As part of the Chapter 11 process, Mirant rejected itsLTSAs and entered into new agreements on June 16, 2004, related to certainof its combustion turbine generation facilities. The new agreements providemore favorable terms, including reduced pricing and increased flexibility tomodify terms based upon market conditions. Under the terms of the previousLTSAs, Mirant had prepaid future maintenance services at certain generatingfacilities. The Company recognized a $33 million charge in reorganizationitems, net in the consolidated statements of operations for the year ended December 31,2004, as a result of forfeited prepayments and impairments of certain purchasedintangible assets related to the previous LTSAs.

Also as part of the Chapter 11 process, on September 30,2004, Mirant rejected its LTSA associated with the Wrightsville generationfacility. The Company recognized a $3 million charge in reorganizationitems, net for the year ended December 31, 2004, for forfeited prepaymentsand the expected cost of settling the vendor’s claim as a result of thecontract rejection.

As of December 31,2006, the total estimated commitments under the new LTSA agreements associatedwith turbines installed or in storage were approximately $460 million. Ofthis total, $33 million relates to the Company’s continuing operations and $427million relates to the Company’s six natural gas-fired plants that are includedin liabilities held for sale. These commitments are payable over the terms ofthe respective agreements, which range from ten to twenty years. Theseagreements have terms that allow for cancellation of the contracts by the Companyupon the occurrence of several major events during the term of the contracts.Estimates for future commitments for the LTSAs are based on the stated paymentterms in the contracts at the time of execution. These payments are subject toan annual inflationary adjustment.

***OtherPurchase Commitments***

Other purchase commitmentsrepresent the open purchase orders less invoices received related to openpurchase orders for general procurement products and services purchased in theordinary course of business. These include construction, maintenance and laboractivities at the Company’s generation facilities.

**17.**          PowerPurchase Agreements and Obligations under Energy Delivery and PurchaseCommitments

Under the APSA for the Pepco generating assets, Mirantassumed and recorded net obligations of approximately $2.4 billionrepresenting the estimated fair value (at the date of acquisition) ofout-of-market energy delivery agreements and 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 themarketplace including brokers and trading platforms/exchanges such as the NewYork Mercantile Exchange and estimated load information.

The PPAs are for a total capacity of 735 MW andexpire over periods through 2021. Upon the adoption of SFAS No. 133 on January 1,2001, each PPA contract was evaluated to determine whether it met thedefinition of a derivative contract. PPAs determined to be derivativeinstruments are recorded on the balance sheet at fair value, with changes infair value recorded currently in generation revenue. The Company recognized$46 million, $104 million and $161 million of unrealized gainsduring 2006, 2005 and 2004, respectively, in connection with the PPAs. At December 31,2006, the estimated commitments under the PPAs were $779 million based onthe total remaining MW commitment at contractual prices. As of December 31,2006, the fair value of the PPAs recorded in price risk management liabilitiesin the consolidated balance sheet totaled $425 million, of which$36 million is classified as current.

F-54

----

As discussed in Note 23, pending a finaldetermination of the Mirant Debtors’ ability to reject the APSA, theBack-to-Back Agreement, and certain other agreements with Pepco, and theresolution of the Recharacterization Complaint, the Plan provides that theMirant Debtors’ obligations under the APSA and the Back-to-Back Agreement areinterim obligations of Mirant Power Purchase and are unconditionally guaranteedby Mirant. If the Mirant Debtors succeed in rejecting or recharacterizing anyof these agreements, 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.Pepco’s damages claim would then be satisfied pursuant to the terms of thePlan. If the proposed settlement between Mirant and Pepco is approved andbecomes effective, it will result in the dismissal of all pending litigationbetween Mirant and Pepco related to the APSA and the Back-to-Back Agreement.Under the settlement, the APSA will be assumed and performed by Mirant PowerPurchase. The Back-to-Back Agreement will be rejected and terminated as of May 31,2006, allowing Mirant to avoid the expected cost of the Back-to-Back Agreementthrough its stated expiration in 2021. Under certain conditions, however, thesettlement allows Mirant to assume and continue to perform, rather than reject,the Back-to-Back Agreement, thereby reducing the claim received by Pepco underthe settlement and the amount that would have to be paid by Mirant to Pepco tosatisfy that claim.

The TPAs stated thatMirant would sell a quantity of MWhs over the life of the contracts based onPepco’s load requirements. The TPA related to load in Maryland expired in June 2004,while the TPA related to load in the District of Columbia expired in January 2005.As actual MWhs were purchased or sold under these agreements, Mirant amortizeda ratable portion of the obligation as an increase in revenues. The Companyrecorded, as an adjustment of revenues, amortization of the TPA obligation ofapproximately $9 million and $344 million during the years ended December 31,2005 and 2004, respectively.

**18.**          Stockholders’Equity

In connection with the consummation of the Plan,Mirant filed a new certificate of incorporation which authorized 1.5 billionshares of New Mirant common stock and 100 million shares of preferredstock. On January 3, 2006, all shares of Mirant’s old common stock werecancelled, and 300 million shares of Mirant’s new common stock wereissued. Mirant reserved 23.5 million shares of common stock for unresolvedclaims.

Mirant also issued two series of warrants that willexpire on January 3, 2011. The Series A and Series B warrantsentitle the holders to purchase an aggregate of approximately 35 millionand 18 million shares of New Mirant common stock, respectively. Theexercise price of the Series A and Series B warrants is $21.87 and$20.54 per share, respectively. The exercise price and number of common sharesissuable are subject to adjustments based on the occurrence of certain events,including (1) dividends or distributions, (2) rights offerings or (3) otherdistributions. Mirant’s new common stock is currently traded on the NYSE andhas been assigned the ticker symbol MIR.

On January 3, 2006, the Omnibus Incentive Planfor certain employees and directors of Mirant became effective. Under theOmnibus Incentive Plan, 18,575,851 shares of Mirant common stock are availablefor issuance to participants. For further discussion of the Omnibus IncentivePlan see Note 14 to the consolidated financial statements.

F-55

----

**19.**          Earnings per Share

Pursuant to the Plan, on January 3, 2006, allshares of Mirant’s old common stock were cancelled and 300 million shares ofnew common stock were issued. Mirant also issued two series of warrants thatwill expire on January 3, 2011.

Mirant calculates basic EPS by dividing incomeavailable to shareholders by the weighted average number of common sharesoutstanding. Diluted EPS gives effect to dilutive potential common shares,including restricted stock, restricted stock units, stock options and warrants.The Company excluded 3.4 million of potential common shares representingantidilutive stock options from the earnings per share calculations for theyear ended December 31, 2006.

Thefollowing table shows the computation of basic and diluted EPS for the yearended December 31, 2006 (in millions except per share data):

| ** **                                                                    | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Net income (loss)  from continuing operations                                 |       | $          | 1,773      |       | $          | (1,406     | )          | $ | 1 |   |
| Net income (loss)  from discontinued operations                               |       | 91         |       | 99         |       | (477       | )          |
| Net income (loss)  as reported                                                |       | $          | 1,864      |       | $          | (1,307     | )          | $ | (476 | ) |
| **Basic  and diluted:**                                                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Weighted average  shares outstanding—basic                               |       | 285        |       |       |       |       |       |
| Shares due to  assumed exercise of warrants                                   |       | 11         |       |       |       |       |       |
| Shares due to  assumed vesting of restricted stock and restricted stock units |       | 1          |       |       |       |       |       |
| Weighted average  shares outstanding—diluted                             |       | 297        |       |       |       |       |       |
| **Basic  EPS**                                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| EPS from  continuing operations                                               |       | $          | 6.22       |       |       |       |       |   |
| EPS from  discontinued operations                                             |       | 0.32       |       |       |       |       |       |
| Basic EPS                                                                     |       | $          | 6.54       |       |       |       |       |   |
| **Diluted  EPS**                                                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| EPS from  continuing operations                                               |       | $          | 5.97       |       |       |       |       |   |
| EPS from  discontinued operations                                             |       | 0.31       |       |       |       |       |       |
| Diluted EPS                                                                   |       | $          | 6.28       |       |       |       |       |   |

 

During the third quarterof 2006, the Company repurchased 43 million shares of Mirant common stock foran aggregate purchase price of approximately $1.23 billion. On September 28,2006, the Company announced that its Board of Directors had authorized a $100million share repurchase program. As of December 31, 2006 and February 21,2007, the Company has repurchased 1.18 million shares under this program.Earnings per share information for periods prior to 2006 have not beenpresented because the information is not relevant in any material respect forusers of its financial statements.

**20.**          SegmentReporting

The Company previouslymanaged its business as three operating segments: United States, Philippinesand Caribbean. In 2006, the Company commenced separate auction processes todispose of its Caribbean and Philippine businesses and certain U.S. naturalgas-fired plants. The planned sales have resulted in the reclassification ofthe revenues and expenses of these businesses and assets to discontinuedoperations and the reclassification of the related assets and liabilities toheld for sale for all periods presented. In 2006, the Company re-evaluated thebusiness segments of its continuing operations. As a result, the Company nowhas four operating segments: Mid-Atlantic, Northeast, California and OtherOperations. Other Operations 

F-56

----

includesproprietary trading, fuel oil management, and gains and losses related to the Company’sBack-to-Back Agreement and TPAs with Pepco.

**BusinessSegments**

| ** **                                                                             | ** ** | **Mid-  Atlantic**     | ** ** | **Northeast** | ** ** | **California** | ** ** | **Other  Operations** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|----------------------------------------------------------------------------------------|------------|------------------------|------------|---------------|------------|----------------|------------|-----------------------|------------|------------------|------------|-----------|------------|
| ** **                                                                             | ** ** | **(in millions)** | ** ** |
| **2006:**                                                                              |       |                   |       |          |       |           |       |                  |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Operating Revenues                                                                     |       |                   | $          | 1,901         |       |           |       | $                     | 827        |             |       |      | $          | 171 |   |   |   | $ | 204 |   |   |   | $ | — |   |   | $ | 3,103 |   |
| Cost of fuel, electricity and other products                                           |       |                   | 583        |          |       |           | 469        |                  |       |             | 56         |      |       |   | 86 |   |   |   | (38 | ) |   | 1,156 |   |
| Gross margin                                                                           |       |                   | 1,318      |          |       |           | 358        |                  |       |             | 115        |      |       |   | 118 |   |   |   | 38 |   |   | 1,947 |   |
| Operating Expenses:                                                                    |       |                   |       |          |       |           |       |                  |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Operations and maintenance                                                             |       |                   | 333        |          |       |           | 133        |                  |       |             | 63         |      |       |   | 80 |   |   |   | — |   |   | 609 |   |
| Depreciation and amortization                                                          |       |                   | 74         |          |       |           | 25         |                  |       |             | 13         |      |       |   | 25 |   |   |   | — |   |   | 137 |   |
| Impairment losses                                                                      |       |                   | —     |          |       |           | 118        |                  |       |             | —     |      |       |   | 1 |   |   |   | — |   |   | 119 |   |
| Loss (gain) on sales of assets, net                                                    |       |                   | (7         | )             |       |           | (46        | )                     |       |             | —     |      |       |   | (40 | ) |   |   | 44 |   |   | (49 | ) |
| Total operating expenses                                                               |       |                   | 400        |          |       |           | 230        |                  |       |             | 76         |      |       |   | 66 |   |   |   | 44 |   |   | 816 |   |
| Operating Income                                                                       |       |                   | 918        |          |       |           | 128        |                  |       |             | 39         |      |       |   | 52 |   |   |   | (6 | ) |   | 1,131 |   |
| Total other  expense (income), net                                                     |       |                   | (4         | )             |       |           | 9          |                  |       |             | (34        | )         |       |   | 128 |   |   |   | — |   |   | 99 |   |
| Income (loss)  from continuing operations before reorganization items and income taxes |       |                   | 922        |          |       |           | 119        |                  |       |             | 73         |      |       |   | (76 | ) |   |   | (6 | ) |   | 1,032 |   |
| Reorganization  items, net                                                             |       |                   | —     |          |       |           | (163       | )                     |       |             | —     |      |       |   | — |   |   |   | — |   |   | (163 | ) |
| Provision  (benefit) for income taxes                                                  |       |                   | —     |          |       |           | 2          |                  |       |             | —     |      |       |   | (580 | ) |   |   | — |   |   | (578 | ) |
| Income from  continuing operations                                                     |       |                   | $          | 922           |       |           |       | $                     | 280        |             |       |      | $          | 73 |   |   |   | $ | 504 |   |   |   | $ | (6 | ) |   | $ | 1,773 |   |
|                                                                                   |       |                   |       |          |       |           |       |                  |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Total assets of  continuing operations                                                 |       |                   | $          | 3,404         |       |           |       | $                     | 1,196      |             |       |      | $          | 443 |   |   |   | $ | 3,321 |   |   |   | $ | (1,800 | ) |   | $ | 6,564 |   |
| Gross property additions                                                               |       |                   | $          | 112           |       |           |       | $                     | 12         |             |       |      | $          | 1 |   |   |   | $ | 8 |   |   |   | $ | — |   |   | $ | 133 |   |

 

F-57

----

 

| ** **                                                                             | ** ** | **Mid-  Atlantic**     | ** ** | **Northeast** | ** ** | **California** | ** ** | **Other   Operations** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|----------------------------------------------------------------------------------------|------------|------------------------|------------|---------------|------------|----------------|------------|-----------------------------|------------|------------------|------------|-----------|------------|
| ** **                                                                             | ** ** | **(in millions)** | ** ** |
| **2005:**                                                                              |       |                   |       |          |       |           |       |                        |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Operating Revenues                                                                     |       |                   | $          | 1,197         |       |           |       | $                           | 1,039      |             |       |      | $          | 166 |   |   |   | $ | 245 |   |   |   | $ | (1 | ) |   | $ | 2,646 |   |
| Cost of fuel, electricity and other products                                           |       |                   | 742        |          |       |           | 834        |                        |       |             | 53         |      |       |   | 187 |   |   |   | (16 | ) |   | 1,800 |   |
| Gross margin                                                                           |       |                   | 455        |          |       |           | 205        |                        |       |             | 113        |      |       |   | 58 |   |   |   | 15 |   |   | 846 |   |
| Operating  Expenses:                                                                   |       |                   |       |          |       |           |       |                        |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Operations and maintenance                                                             |       |                   | 341        |          |       |           | 225        |                        |       |             | 69         |      |       |   | 64 |   |   |   | (1 | ) |   | 698 |   |
| Depreciation and amortization                                                          |       |                   | 64         |          |       |           | 33         |                        |       |             | 5          |      |       |   | 33 |   |   |   | — |   |   | 135 |   |
| Impairment losses                                                                      |       |                   | —     |          |       |           | —     |                        |       |             | —     |      |       |   | 9 |   |   |   | — |   |   | 9 |   |
| Loss (gain) on sales of assets, net                                                    |       |                   | —     |          |       |           | (10        | )                           |       |             | —     |      |       |   | 19 |   |   |   | 8 |   |   | 17 |   |
| Total operating expenses                                                               |       |                   | 405        |          |       |           | 248        |                        |       |             | 74         |      |       |   | 125 |   |   |   | 7 |   |   | 859 |   |
| Operating Income  (loss)                                                               |       |                   | 50         |          |       |           | (43        | )                           |       |             | 39         |      |       |   | (67 |  ) |   |   | 8 |   |   | (13 | ) |
| Total other  expense, net                                                              |       |                   | 18         |          |       |           | 6          |                        |       |             | 1          |      |       |   | 1,414 |   |   |   | (26 | ) |   | 1,413 |   |
| Income (loss)  from continuing operations before reorganization items and income taxes |       |                   | 32         |          |       |           | (49        | )                           |       |             | 38         |      |       |   | (1,481 | ) |   |   | 34 |   |   | (1,426 | ) |
| Reorganization  items, net                                                             |       |                   | 22         |          |       |           | 7          |                        |       |             | (169       | )         |       |   | 96 |   |   |   | 26 |   |   | (18 | ) |
| Provision  (benefit) for income taxes                                                  |       |                   | —     |          |       |           | 6          |                        |       |             | 9          |      |       |   | (33 | ) |   |   | — |   |   | (18 | ) |
| Income from  continuing operations                                                     |       |                   | $          | 10            |       |           |       | $                           | (62        | )                |       |      | $          | 198 |   |   |   | $ | (1,544 | ) |   |   | $ | 8 |   |   | $ | (1,390 | ) |
|                                                                                   |       |                   |       |          |       |           |       |                        |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Total assets of  continuing operations                                                 |       |                   | $          | 3,335         |       |           |       | $                           | 1,020      |             |       |      | $          | 379 |   |   |   | $ | 4,355 |   |   |   | $ | (1,761 | ) |   | $ | 7,328 |   |
| Gross property additions                                                               |       |                   | $          | 67            |       |           |       | $                           | 15         |             |       |      | $          | 14 |   |   |   | $ | 5 |   |   |   | $ | — |   |   | $ | 101 |   |

 

F-58

----

| ** **                                                                             | ** ** | **Mid-  Atlantic**     | ** ** | **Northeast** | ** ** | **California** | ** ** | **Other  Operations** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|----------------------------------------------------------------------------------------|------------|------------------------|------------|---------------|------------|----------------|------------|-----------------------|------------|------------------|------------|-----------|------------|
| ** **                                                                             | ** ** | **(in millions)** | ** ** |
| **2004:**                                                                              |       |                   |       |          |       |           |       |                  |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Operating Revenues                                                                     |       |                   | $          | 1,022         |       |           |       | $                     | 804        |             |       |      | $          | 376 |   |   |   | $ | 1,049 |   |   |   | $ | (3 | ) |   | $ | 3,248 |   |
| Cost of fuel, electricity and other products                                           |       |                   | 521        |          |       |           | 576        |                  |       |             | 230        |      |       |   | 839 |   |   |   | (7 | ) |   | 2,159 |   |
| Gross margin                                                                           |       |                   | 501        |          |       |           | 228        |                  |       |             | 146        |      |       |   | 210 |   |   |   | 4 |   |   | 1,089 |   |
| Operating Expenses:                                                                    |       |                   |       |          |       |           |       |                  |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Operations and maintenance                                                             |       |                   | 336        |          |       |           | 200        |                  |       |             | 80         |      |       |   | 105 |   |   |   | (3 | ) |   | 718 |   |
| Depreciation and amortization                                                          |       |                   | 62         |          |       |           | 31         |                  |       |             | 4          |      |       |   | 40 |   |   |   | — |   |   | 137 |   |
| Impairment losses                                                                      |       |                   | —     |          |       |           | —     |                  |       |             | —     |      |       |   | 9 |   |   |   | — |   |   | 9 |   |
| Loss (gain) on sales of assets, net                                                    |       |                   | —     |          |       |           | 43         |                  |       |             | —     |      |       |   | (12 | ) |   |   | 18 |   |   | 49 |   |
| Total operating expenses                                                               |       |                   | 398        |          |       |           | 274        |                  |       |             | 84         |      |       |   | 142 |   |   |   | 15 |   |   | 913 |   |
| Operating Income  (loss)                                                               |       |                   | 103        |          |       |           | (46        | )                     |       |             | 62         |      |       |   | 68 |   |   |   | (11 | ) |   | 176 |   |
| Total other  expense (income), net                                                     |       |                   | 3          |          |       |           | (3         | )                     |       |             | 1          |      |       |   | (44 | ) |   |   | (7 | ) |   | (50 | ) |
| Income (loss)  from continuing operations before reorganization items and income taxes |       |                   | 100        |          |       |           | (43        | )                     |       |             | 61         |      |       |   | 112 |   |   |   | (4 | ) |   | 226 |   |
| Reorganization  items, net                                                             |       |                   | (6         | )             |       |           | 20         |                  |       |             | 18         |      |       |   | 188 |   |   |   | 7 |   |   | 227 |   |
| Provision  (benefit) for income taxes                                                  |       |                   | —     |          |       |           | (5         | )                     |       |             | (15        | )         |       |   | 18 |   |   |   | — |   |   | (2 | ) |
| Income (loss)  from continuing operations                                              |       |                   | $          | 106           |       |           |       | $                     | (58        | )                |       |      | $          | 58 |   |   |   | $ | (94 | ) |   |   | $ | (11 | ) |   | $ | 1 |   |
|                                                                                   |       |                   |       |          |       |           |       |                  |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Total assets of  continuing operations                                                 |       |                   | $          | 3,155         |       |           |       | $                     | 1,469      |             |       |      | $          | 548 |   |   |   | $ | 3,017 |   |   |   | $ | (2,638 | ) |   | $ | 5,551 |   |
| Gross property additions                                                               |       |                   | $          | 40            |       |           |       | $                     | 34         |             |       |      | $          | 11 |   |   |   | $ | 4 |   |   |   | $ | — |   |   | $ | 89 |   |

 

| ** **                 | ** ** | **Geographic Areas**                                                                        | ** ** |
|----------------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| ** **                 | ** ** | **Property, Plant and Equipment and Other Intangible Assets** | ** ** |
| ** **                 | ** ** | **Mid-  Atlantic**                                                                               | ** ** | **Northeast** | ** ** | **California** | ** ** | **Other   Operations** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| ** **                 | ** ** | **(in millions)**                                                                           | ** ** |
| At  December 31, 2006 |       |                                                                                             | $          | 2,450 |   |   |   | $ | 571 |   |   |   | $ | 163 |   |   |   | $ | 41 |   |   |   | $ | (799 | ) |   | $ | 2,426 |   |
| At December 31,  2005 |       |                                                                                             | $          | 2,369 |   |   |   | $ | 707 |   |   |   | $ | 222 |   |   |   | $ | 54 |   |   |   | $ | (799 | ) |   | $ | 2,553 |   |

 

F-59

----

**21.   Quarterly Financial Data (Unaudited)**

Summarizedquarterly financial data for 2006, 2005 and 2004, is as follows(in millions):

| ** ** | ** ** | ** **    | ** ** | ** **             | ** ** | **Income (Loss)** | ** ** | ** **             | ** ** |
|------------|------------|---------------|------------|------------------------|------------|------------------------|------------|------------------------|------------|
| ** ** | ** ** | ** **    | ** ** | ** **             | ** ** | **Before**             | ** ** | ** **             | ** ** |
| ** ** | ** ** | ** **    | ** ** | ** **             | ** ** | **Cumulative**         | ** ** | ** **             | ** ** |
| ** ** | ** ** | ** **    | ** ** | ** **             | ** ** | **Effect of**     | ** ** | ** **             | ** ** |
| ** ** | ** ** | ** **    | ** ** | ** **             | ** ** | **Changes in**    | ** ** | **Consolidated**       | ** ** |
| ** ** | ** ** | **Operating** | ** ** | **Operating**          | ** ** | **Accounting**         | ** ** | **Net**                | ** ** |
| ** ** | ** ** | **Revenue**   | ** ** | **Income (Loss)** | ** ** | **Principles**         | ** ** | **Income (Loss)** | ** ** |
| **2006:**  |       |          |       |                   |       |                   |       |                   |       |   |   |   |   |   |   |   |   |
| March      |       |          | $          | 962                    |       |                   |       | $                      | 484        |   |   |   | $ | 467 |   |   |   | $ | 467 |   |   |
| June       |       |          | 621        |                   |       |                   | 148        |                   |       |   | 99 |   |   |   | 99 |   |   |
| September  |       |          | 970        |                   |       |                   | 281        |                   |       |   | (26 | ) |   |   | (26 | ) |   |
| December   |       |          | 550        |                   |       |                   | 218        |                   |       |   | 1,324 | (1) |   |   | 1,324 |   |   |
| **2005:**  |       |          |       |                   |       |                   |       |                   |       |   |   |   |   |   |   |   |   |
| March      |       |          | $          | 534                    |       |                   |       | $                      | (6         | ) |   |   | $ | 11 |   |   |   | $ | 11 |   |   |
| June       |       |          | 590        |                   |       |                   | (18        | )                      |       |   | (10 | ) |   |   | (10 | ) |   |
| September  |       |          | 411        |                   |       |                   | (308       | )                      |       |   | (1,515 | )(2) |   |   | (1,515 | ) |   |
| December   |       |          | 1,111      |                   |       |                   | 319        |                   |       |   | 223 |   |   |   | 207 |   |   |
| **2004:**  |       |          |       |                   |       |                   |       |                   |       |   |   |   |   |   |   |   |   |
| March      |       |          | $          | 874                    |       |                   |       | $                      | 55         |   |   |   | $ | 30 |   |   |   | $ | 30 |   |   |
| June       |       |          | 930        |                   |       |                   | 60         |                   |       |   | 32 |   |   |   | 32 |   |   |
| September  |       |          | 758        |                   |       |                   | 17         |                   |       |   | 32 |   |   |   | 32 |   |   |
| December   |       |          | 686        |                   |       |                   | 44         |                   |       |   | (570 | )(3) |   |   | (570 | ) |   |

----

(1)          Includes $580 millionrecognized for continuing operations related to the release of the valuationallowance pertaining to deferred tax assets previously recorded including theestimated value of the NOLs that will be used to offset the anticipated 2007taxable gain resulting from the sale and a gain of approximately $244 millionon the New York property tax settlement.

(2)          Includes interestexpense of approximately $1.2 billion on liabilities subject to compromise.

(3)          Includesan impairment charge of $582 million for goodwill related to Asia reportingunit.

**22.   Valuationand Qualifying Accounts**

| ** **                                         | ** ** | **As of December 31, 2006, 2005 and 2004** | ** ** |
|----------------------------------------------------|------------|-------------------------------------------------------------------------------|------------|
| ** **                                         | ** ** | ** **                                                                    | ** ** | **Additions** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Description**                                    | ** ** | ** **                                                                    | ** ** | **Balance at  Beginning  of Period** | ** ** | **Charged  to  Income** | ** ** | **Charged to  Other  Accounts** | ** ** | **Deductions** | ** ** | **Balance at  End of  Period** | ** ** |
| ** **                                         | ** ** | **(in millions)**                                                             | ** ** |
| Provision for uncollectible  accounts (current)    |       |                                                                          |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| 2006                                               |       |                                                                          | $          | 84 |   |   |   | $ | 15 |   |   |   | $ | (24 | ) |   |   | $ | — |   |   |   | $ | 75 |   |   |
| 2005                                               |       |                                                                          | 234        |   |   |   | 16 |   |   |   | (167 | ) |   |   | 1 |   |   |   | 84 |   |   |
| 2004                                               |       |                                                                          | 206        |   |   |   | 6 |   |   |   | 32 |   |   |   | (10 | ) |   |   | 234 |   |   |
| Provision for  uncollectible accounts (noncurrent) |       |                                                                          |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| 2006                                               |       |                                                                          | $          | 72 |   |   |   | $ | 14 |   |   |   | $ | 24 |   |   |   | $ | (86 | ) |   |   | $ | 24 |   |   |
| 2005                                               |       |                                                                          | 161        |   |   |   | — |   |   |   | 7 |   |   |   | (96 | ) |   |   | 72 |   |   |
| 2004                                               |       |                                                                          | 205        |   |   |   | — |   |   |   | (34 | ) |   |   | (10 | ) |   |   | 161 |   |   |
|                                                    |            |                                                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

F-60

----

**23.   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, management provides forestimated losses to the extent information becomes available indicating thatlosses are probable and that the amounts are reasonably estimable. Additionallosses could have a material adverse effect on the Company’s consolidatedfinancial position, results of operations or cash flows.

***Chapter 11Proceedings***

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

As of December 31,2006, approximately 21 million of the shares of Mirant common stock to bedistributed under the Plan have not yet been distributed and have been reservedfor distribution with respect to claims that are disputed by the Mirant Debtorsand have not been resolved. A settlement entered into on May 30, 2006,among Pepco, Mirant, MC 2005, LLC f/k/a Mirant Corporation (“Old Mirant”), andvarious subsidiaries of Mirant, if approved by final order in the Chapter 11proceedings, would result in the distribution of up to 18 million of thereserved shares to Pepco, as described below in *PepcoLitigation*. Under the terms of the Plan, to the extent other suchunresolved claims are resolved now that Mirant has emerged from bankruptcy, theclaimants will be paid from the reserved shares on the same basis as if theyhad been paid when the Plan became effective. That means that their allowedclaims will receive the same pro rata distributions of Mirant common stock,cash, or both common stock and cash as previously allowed claims in accordancewith the terms of the Plan. To the extent the aggregate amount of the payoutsdetermined to be due with respect to such disputed claims ultimately exceedsthe amount of the funded claim reserve, Mirant would have to issue additionalshares of common stock to address the shortfall, which would dilute existingMirant shareholders, and Mirant and Mirant Americas Generation would have topay additional cash amounts as necessary under the terms of the Plan to satisfysuch pre-petition claims. If Mirant is required to issue additional shares ofcommon stock to satisfy unresolved claims, certain parties who under the Planreceived common stock and warrants also are entitled to receive additionalshares of common stock to avoid dilution of their distributions under the Plan.

The Company’s subsidiariesrelated to its New York business operations, Mirant New York, Mirant Bowline,Mirant Lovett, Hudson Valley Gas Corporation and Mirant NY-Gen remain inbankruptcy. The Company’s Lovett and Bowline generation facilities in New Yorkwere subject to disputes with local tax authorities regarding property taxassessments that were not resolved until December 2006, as described belowin *New York Tax Proceedings*. Resolution ofthose tax disputes should allow Mirant New York, Mirant Bowline, and HudsonValley Gas to emerge from bankruptcy in 2007. On January 26, 2007, MirantNew York, Mirant Bowline, and Hudson Valley Gas (collectively, the “EmergingNew York Entities”) filed a Supplemental Joint Chapter 11 Plan ofReorganization of the Emerging New York Entities (the “Supplemental Plan”) withthe Bankruptcy Court. The Supplemental Plan has two main components. First, theSupplemental Plan incorporates a settlement with the various New York taxjurisdictions that resolved the tax disputes related to the Lovett and Bowlinefacilities. Second, the Supplemental Plan provides unsecured creditors of theEmerging New York Entities with the same treatment afforded holders of 

F-61

----

unsecuredclaims against Mirant Americas Generation and its subsidiaries under the Plan.Such unsecured creditors of the Emerging New York Entities will receive their *pro rata* share of the pool of assets created under the Planfor the benefit of the unsecured creditors of Mirant Americas Generation andits subsidiaries. On January 26, 2007, the Emerging New York Entities alsofiled a motion with the Bankruptcy Court to establish procedures to facilitatethe consideration and confirmation of the Supplemental Plan. That motionrequests, among other things, that the Bankruptcy Court find that theSupplemental Plan does not alter in any respect from the Plan the treatment ofthe holders of unsecured claims against the Emerging New York Entities, andthat all votes previously cast by such holders in respect of the Plan (whichvotes accepted the Plan for the Emerging New York Entities by the requisitenumber and amount required by the Bankruptcy Code) should be deemed votes castin respect of the Supplemental Plan. The hearing before the Bankruptcy Court toconsider the confirmation of the Supplemental Plan is scheduled for March 21,2007.

On October 19, 2006,Mirant Lovett notified the New York Public Service Commission, the NYISO,Orange and Rockland and certain other affected transmission and distributioncompanies in New York of its intent to discontinue operation of units 3 and 5of the Lovett facility in April 2007. The discontinuance of operations atunit 5 is in accordance with the requirements of a June 11, 2003, ConsentDecree (the “2003 Consent Decree”) among Mirant Lovett, the State of New Yorkand the NYSDEC that requires Mirant Lovett to install certain environmentalcontrols on unit 5 of the Lovett facility or shut down that unit by April 30,2007. The 2003 Consent Decree imposes similar requirements with respect to unit4 that have to be met by April 30, 2008. Operations at unit 3 are beingdiscontinued because it is uneconomic to continue to run unit 3 if operationsat unit 5 are discontinued. Mirant Lovett is in discussions with the NYSDEC andthe New York State Office of the Attorney General regarding environmentalcontrols. If Mirant Lovett is able to agree with the New York Attorney General’soffice and the NYSDEC on alternative control technologies that would allow unit5 to remain in operation past April 30, 2007, then Mirant Lovett mayrescind the notice of its intent to discontinue operations at units 3 and 5.Until a resolution is reached on environmental controls that would permiteconomically feasible operation, Mirant Lovett will likely remain in Chapter11. Mirant NY-Gen, which owns hydroelectric facilities at Swinging Bridge, Rioand Mongaup, and small combustion turbine facilities at Hillburn and Shoemaker,is insolvent. Its expenses are being funded under a debtor-in-possessionfacility provided by Mirant Americas with the approval of, and under thesupervision of, the Bankruptcy Court. Mirant NY-Gen is proceeding with theimplementation of a remediation plan for the sinkhole discovered in May 2005in the dam at the Swinging Bridge facility. The status of the remediationeffort is discussed below in *Other Contingencies*.

On January 31, 2007,Mirant New York entered into an agreement for the sale of Mirant NY-Gen, whichowns the Hillburn and Shoemaker gas turbine facilities and the Swinging Bridge,Rio and Mongaup hydroelectric generating facilities. An auction processsupervised by the Bankruptcy Court is required before bankruptcy court approvalmay occur. The estimated sales price of $3 million is subject to adjustmentsfor working capital and certain dam remediation efforts that are ongoing at theSwinging Bridge facility. The transaction is expected to close in the secondquarter of 2007.

Until the Company’ssubsidiaries related to its New York business operations emerge frombankruptcy, the Company will not have access to the cash from operationsgenerated from these subsidiaries. In 2006, Mirant’s New York operationsgenerated $17 million of cash from operating activities.

***Actions Pursued by MC Asset Recovery, LLC***

In2005, Mirant Corporation and various of its subsidiaries filed several actionsbefore the Bankruptcy Court seeking to recover damages for fraudulent transfersthat occurred prior to the filing of Mirant’s bankruptcy proceedings. Each ofthose actions alleges that the defendants engaged in transactions with Mirantor its subsidiaries at a time when they were insolvent or were renderedinsolvent as a result of the 

F-62

----

resulting transfers and that they did not receive fairvalue for those transfers. Several of these actions indicate that the namedplaintiff, typically Mirant Corporation, is joined by the debtor affiliates ofMirant Corporation to the extent of their respective interests in the claimsasserted. In addition to these avoidance actions, the official Committee ofUnsecured Creditors of Mirant Corporation filed an action against ArthurAndersen on behalf of the Mirant Debtors alleging malpractice. Under the Plan,the rights to most of these avoidance actions, and the suit filed againstArthur Andersen, have been transferred to MC Asset Recovery. MC Asset Recovery,while wholly-owned by Mirant, is managed by managers that are independent ofMirant and its other subsidiaries. Mirant is obligated to make capitalcontributions to MC Asset Recovery as necessary to pay up to $20 million ofprofessional fees and to pay certain other costs incurred by MC Asset Recovery,including expert witness fees and other costs of the avoidance actions and theAndersen suit. Under the Plan, any cash recoveries received by MC AssetRecovery from the avoidance actions or the Andersen suit, net of costs incurredin prosecuting the actions (including all capital contributions from Mirant),are to be paid to the unsecured creditors of Mirant Corporation in the Chapter11 proceedings and the holders of the equity interests in Mirant Corporationimmediately prior to the effective date of the Plan. Mirant may not reduce suchpayments for the taxes owed on any recoveries up to $175 million. If theaggregate recoveries exceed $175 million net of costs, then Mirant may reducethe payments to be made to such unsecured creditors and former holders ofequity interests under the Plan by the amount of any taxes it will owe on theamount in excess of $175 million.

***Pepco Litigation***

In 2000, Mirant purchasedpower generating facilities and other assets from Pepco, including certain PPAsbetween Pepco and third parties. Under the terms of the APSA, Mirant and Pepco entered into the Back-to-BackAgreement with respect to certain PPAs, including Pepco’s long-term PPA withPanda, under which (1) Pepco agreed to resell to Mirant all capacity,energy, ancillary services and other benefits to which it is entitled underthose agreements and (2) Mirant agreed to pay Pepco each month all amountsdue from Pepco to the sellers under those agreements for the immediatelypreceding month associated with such capacity, energy, ancillary services andother benefits. The Panda PPA runs until 2021, and the Back-to-BackAgreement does not expire until all obligations have been performed under thePanda PPA. Under the Back-to-Back Agreement, Mirant is obligated to purchasepower from Pepco at prices that typically are higher than the market prices forpower.

*Pepco Contract Litigation.**  *On August 28, 2003, the Mirant Debtors filed amotion in the bankruptcy proceedings to reject the Back-to-Back Agreement (the “FirstRejection Motion”). If the Mirant Debtors succeed in rejecting the Back-to-BackAgreement, Mirant would have no further obligations with respect to thatagreement and Pepco would receive a claim in the bankruptcy proceedings for itsresulting damages. On December 9, 2004, the United States District Courtfor the Northern District of Texas held that the Back-to-Back Agreement was apart of and not severable from, and therefore could not be rejected apart from,the APSA. The Mirant Debtors appealed that decision to the United States Courtof Appeals for the Fifth Circuit (the “Fifth Circuit”). On July 19, 2006,the Fifth Circuit affirmed the district court’s December 9, 2004,decision, concluding that the APSA, the Back-to-Back Agreement and otheragreements executed under the terms of the APSA constituted a single agreementand that the Back-to-Back Agreement could not be separately rejected.

On January 21, 2005,the Mirant Debtors filed a separate motion in the bankruptcy proceedings toreject the APSA, including the Back-to-Back Agreement but not including otheragreements entered into between Mirant and its subsidiaries and Pepco under theterms of the APSA (the “Second Rejection Motion”). On August 16, 2005, thedistrict court informally stayed the Second Rejection Motion pending rulings bythe Fifth Circuit on the Mirant Debtors’ appeals from the district court’s December 9,2004, decision denying the First Rejection Motion. On January 31, 2007,the district court terminated this proceeding based on the filing of theproposed settlement described below in *Proposed Pepco Settlement*.

F-63

----

On December 1, 2005,the Mirant Debtors filed a complaint with the Bankruptcy Court seeking torecharacterize the Back-to-Back Agreement as a debt obligation arising prior tothe filing of the Chapter 11 proceedings (the “RecharacterizationComplaint”). The complaint seeks the recovery of all payments made to Pepcounder the Back-to-Back Agreement since the filing of the Chapter 11proceedings. If the Mirant Debtors succeed on the Recharacterization Complaint,Pepco would receive a claim in the bankruptcy proceedings for the amount of anypayments recovered by the Mirant Debtors and for the amount owed under theBack-to-Back Agreement for its remaining term. The Recharacterization Complaintremains pending in the Bankruptcy Court.

Pending a finaldetermination of the Mirant Debtors’ ability to reject the APSA, theBack-to-Back Agreement, and certain other agreements with Pepco, and theresolution of the Recharacterization Complaint, the Plan provides that theMirant Debtors’ obligations under the APSA and the Back-to-Back Agreement areinterim obligations of Mirant Power Purchase and are unconditionally guaranteedby Mirant. If the Mirant Debtors succeed in rejecting or recharacterizing anyof these agreements, the obligations of Mirant Power Purchase and Mirant’s guaranteeobligations terminate with respect to that agreement, and Pepco would beentitled to a claim in the Chapter 11 proceedings for any resulting damages.Pepco’s damages claim would then be satisfied pursuant to the terms of thePlan. See *Chapter 11 Proceedings*above for furtherdiscussion of the treatment under the Plan of unresolved claims in the Chapter11 proceedings.

If the proposed settlementbetween Mirant and Pepco described below in *Proposed Pepco Settlement*is approved and becomes effective, it will result in the dismissal of allpending litigation between Mirant and Pepco related to the APSA and theBack-to-Back Agreement. Under the settlement, the APSA will be assumed andperformed by Mirant Power Purchase. The Back-to-Back Agreement will be rejectedand terminated as of May 31, 2006, allowing Mirant to avoid the expectedcost of the Back-to-Back Agreement through its stated expiration in 2021. Undercertain conditions described below in *Proposed Pepco Settlement*,however, the settlement allows Mirant to assume and continue to perform, ratherthan reject, the Back-to-Back Agreement, thereby reducing the claim received byPepco under the settlement and the amount that would have to be paid by Mirantto Pepco to satisfy that claim.

*Potential AdjustmentRelated to Panda Power Purchase Agreement.*   Atthe time of the acquisition of the Mirant Mid-Atlantic assets from Pepco in December 2000,Mirant also entered into an agreement with Pepco that, as subsequentlymodified, provided that the price paid by Mirant for those assets would beadjusted if by April 8, 2005, a binding court order had been enteredfinding that the Back-to-Back Agreement violated the Panda PPA as a prohibitedassignment, transfer or delegation of the Panda PPA or because it caused aprohibited delegation or transfer of rights, duties or obligations under thePanda PPA that was not severable from the rest of the Back-to-Back Agreement.Panda initiated legal proceedings in 2000 asserting that the Back-to-BackAgreement violated provisions in the Panda PPA prohibiting Pepco from assigningthe Panda PPA or delegating its duties under the Panda PPA to a third partywithout Panda’s prior written consent. On June 10, 2003, the MarylandCourt of Appeals, Maryland’s highest court, ruled that the assignment ofcertain rights and delegation of certain duties by Pepco to Mirant under theBack-to-Back Agreement did violate the non-assignment provision of the PandaPPA and was unenforceable. The court, however, left open the issues whether theprovisions found to violate the Panda PPA could be severed and the rest of theBack-to-Back Agreement enforced and whether Panda’s refusal to consent to theassignment of the Panda PPA by Pepco to Mirant was unreasonable and violatedthe Panda PPA. The Company’s view is that the June 10, 2003, decision bythe Maryland Court of Appeals does not suffice to trigger a purchase priceadjustment under the agreement between Mirant and Pepco. If that court orderwere found to have triggered the purchase price adjustment, the agreementbetween Mirant and Pepco provides that the amount of the adjustment would benegotiated in good faith by the parties or determined by binding arbitration soas to compensate Pepco for the termination of the benefit of the Back-to-BackAgreement while also holding Mirant economically indifferent from such court order.

F-64

----

If the proposed settlementbetween Mirant and Pepco described below in *Proposed Pepco Settlement*is approved and becomes effective, it would result in the termination of any potentialadjustment to the price paid by Mirant for its December 2000 acquisitionof the Pepco assets related to the Panda PPA with no amount being owed.

*Pepco Avoidance Action.**  *On July 13, 2005, Mirant and several of itssubsidiaries filed a lawsuit against Pepco before the Bankruptcy Courtasserting that Mirant did not receive fair value in return for the purchaseprice paid for the Pepco assets and that the acquisition occurred at a timewhen Mirant was either insolvent or was rendered insolvent as a result of thetransaction. The suit seeks damages for fraudulent transfer under 11 U.S.C. §§544 and 550 and applicable state law anddisallowance of claims filed by Pepco in the Chapter 11 proceedings. On November 3,2005, the district court granted a motion filed by Pepco asking that the suitbe heard by the district court rather than the Bankruptcy Court. If theproposed settlement between Mirant and Pepco described below in *Proposed Pepco Settlement* is approved and becomes effective,it would result in the release by Mirant and its subsidiaries of all claimsasserted against Pepco in the suit filed July 13, 2005.

*Proposed Pepco Settlement.*   OnMay 30, 2006, Mirant, Mirant Power Purchase, Old Mirant, varioussubsidiaries of Mirant, and a trust established pursuant to the Plan to whichownership of Old Mirant and Mirant Americas Energy Marketing was transferred(collectively the “Mirant Settling Parties”) entered into a SettlementAgreement and Release (the “Settlement Agreement”) with Pepco and variousaffiliates of Pepco (collectively the “Pepco Settling Parties”). Once itbecomes effective, the Settlement Agreement will fully resolve the contractrejection motions that remain pending in the bankruptcy proceedings, as well asother matters currently disputed between Pepco and Mirant and its subsidiaries.The Pepco Settling Parties and the Mirant Settling Parties will release eachother from all claims known as of May 30, 2006, including the fraudulenttransfer claims brought by Old Mirant and several of its subsidiaries againstPepco in July 2005 that are described above in *PepcoAvoidance Action*. The Settlement Agreement will become effective onceit has been approved by the Bankruptcy Court and that approval order has becomea final order no longer subject to appeal. On August 9, 2006, theBankruptcy Court entered an order approving the Settlement Agreement, butcertain holders of unsecured claims against Old Mirant in the bankruptcyproceedings appealed that order. On December 26, 2006, the district courtaffirmed the bankruptcy court order approving the settlement, but the claimsholders have appealed that ruling to the Fifth Circuit, and the approval orderhas not yet become a final order.

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

TheSettlement Agreement grants Pepco a claim against Old Mirant in Old Mirant’sbankruptcy proceedings that will result in Pepco receiving common stock ofMirant and cash having a value, after liquidation of the stock by Pepco, equalto $520 million, subject to certain adjustments. Upon the Settlement Agreementbecoming effective, Mirant will distribute up to 18 million shares of Mirantcommon stock to Pepco to satisfy its claim and Pepco will liquidate those shares.The shares to be distributed to Pepco will be determined by Mirant after theSettlement Agreement becomes effective so as to produce upon liquidation totalnet proceeds as near to $520 million as possible, subject to the overall cap onthe shares to be distributed of 18 million shares. If the net proceeds receivedby Pepco from the liquidation of the shares are less than $520 million, Mirantwill pay Pepco cash equal to the difference. If Mirant exercises the option tohave the Back-to-Back Agreement assumed, then the $520 million is reduced to$70 million, Mirant Power Purchase would continue to perform the Back-to-BackAgreement 

F-65

----

through its expiration in 2021, and Mirant wouldguarantee its performance. The Settlement Agreement allocates the $70 millionto various claims asserted by Pepco that do not arise from the rejection of theBack-to-Back Agreement, including claims asserted under the Local Area SupportAgreement between Pepco and Mirant Potomac River that are discussed below inPepco Assertion of Breach of Local Area Support Agreement.

Whilethe appeal filed from the Bankruptcy Court’s August 9, 2006, orderapproving the Settlement Agreement is pending, the parties will continue toperform their obligations under the Back-to-Back Agreement until the appeal isresolved and the approval order has become a final order. Unless theBack-to-Back Agreement is assumed, Pepco will refund to Mirant Power Purchaseall payments received under the Back-to-Back Agreement for energy, capacity orother services delivered after May 31, 2006, through the date theSettlement Agreement becomes effective. The appeal of the approval order alsoresulted in Mirant paying Pepco $70 million. The $70 million will be repaid toMirant when a final order is entered either affirming the approval order, whichwould cause the Settlement Agreement to become effective, or determining thatthe Settlement Agreement cannot be approved.

Upon the final distribution of the shares to Pepco,Mirant expects to recognize a gain as a result of the rejection of theBack-to-Back Agreement. The amount of the gain will reflect the recorded pricerisk management liabilities for the Back-to-Back Agreement in the consolidatedbalance sheet at that date reduced by the amount of cash required to be paid byMirant in order for Pepco to receive the $520 million required under theSettlement Agreement. The closing price of Mirant’s stock as of December 31,2006, was $31.57 and the net proceeds at that price would have been sufficientto provide the $520 million to Pepco. As of December 31, 2006, the fairvalue of the Back-to-Back Agreement recorded in price risk managementliabilities in Mirant’s consolidated balance sheet totaled $425 million, ofwhich $36 million is classified as current. Thus, the amount of the estimatedcontingent gain is approximately $445 million at December 31, 2006,including estimated refunds of $20 million for payments to Pepco under theBack-to-Back Agreement for periods since May 31, 2006. Until the finaldistribution of the shares to Pepco, the amount of the estimated gain isaffected by changes in the fair value of the Back-to-Back Agreement, the numberof common shares distributed to Pepco and the proceeds received by Pepco fromits liquidation of the common shares.

***Californiaand Western Power Markets***

*FERC Refund Proceedings.*   OnJuly 25, 2001, the FERC issued an order requiring proceedings (the “FERCRefund Proceedings”) to determine the amount of any refunds and amounts owedfor sales made by market participants, including Mirant Americas EnergyMarketing, to the CAISO or the Cal PX from October 2, 2000, through June 20,2001 (the “Refund Period”). Various parties have appealed these FERC orders tothe United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”)seeking review of a number of issues, including changing the Refund Period toinclude periods prior to October 2, 2000, and expanding the sales ofelectricity subject to potential refund to include bilateral sales made to theDWR and other parties. On August 2, 2006, the Ninth Circuit issued anopinion addressing some of the issues raised by these appeals. The NinthCircuit remanded to the FERC for further proceedings the FERC’s denial ofrelief for sales of electricity made in the CAISO and Cal PX markets prior to October 2,2000, at rates found to be unjust and directed the FERC to address the parties’request for a market-wide remedy for tariff violations that may have occurredprior to October 2, 2000. In addition, the Ninth Circuit found that theFERC had not adequately supported its decision to exclude from the FERC RefundProceedings (i) sales made in the CAISO and Cal PX that had a term ofgreater than 24 hours, and (ii) energy exchange transactions, and remandedthese issues to the FERC for further proceedings. The Ninth Circuit affirmedthe FERC’s decision to exclude bilateral sales to the DWR from the FERC RefundProceeding. If the FERC grants the parties’ requested relief with respect tothe issues remanded by the Ninth Circuit, any expansion of the Refund Period toinclude periods prior to October 2, 2000, or of the types of sales ofelectricity potentially subject to refund could increase the refund exposure ofMirant Americas Energy Marketing in this proceeding.

F-66

----

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 CPUC and the EOB filed to recover certain refunds from parties,including Mirant Americas Energy Marketing, for bilateral sales of electricityto the DWR at the California/Oregon border, claiming that such sales took placein the Pacific Northwest. In an order issued June 25, 2003, the FERC ruledthat no refunds were owed and terminated the proceeding. On November 10,2003, the FERC denied requests for rehearing filed by various parties. Variousparties appealed the FERC’s decision to the Ninth Circuit.

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 ofMirant Americas Generation. The Ninth Circuit remanded the proceeding to theFERC for it to determine what remedies, including potential refunds, areappropriate where entities, including Mirant Americas Energy Marketing,purportedly did not comply with certain filing requirements for transactionsconducted under market-based rate tariffs. On July 31, 2006, the NinthCircuit denied a petition for rehearing filed by Mirant Americas EnergyMarketing and other parties. Various parties to the proceeding have filed apetition for writ of certiorari with the United States Supreme Court requestingit to review the Ninth Circuit’s September 9, 2004, decision.

On January 14, 2005,**Mirantand certain of its subsidiaries entered into a Settlement and Release of ClaimsAgreement (the “California Settlement”) with PG&E, 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 courts and before the FERC.The Mirant entities that are parties to the California Settlement(collectively, the “Mirant Settling Parties”) include Mirant Corporation,Mirant Americas Energy Marketing, Mirant Americas Generation, and Mirant NorthAmerica (as the successor to Mirant California Investments, Inc.). TheCalifornia Settlement was approved by the FERC on April 13, 2005, andbecame effective April 15, 2005, upon its approval by the BankruptcyCourt. The California Settlement resulted in the release of most of MirantAmericas Energy Marketing’s potential liability (1) in the FERC RefundProceedings for sales made in the CAISO or the Cal PX markets, (2) in theproceeding also initiated by the FERC in July 2001 to determine whetherthere had been unjust and unreasonable charges for spot market bilateral salesin the Pacific Northwest from December 25, 2000, through June 20,2001, and (3) in any proceedings at the FERC resulting from the NinthCircuit’s reversal of the FERC’s dismissal of the complaint filed in 2002 bythe California Attorney General. Under the California Settlement, theCalifornia Parties and those other market participants who have opted into thesettlement have released the Mirant Settling Parties from any liability forrefunds related to sales of electricity and natural gas in the western marketsfrom January 1, 1998, through July 14, 2003. Also, the CaliforniaParties have assumed the obligation of Mirant Americas Energy Marketing to payany refunds determined by the FERC to be owed by Mirant Americas EnergyMarketing to other parties that do not opt into the settlement for transactionsin the CAISO and Cal PX markets during the Refund Period, with the liability ofthe California Parties for such refund obligation limited to the amount ofcertain receivables assigned by Mirant Americas Energy Marketing to the CaliforniaParties under the California Settlement. The settlement did not relieve MirantAmericas Energy Marketing of liability for any refunds that the FERC determinesit to owe (1) to participants in the Cal PX and CAISO markets that are notCalifornia Parties (or that did not elect to opt into the settlement) forperiods outside of the Refund Period and (2) to participants in bilateraltransactions with Mirant Americas Energy Marketing that are not CaliforniaParties (or that did not elect to opt into the settlement).

F-67

----

The Company’s view is that the bulk of any obligationsof Mirant Americas Energy Marketing to make refunds as a result of salescompleted prior to July 14, 2003, in the CAISO or Cal PX markets or inbilateral transactions either have been addressed by the California Settlementor have been resolved as part of Mirant Americas Energy Marketing’s bankruptcyproceedings. To the extent that Mirant Americas Energy Marketing’s potentialrefund liability arises from contracts that were transferred to Mirant EnergyTrading as part of the transfer of the trading and marketing business under thePlan, Mirant Energy Trading may have exposure to any refund liability relatedto transactions under those contracts.

*FERC Show Cause ProceedingRelating to Trading Practices.**  *OnJune 25, 2003, the FERC issued a show cause order (the “Trading PracticesOrder”) to more than 50 parties, including Mirant Americas Energy Marketing andsubsidiaries of Mirant Americas Generation, that a FERC staff report issued on March 26,2003, identified as having potentially engaged in one or more tradingstrategies of the type employed by Enron Corporation and its affiliates (“Enron”),as described in Enron memos released by the FERC in May 2002. The TradingPractices Order identified certain specific trading practices that the FERCindicated could constitute gaming or anomalous market behavior in violation ofthe CAISO and Cal PX tariffs. The Trading Practices Order requires the CAISO toidentify transactions between January 1, 2000, and June 20, 2001,that may involve the identified trading strategies, and then requires theapplicable sellers involved in those transactions to demonstrate why suchtransactions were not violations of the CAISO and Cal PX tariffs. On September 30,2003, the Mirant entities filed with the FERC for approval of a 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 with respectto the sale of ancillary services. Under that amendment, the FERC would have anallowed unsecured claim in Mirant Americas Energy Marketing’s bankruptcyproceeding for $3.67 million in settlement of the allegations with respectto the sale of ancillary services. The FERC approved the Trading SettlementAgreement, as amended, on June 27, 2005, and the Bankruptcy Court approvedit on August 24, 2005. Certain parties filed motions for rehearing, whichthe FERC denied on October 11, 2006. A party to the proceeding hasappealed the FERC’s June 27, 2005, order to the Ninth Circuit.

***Shareholder-BondholderLitigation***

*MirantSecurities Consolidated Action.*   Twenty lawsuitsfiled in 2002 against Mirant and four of its officers have beenconsolidated into a single action, In re Mirant Corporation SecuritiesLitigation, before the United States District Court for the Northern Districtof Georgia. In their original complaints, the plaintiffs allege, among otherthings, that the defendants violated federal securities laws by making materialmisrepresentations and omissions to the investing public regarding Mirant’sbusiness operations and future prospects during the period from January 19,2001, through May 6, 2002, due to potential liabilities arising out of itsactivities in California during 2000 and 2001. The plaintiffs seek unspecifieddamages, including compensatory damages, and the recovery of reasonableattorneys’ fees and costs.

In November 2002, the plaintiffs filed an amendedcomplaint that added as defendants The Southern Company (“Southern”), thedirectors of Mirant immediately prior to its initial public offering of stockand various firms that were underwriters for the initial public offering by theCompany. In addition to the claims set out in the original complaint, theamended complaint asserts claims under the Securities Act, alleging that theregistration statement and prospectus for the initial public offering in 2000of Mirant’s old common stock terminated under the Plan misrepresented and omittedmaterial facts. On July 14, 2003, the district court dismissed the claimsasserted by the plaintiffs based on the Company’s California business 

F-68

----

activities but allowed thecase to proceed on the plaintiffs’ other claims. On March 24, 2006, theplaintiffs filed a motion for reconsideration of that ruling, which motionremains pending. On December 11, 2003, the plaintiffs filed a proof ofclaim against Mirant in the Chapter 11 proceedings, but they subsequentlywithdrew their claim in October 2004. On August 29, 2005, thedistrict court, at the request of the plaintiffs, dismissed Mirant as adefendant in this action.

A master separationagreement between Mirant and Southern entered into in conjunction with Mirant’sspin-off from Southern in 2001 obligates Mirant to indemnify Southern for anylosses arising out of any acts or omissions by Mirant and its subsidiaries inthe conduct of the business of Mirant and its subsidiaries. Mirant has filed toreject the separation agreement in the Chapter 11 proceedings. Any damagesdetermined to be owed to Southern arising from the rejection of the separationagreement will be addressed as a claim in the Chapter 11 proceedings under theterms of the Plan. The underwriting agreements between Mirant and the variousfirms added as defendants that were underwriters for the initial publicoffering by the Company in 2000 also provide for Mirant to indemnify such firmsagainst any losses arising out of any acts or omissions by Mirant and itssubsidiaries. The underwriters filed a claim against Mirant in the Chapter 11proceedings that was subordinated to claims of Mirant’s creditors andextinguished under the Plan.

***U.S. GovernmentInquiries***

*Department of JusticeInquiries**.**  **In November 2002, Mirant received a subpoena from theDOJ, acting through the United States Attorney’s office for the NorthernDistrict of California, requesting information about its activities and thoseof its subsidiaries for the period since January 1, 1998. The subpoenarequested information related to the California energy markets and othertopics, including the reporting of inaccurate information to trade publicationsthat publish natural gas or electricity spot price data. The subpoena wasissued as part of a grand jury investigation. The DOJ’s investigation is basedupon the same circumstances that were the subject of an investigation by theCFTC that was settled in December 2004, as described in the Company’s AnnualReport on Form 10 K for the year ended December 31, 2004, in LegalProceedings-Other Governmental Proceedings-CFTC Inquiry. On June 19, 2006, twoformer employees pled guilty to charges of conspiracy to manipulate the priceof natural gas in interstate commerce during the period from July 1, 2000,until November 1, 2000, while they were west region traders for Mirant AmericasEnergy Marketing. Mirant is discussing the disposition of this matter with theDOJ. If Mirant is unable to reach a consensual resolution with the DOJ, it ispossible that the DOJ could seek indictments against one or more Mirantentities for alleged violations of the Commodity Exchange Act. A consensualresolution of this matter could involve a deferred prosecution agreement andpayment of a fine or penalty. The Company’s current assessment is that theamount of any such fine or penalty would not exceed amounts previously accrued.*

***EnvironmentalMatters***

*EPA Information Request.**  *In January 2001, the EPA issued a request forinformation to Mirant concerning the implications under the EPA’s NSRregulations promulgated under the Clean Air Act of past repair and maintenanceactivities at the Potomac River plant in Virginia and the Chalk Point,Dickerson and Morgantown plants in Maryland. The requested information concernsthe period of operations that predates the Company subsidiaries’ ownership andlease of those plants. Mirant responded fully to this request. Under the APSA,Pepco is responsible for fines and penalties arising from any violationassociated with operations prior to the Company subsidiaries’ acquisition orlease of the plants. If a violation is determined to have occurred at any ofthe plants, the Company subsidiary owning or leasing the plant may beresponsible for the cost of purchasing and installing emissions controlequipment, the cost of which may be material. The Company’s subsidiaries owningor leasing the Chalk Point, Dickerson and Morgantown plants in Maryland will beinstalling a variety of emissions control equipment on those plants to complywith the Maryland Healthy Air Act, but that equipment will not include all ofthe emissions 

F-69

----

control equipmentthat could be required if a violation of the EPA’s NSR regulations isdetermined to have occurred at one or more of those plants. If such a violationis determined to have occurred after the Company’s subsidiaries acquired orleased the plants or, if occurring prior to the acquisition or lease, isdetermined to constitute a continuing violation, the Company’s subsidiaryowning or leasing the plant at issue could also be subject to fines andpenalties by the state or federal government for the period after itsacquisition or lease of the plant, the cost of which may be material, althoughapplicable bankruptcy law may bar such liability for periods prior to January 3,2006, when the Plan became effective for the Company and its subsidiaries thatown or lease these plants.

*Mirant Potomac RiverNotice of Violation.**  *On September 10,2003, the Virginia DEQ issued an NOV to Mirant Potomac River alleging that itviolated its Virginia Stationary Source Permit to Operate by emitting NOx inexcess of the “cap” established by the permit for the 2003 summer ozone season.Mirant Potomac River responded to the NOV, asserting that the cap wasunenforceable, noting that when the cap was made part of the permit it couldcomply through the purchase of emissions allowances and raising other equitabledefenses. Virginia’s civil enforcement statute provides for injunctive reliefand penalties. On January 22, 2004, the EPA issued an NOV to MirantPotomac River alleging the same violation of its Virginia Stationary SourcePermit to Operate as set out in the NOV issued by the Virginia DEQ.

On September 27,2004, Mirant Potomac River, Mirant Mid-Atlantic, the Virginia DEQ, the MDE, theDOJ and the EPA entered into, and filed for approval with the United StatesDistrict Court for the Eastern District of Virginia, a proposed consent decree(the “Original Consent Decree”) that, if approved, would have resolved MirantPotomac River’s potential liability for matters addressed in the NOVspreviously issued by the Virginia DEQ and the EPA. The Original Consent Decreewould have required Mirant Potomac River and Mirant Mid-Atlantic to (1) installpollution control equipment at the Potomac River plant in Virginia and at theMorgantown plant in Maryland leased by Mirant Mid-Atlantic, (2) complywith declining system-wide ozone season NOx emissions caps from 2004 through2010, (3) comply with system-wide annual NOx emissions caps starting in2004, (4) meet seasonal system average emissions rate targets in 2008 and (5) paycivil penalties and perform supplemental environmental projects in and aroundthe Potomac River plant expected to achieve additional environmental benefits.Except for the installation of the controls planned for the Potomac River unitsand the installation of selective catalytic reduction (“SCR”) or equivalenttechnology at Mirant Mid-Atlantic’s Morgantown units 1 and 2 in 2007 and 2008,the Original Consent Decree would not have obligated the Company’s subsidiariesto install specifically designated technology, but rather to reduce emissionssufficiently to meet the various NOx caps. Moreover, as to the requiredinstallations of SCRs at Morgantown, Mirant Mid-Atlantic may choose not toinstall the technology by the applicable deadlines and leave the units offeither permanently or until such time as the SCRs are installed. The OriginalConsent Decree was subject to the approval of the district court and theBankruptcy Court. As described below, the Original Consent Decree was notapproved and the parties have filed an amended proposed consent decree thatsupersedes the Original Consent Decree.

On July 22,2005, the district court granted a motion filed by the City of Alexandriaseeking to intervene in the district court action, although the district courtimposed certain limitations on the City of Alexandria’s participation in theproceedings. On September 23, 2005, the City of Alexandria filed a motionseeking authority to file an amended complaint in the action seeking injunctiverelief and civil penalties under the Clean Air Act for alleged violations byMirant Potomac River of its Virginia Stationary Source Permit to Operate andthe State of Virginia’s State Implementation Plan. Based upon a computermodeling described below in *Mirant Potomac RiverDownwash Study*, the City of Alexandria asserted that emissions fromthe Potomac River plant cause or contribute to exceedances of NAAQS for SO2,NO2 and particulate matter. The City of Alexandria also contended based on itsmodeling analysis that the plant’s emissions of hydrogen chloride and hydrogenfluoride exceed Virginia state standards. Mirant Potomac River disputes theCity of Alexandria’s allegations that it has violated the Clean Air Act andVirginia law. 

F-70

----

On December 2, 2005, the district court denied theCity of Alexandria’s motion seeking to file an amended complaint.

Inearly May 2006, the parties to the Original Consent Decree and MirantChalk Point entered into and filed for approval with the United States DistrictCourt for the Eastern District of Virginia an amended consent decree (the “AmendedConsent Decree”) that, if approved, will resolve Mirant Potomac River’spotential liability for matters addressed in the NOVs previously issued by theVirginia DEQ and the EPA. The Amended Consent Decree includes the requirementsthat were to be imposed under the terms of the Original Consent Decree asdescribed above. It also defines the rights and remedies of the parties in theevent of a rejection in bankruptcy or other termination of any of the long-termleases under which Mirant Mid-Atlantic leases the coal units at the Dickersonand Morgantown plants. The Amended Consent Decree provides that ifMirant Mid-Atlantic rejects or otherwise loses one or more of its leaseholdinterests in the Morgantown and Dickerson plants and ceases to operate one orboth of the plants, Mirant Mid-Atlantic, Mirant Chalk Point and/or MirantPotomac will (i) provide the EPA, Virginia DEQ and the MDE with thewritten agreement of the new owner or operator of the affected plant or plantsto be bound by the obligations of the Amended Consent Decree and (ii) wherethe affected plant is the Morgantown plant, offer to any and all prospectiveowners and/or operators of the Morgantown plant to pay for completion ofengineering, construction and installation of the SCRs required by the AmendedConsent Decree. If the new owner or operator of the affected plant or plantsdoes not agree to be bound by the obligations of the Amended Consent Decree, itrequires Mirant Mid-Atlantic, Mirant Chalk Point and/or Mirant Potomac toinstall an alternative suite of environmental controls at the plants theycontinue to own. The district court and theBankruptcy Court must approve the Amended Consent Decree for it to becomeeffective. The City of Alexandria and certain individuals and organizationshave opposed entry of the Amended Consent Order. The Bankruptcy Court approvedthe Amended Consent Decree on June 1, 2006. The district court has not yetapproved the Amended Consent Decree.

On April 26, 2006,Mirant Mid-Atlantic and the MDE entered into an agreement to allow MirantMid-Atlantic to implement the consent decree with respect to the Morgantownplant, if the consent decree receives the necessary approvals. Under theagreement, Mirant Mid-Atlantic agreed to certain ammonia and particulate matteremissions limits and to submit testing results to the MDE.

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

The computer modelinganalysis predicted that emissions from the Potomac River plant have thepotential to contribute to localized, modeled instances of exceedances of theNAAQS for SO2, NO2 and PM10 under certain conditions. Based on those results,the Virginia DEQ issued a directive to Mirant Potomac River on August 19,2005, to undertake immediately such action as was necessary to ensureprotection of human health and the environment and eliminate NAAQS violations.On August 24, 2005, power production at all five units of the PotomacRiver generating facility was temporarily halted in response to the directivefrom the Virginia DEQ. On August 25,2005, the District of Columbia Public Service Commission filed an emergencypetition and complaint with the FERC and the DOE to prevent the shutdown of thePotomac River facility. The matter remains pending before the FERC and the DOE.On December 20, 2005, due to a determination by the DOE that an emergencysituation existed with respect to the reliability of the supply of electricityto central Washington, D.C., the DOE ordered Mirant Potomac River to generateelectricity at the Potomac River generating facility, as requested by PJM, 

F-71

----

during any period in which one or both of thetransmission lines serving the central Washington, D.C. area are out of servicedue to a planned or unplanned outage. In addition, the DOE ordered MirantPotomac River, at all other times, for electric reliability purposes, to keepas many units in operation as possible and to reduce the start-up time of unitsnot in operation without contributing to any NAAQS exceedances. The DOErequired Mirant Potomac River to submit a plan, on or before December 30,2005, that met these requirements. The order further provides that MirantPotomac River and its customers should agree to mutually satisfactory terms forany costs incurred by it under this order or just and reasonable terms shall beestablished by a supplemental order. Certain parties filed for rehearing of theDOE order, and on February 17, 2006, the DOE issued an order grantingrehearing solely for purposes of considering further the rehearing requests.Mirant Potomac River submitted an operating plan in accordance with the order.On January 4, 2006, the DOE issued an interim response to Mirant PotomacRiver’s operating plan authorizing operation of the units of the Potomac Rivergenerating facility on a reduced basis, but making it possible to bring theentire plant into service within approximately 28 hours when necessary forreliability purposes. The DOE’s order expires July 1, 2007, but MirantPotomac River expects it will be able to continue to operate these units afterthat expiration.

In aletter received December 30, 2005, the EPA invited Mirant Potomac Riverand the Virginia DEQ to work with the EPA to ensure that Mirant Potomac River’soperating plan submitted to the DOE adequately addressed NAAQS issues. The EPAalso asserted in its letter that Mirant Potomac River did not immediatelyundertake action as directed by the Virginia DEQ’s August 19, 2005, letterand failed to comply with the requirements of the Virginia State ImplementationPlan established by that letter. Mirant Potomac River received a second letterfrom the EPA on December 30, 2005, requiring Mirant to provide certainrequested information as part of an EPA investigation to determine the CleanAir Act compliance status of the Potomac River generating facility.

On June 1, 2006,Mirant Potomac River and the EPA executed an ACO by Consent to resolve the EPA’sallegations that Mirant Potomac River violated the Clean Air Act by notimmediately shutting down all units at the Potomac River facility upon receiptof the Virginia DEQ’s August 19, 2005, letter and to assure an acceptablelevel of reliability to the District of Columbia. The ACO (i) specifiescertain operating scenarios and SO2 emissions limits for the Potomac Riverfacility, which scenarios and limits take into account whether one or both ofthe 230kV transmission lines serving Washington, D.C. are out of service; (ii) requiresthe operation of trona injection units to reduce SO2 emissions; and (iii) requiresMirant Potomac River to undertake a model evaluation study to predict ambientair quality impacts from the facility’s operations. In accordance with thespecified operating scenarios, the ACO permits the facility to operate using adaily predictive modeling protocol. This protocol allows Mirant Potomac Riverto schedule the facility’s level of operations based on whether computermodeling predicts a NAAQS exceedance, based on weather and certain operatingparameters. On June 2, 2006, the DOE issued a letter modifying its January 6,2006, order to direct Mirant Potomac River to comply with the ACO in order toensure adequate electric reliability to the District of Columbia. MirantPotomac River is operating the Potomac River facility in accordance with theACO and has been able to operate all five units of the facility most of thetime under the ACO.

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

F-72

----

*Suit Regarding Chalk PointEmissions.*   By letter dated June 15, 2006,four environmental advocacy organizations—Environmental Integrity Project,Chesapeake Climate Action Network, Patuxent Riverkeeper and EnvironmentMaryland Research and Policy Center—notified Mirant and Mirant Mid-Atlanticthat they intended to file suit alleging that Mirant Chalk Point had violatedthe opacity limits set by the permits for Chalk Point unit 3 and unit 4 duringthousands of six minute time intervals between January 2002 andMarch 2006. The letter indicated that the organizations intend to filesuit to enjoin the violations alleged, to obtain civil penalties for pastnoncompliance to the extent that liability for these violations was notdischarged by the bankruptcy of Mirant Chalk Point, and to recover attorneys’fees. On August 3, 2006, Mirant, Mirant Mid-Atlantic, and Mirant ChalkPoint filed a complaint in the Bankruptcy Court seeking an injunction barringthe four organizations from filing suit as threatened in the June 15,2006, notice on the grounds that the notice and any claim for civil penaltiesor other monetary relief for alleged violations occurring beforeJanuary 3, 2006, violated the discharge of claims and causes of actiongranted Mirant Chalk Point under the Plan. On August 14, 2006, theBankruptcy Court entered an order agreed to by the parties enjoining the fourorganizations from seeking monetary damages for any alleged violationsoccurring on or before January 3, 2006. As part of that order, the organizationsagreed not to file a complaint initiating litigation concerning the allegedviolations until August 30, 2006.

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

On August 30, 2006,the four environmental organizations filed suit in the United States DistrictCourt for the District of Maryland against Mirant, Mirant Mid-Atlantic, andMirant Chalk Point asserting that emissions from Chalk Point units 3 and 4 hadviolated opacity limits set under the Clean Air Act and state law on numerousoccasions since January 4, 2006. The plaintiffs sought an injunction prohibitingfurther violations by Chalk Point units 3 and 4 of the Clean Air Act, civilpenalties of up to $32,500 for each violation of the Clean Air Act, additionalcivil penalties for mitigation projects, and attorneys’ fees. OnSeptember 22, 2006, the Mirant defendants filed a motion to dismiss,arguing that under the Clean Air Act the MDE’s prosecution of the same allegedviolations in the Maryland state court proceeding and their resolution throughthe Consent Decree barred the plaintiffs’ suit. On January 3, 2007, thedistrict court granted the motion and dismissed the complaint, and that orderhas become final.

*New York StateAdministrative Claim.*   On January 24, 2006,the State of New York and the NYSDEC filed a notice of administrative claims inthe Company’s Chapter 11 proceedings asserting a claim seeking to require theCompany to provide funding to its subsidiaries owning generating facilities inNew York to satisfy certain specified environmental compliance obligations. TheState of New York alleges that during the pendency of the Chapter 11proceedings the Company and its subsidiaries that have emerged from bankruptcymade decisions on behalf of the Company’s subsidiaries owning generatingfacilities in New York and did not appropriately maintain the corporateseparateness between themselves and those subsidiaries. The Company disputesthose allegations. The State of New York cites various existing outstandingmatters between the State and the Company’s subsidiaries owning generatingfacilities in New York related to compliance with environmental laws andregulations, most of which are not material. The most significant complianceobligation identified by the State of New York in its notice of administrativeclaim relates to the “2003 Consent Decree” entered into by Mirant New York andMirant Lovett with the 

F-73

----

State of New Yorkto resolve issues related to NSR requirements under the Clean Air Act relatedto the Lovett plant. Under the 2003 Consent Decree, Mirant Lovett is requiredto make an election to install certain environmental controls on units 5 and 4of the Lovett facility or shut down those units by April 30, 2007, andApril 30, 2008, respectively. The State of New York notes in its notice ofadministrative claim that the cost of implementing such environmental controlscould exceed $200 million. On October 19, 2006, Mirant Lovett notified theNew York Public Service Commission and the NYISO of its intent to discontinueoperation of unit 5 of the Lovett facility in April 2007 in accordancewith the requirements of the 2003 Consent Decree. If Mirant Lovett is able toagree with the State of New York and the NYSDEC on alternative control technologiesthat would allow unit 5 to remain in operation past April 30, 2007, thenMirant Lovett may rescind the notice of its intent to discontinue operations atunit 5. The State of New York and the NYSDEC have executed a stipulated orderwith the Company, its New York subsidiaries and the other Mirant Debtors tostay resolution of this administrative claim. That stipulated order wasapproved by the Bankruptcy Court on February 23, 2006.

*Riverkeeper Suit AgainstMirant Lovett.**  *OnMarch 11, 2005, Riverkeeper, Inc. filed suit against Mirant Lovett inthe United States District Court for the Southern District of New York underthe Clean Water Act. The suit alleges that Mirant Lovett failed to implement amarine life exclusion system at its Lovett generating plant and to performmonitoring for the exclusion of certain aquatic organisms from the plant’scooling water intake structures in violation of Mirant Lovett’s water dischargepermit issued by the State of New York. The plaintiff requests the court toenjoin Mirant Lovett from continuing to operate the Lovett generating plant ina manner that allegedly violates the Clean Water Act, to impose civil penaltiesof $32,500 per day of violation, and to award the plaintiff attorneys’ 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.

***City of AlexandriaZoning Action***

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

At its December 18,2004, meeting, the City Council also approved revocation of two special usepermits issued in 1989 (the “1989 SUPs”), one applicable to the administrativeoffice space at Mirant Potomac River’s plant and the other for the plant’stransportation management plan. Under the terms of the approved action, therevocation of the 1989 SUPs was to take effect 120 days after the CityCouncil’s action, provided, however, that if Mirant Potomac River within such120-day period filed an application for the necessary special use permitsto bring the plant into compliance with the zoning ordinance provisions then ineffect, the effective date of the revocation of the 1989 SUPs would be stayeduntil final decision by the City Council on such application. The approvedaction further provides that if such special use permit application is approvedby the City Council, revocation of the 1989 SUPs will be dismissed as moot, andif the City Council does not approve the application, the revocation of the1989 SUPs will become effective and the plant will be considered anonconforming use subject to abatement.

F-74

----

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 sought to overturn the actions taken by the CityCouncil on December 18, 2004, changing the zoning status of Mirant PotomacRiver’s generating plant and approving revocation of the 1989 SUPs, on thegrounds that those actions violated federal, state and city laws. The complaintasserted, among other things, that the actions taken by the City Councilconstituted unlawful spot zoning, were arbitrary and capricious, constituted anunlawful attempt by the City Council to regulate emissions from the plant, andviolated Mirant Potomac River’s due process rights. Mirant Potomac River andMirant Mid-Atlantic requested the court to enjoin the City of Alexandria andthe City Council from taking any enforcement action against Mirant PotomacRiver or from requiring it to obtain a special use permit for the continuedoperation of its generating plant. On January 18, 2006, the court issuedan oral ruling following a trial that the City of Alexandria acted unreasonablyand arbitrarily in changing the zoning status of Mirant Potomac River’sgenerating plant and in revoking the 1989 SUPs. On February 24, 2006, thecourt entered 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 filed a petitionwith the Virginia Supreme Court seeking to appeal this judgment, and onSeptember 11, 2006, the Virginia Supreme Court agreed to hear the appeal.

***Pepco Assertion ofBreach of Local Area Support Agreement***

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 claims in thebankruptcy proceedings asserting that Mirant Potomac River’s shutdown of thePotomac River plant causes Mirant Potomac River to be liable for the cost ofsuch transmission facilities, which cost it estimates to be in excess of $70million. Mirant Potomac River disputes Pepco’s interpretation of the agreement.The outcome of this matter cannot be determined at this time.

If it is approved by afinal order of the Bankruptcy Court, the Settlement Agreement entered into onMay 30, 2006, by the Mirant Settling Parties and the Pepco SettlingParties would resolve all claims asserted by Pepco against Mirant Potomac Riverarising out of the suspension of operations of the Potomac River plant inAugust 2005. On August 9, 2006, the Bankruptcy Court entered an orderapproving the Settlement Agreement, but certain holders of unsecured claims inthe bankruptcy proceedings have appealed that order, and the order has not yetbecome a final order. Under the Settlement Agreement, Pepco would release allclaims it has asserted against Mirant Potomac River related to the shutdown ofthe plant in return for the claim Pepco receives in the Mirant bankruptcyproceeding.

***New York TaxProceedings***

Mirant New York, MirantBowline, Mirant Lovett, and Hudson Valley Gas (collectively with Mirant NewYork, Mirant Bowline, and Mirant Lovett, the “New York Companies”) were thepetitioners in 

F-75

----

variousproceedings (“Tax Certiorari Proceedings”) initially brought in the New Yorkstate courts challenging the assessed values determined by local taxingauthorities for the Bowline and Lovett generating facilities and a natural gaspipeline (the “HVG Property”) owned by Hudson Valley Gas. Mirant Bowline hadchallenged the assessed value of the Bowline generating facility and theresulting local tax assessments for tax years 1995 through 2006. Mirant Bowlinesucceeded to rights held by Orange & Rockland for the tax years priorto its acquisition of the Bowline Plant in 1999 under its agreement with Orange &Rockland for the purchase of that plant. Mirant Lovett had challenged theassessed value of the Lovett facility for each of the years 2000 through 2006.Hudson Valley Gas had challenged the assessed value of the HVG Property foreach of the years 2004 through 2006.

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

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

On December 13, 2006,Mirant and the New York Companies entered into a settlement agreement (the “SettlementAgreement”) with the Town of Haverstraw (“Haverstraw”), the Town of Stony Point(“Stony Point”), the Haverstraw-Stony Point Central School District (the “SchoolDistrict”), the County of Rockland (the “County”), the Village of Haverstraw (“HaverstrawVillage”), and the Village of West Haverstraw (“West Haverstraw Village” andcollectively with Haverstraw, Stony Point, the School District, the County, andHaverstraw Village, the “Tax Jurisdictions”). The Settlement Agreement wasapproved by the Bankruptcy Court on December 14, 2006, and resolved allpending disputes regarding real property taxes between the New York Companiesand the Tax Jurisdictions. Under the agreement, the New York Companies acceptedthe determinations of assessed value for the Bowline Facility for 1995 through2003 and the Lovett Facility for 2000 through 2003 made by the New York statecourt in its rulings in the Tax Certiorari Proceedings issued in August 2006.The New York Companies and the Tax Jurisdictions agreed to adopt the New Yorkstate court’s assessed values for the Bowline Facility and the Lovett Facilityfor 2003 as the assessed values for each facility for 2004 through 2006. Theparties agreed that the assessed values for the HVG Property for 2004 through2006 should be the values determined previously by Haverstraw. The TaxJurisdictions agreed to cancel penalties on the unpaid taxes owed by the NewYork Companies and to collect interest on those taxes at a rate of 8% per yearfor Mirant Bowline and Mirant Lovett and 12% per year for Hudson Valley Gas.Overall, the New York Companies under the settlement received total refunds of$163 million from the Tax Jurisdictions and paid unpaid taxes to the TaxJurisdictions of $115 million, resulting in the New York Companies receiving anet cash payment in the amount of $48 million. The refunds and unpaid taxeswere paid in early February 2007, and the New York Companies and the TaxJurisdictions are in the process of dismissing all pending litigation relatedto the refunds and the unpaid taxes.

The $163 million of totalrefunds received by the New York Companies was recognized as a gain in thefinancial statements in the fourth quarter of 2006. In addition, the New YorkCompanies had 

F-76

----

previouslyaccrued a liability based upon the unpaid taxes as billed by the TaxJurisdictions. Due to the reductions of the unpaid taxes that occurred pursuantto the terms of the Settlement Agreement, the New York Companies alsorecognized in the fourth quarter of 2006 a reduction of operating expenses ofapproximately $23 million related to 2006 and a gain of approximately $71million related to prior periods.

***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***

*Swinging Bridge.*   OnMay 5, 2005, Mirant NY-Gen discovereda sinkhole at its Swinging Bridge dam, located in Sullivan County, New York. Inresponse, Mirant NY-Gen filled this sinkhole, inspected for damage the dam’sslopes and the enclosed pipe that delivers water from the reservoir to thegenerator, drew down the lake level, and cleaned the diversion tunnel. MirantNY-Gen’s analysis indicated that the most probable cause of the sinkhole waserosion of soil comprising the dam from water flow through a hole in the pipethat delivers water from the reservoir to the generator. The dam is currentlystabilized, and Mirant NY-Gen is performing additional remediation repairs.Mirant NY-Gen currently expects to incur additional costs to repair the dam andto recover insurance proceeds for a portion of these repair costs. Byletter dated June 14, 2006, the FERC authorized Mirant NY-Gen to proceedwith its remediation plan for the sinkhole. The FERC has also concurred withthe results of Mirant NY-Gen’s flood study for its New York Swinging Bridge,Rio and Mongaup generation facilities, which study concluded that no additionalremediation is required. The Bankruptcy Court authorized Mirant NY-Gen toproceed with implementation of the remediation plan on June 29, 2006. Thecurrent estimated cost to remediate the dam at Swinging Bridge is approximately$29 million, of which approximately $22 million had been incurred through December 31,2006. The Bankruptcy Court has approved adebtor-in-possession loan to Mirant NY-Gen from Mirant Americas under whichMirant Americas, subject to certain conditions, would lend up to $16.5 millionto Mirant NY-Gen to provide funding for the repairs on the Swinging Bridge dam.

*California Settlement.**  *The California Settlement described above in *California and Western Power Markets—FERC Refund Proceedings*includeda provision that either (1) the partially constructed Contra Costa 8project, which is a planned 530 MW combined cycle generating facility, andrelated equipment (collectively, the “CC8 Assets”) were to be transferred toPG&E or (2) PG&E would receive additional alternativeconsideration of $70 million (the “CC8 Alternative Consideration”). To fund theCC8 Alternative Consideration, PG&E received an allowed, unsecured claim inthe bankruptcy proceedings against Mirant Delta that resulted in a distributionto PG&E of cash and Mirant common stock with a value of approximately $70million. PG&E was required to liquidate the common stock received as partof that distribution and place the net resulting amount plus any cash receivedinto an escrow account.

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

F-77

----

**Report ofIndependent Registered Public Accounting Firm**

TheBoard of Directors and Shareholders

Mirant Corporation:

We have audited the accompanying consolidated balance sheets of MirantCorporation and subsidiaries (the “Company”)as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity(deficit), comprehensive income (loss) and cash flows for each of the years inthe three-year period ended December 31, 2006. These consolidated financial statements arethe responsibility of the Company’s management. Our responsibility is toexpress an opinion on these consolidatedfinancial statements 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 consolidated financial statements referred to above presentfairly, in all material respects, the financial position of Mirant Corporation and subsidiaries as of December 31,2006 and 2005, and the results of their operations and their cash flows foreach of the years in the three-year period ended December 31, 2006, inconformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financialstatements, the Company adopted Statement of Financial Accounting Standards No. 123(R),*Share-Based Payment*, andStatement of Financial Accounting Standards No. 158, *Employer’s Accounting for Defined Benefit and OtherPostretirement Plans: an amendment of FASB Statements No. 87, 88, 106,and 132R,*in2006 and Financial Accounting Standards Board Interpretation No. 47, *Accounting for Conditional Asset Retirement Obligations: AnInterpretation of FASB Statement No. 143*, in 2005.

We also have audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the effectiveness of Mirant Corporation’s internal controlover financial reporting as of December 31, 2006, based on criteria established in *Internal Control—Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission,and our report dated February 28, 2007, expressed an unqualified opinionon management’s assessment of, and the effective operation of, internal controlover financial reporting.

/s/ KPMG LLP

Atlanta,Georgia

February 28, 2007

F-78

----

**Report of IndependentRegistered Public Accounting Firm**

TheBoard of Directors and Shareholders

Mirant Corporation:

We have audited management’sassessment, included in the accompanying Management’s Report on InternalControl over Financial Reporting*,*thatMirant Corporation maintained effective internal control over financialreporting as of December 31, 2006, based on criteria established in *Internal Control—Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO). Mirant Corporation’s management is responsible for maintainingeffective internal control over financial reporting and for its assessment ofthe effectiveness of internal control over financial reporting. Ourresponsibility is to express an opinion on management’s assessment and anopinion on the effectiveness of the Company’s internal control over financialreporting based on our audit.

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audit toobtain reasonable assurance about whether effective internal control overfinancial reporting was maintained in all material respects. Our audit includedobtaining an understanding of internal control over financial reporting,evaluating management’s assessment, testing and evaluating the design andoperating effectiveness of internal control, and performing such other proceduresas we considered necessary in the circumstances. We believe that our auditprovides a reasonable basis for our opinion.

A company’s internalcontrol over financial reporting is a process designed to provide reasonableassurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with U.S. generallyaccepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with U.S. generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (3) provide reasonable assurance regarding preventionor timely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements. Also, projections of any evaluation of effectiveness tofuture periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.

In our opinion, management’s assessment that MirantCorporation maintained effective internal control over financial reporting asof December 31, 2006, is fairly stated, in all material respects, based oncriteria established in *Internal Control—IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission (COSO). Also, in our opinion, Mirant Corporationmaintained, in all material respects, effective internal control over financialreporting as of December 31, 2006, based on criteria established in *Internal Control—Integrated Framework* issued by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standardsof the Public Company Accounting Oversight Board (United States), theconsolidated balance sheets of Mirant Corporation and subsidiaries as of December 31,2006 and 2005, and the related consolidated statements of operations,stockholders’ equity (deficit), comprehensive income (loss) and cash flows foreach of the years in the three-year period ended December 31, 2006, andour report dated February 28, 2007, expressed an unqualified opinion onthose consolidated financial statements.

/s/ KPMG LLP

Atlanta,Georgia

February 28, 2007

F-79

----

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

None.

**Item 9A*.****                Controlsand Procedures*

**InherentLimitations in Control Systems**

A control system, nomatter 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 disclosurecontrols and procedures, or our internal control over financial reporting, willprevent all error and all fraud.

**Effectiveness ofDisclosure 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 our disclosurecontrols and procedures (as defined by Rules 13a-15(e) and 15d-15(e) underthe Exchange Act), as of December 31, 2006. Based upon this assessment,our management concluded that, as of December 31, 2006, these disclosurecontrols and procedures were effective.

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.

**Management’s Reporton Internal Control over Financial Reporting**

Our management isresponsible for establishing and maintaining adequate internal control overfinancial reporting (as defined by Rules 13a-15(f) under theExchange Act). The Company’s internal control framework and processes have beendesigned to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes inaccordance with U.S. generally accepted accounting principles. Internal controlover financial reporting includes those processes and procedures that:

·       pertainto the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the Company;

·       providereasonable assurance that transactions are recorded properly to allow for thepreparation of financial statements, in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the Company arebeing made only in accordance with authorizations of management and directorsof the Company;

94

----

·       providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the Company’s assets that could have amaterial effect on the consolidated financial statements; and

·       providereasonable assurance as to the detection of fraud.

Under the supervision and with the participation ofour management, including our Chief Executive Officer and our Chief FinancialOfficer, we carried out an assessment of the effectiveness of our internalcontrol over financial reporting as of December 31, 2006. In conductingour assessment, management utilized the criteria set forth by the Committee ofSponsoring Organizations of the Treadway Commission in *InternalControl—Integrated Framework*. Based on this assessment, managementconcluded that our internal control over financial reporting was effective asof December 31, 2006.

Our independent registeredpublic accounting firm, KPMG LLP, has issued reports on management’sassessment of internal control over financial reporting and our consolidatedfinancial statements. KPMG LLP’s reports can be found on pages F-78and F-79. Our audit committee appoints, retains, oversees, evaluates,compensates and terminates on its sole authority our independent auditors andapproves all audit engagements, including the scope, fees and terms of eachengagement. The audit committee’s oversight process is intended to ensure thatwe will continue to have high-quality, cost-efficient independent auditingservices.

**Changes in InternalControl over Financial Reporting**

During the quarter ended December 31,2006, there were no changes in Mirant’s internal control over financialreporting or in other factors that could materially affect or is reasonablylikely to affect such internal controls over financial reporting.

**Item 9B.**               *Other Information*

None.

95

----

**PART III**

**Item 10.***                 Directorsand Executive Officers of the Registrant*

The information requiredby this Item will be set forth in our definitive Proxy Statement for our 2007Annual Meeting of Stockholders, to be filed on or before April 9, 2007,and is incorporated herein by reference.

**Item 11.***                 ExecutiveCompensation*

The information requiredby this Item will be set forth in our definitive Proxy Statement for our 2007Annual Meeting of Stockholders, to be filed on or before April 9, 2007,and is incorporated herein by reference.

**Item 12.***                 SecurityOwnership of Certain Beneficial Owners and Management and Related StockholderMatters*

The information requiredby this Item will be set forth in our definitive Proxy Statement for our 2007Annual Meeting of Stockholders, to be filed on or before April 9, 2007,and is incorporated herein by reference.

**Item 13.***                 CertainRelationships and Related Transactions*

The information requiredby this Item will be set forth in our definitive Proxy Statement for our 2007Annual Meeting of Stockholders, to be filed on or before April 9, 2007,and is incorporated herein by reference.

**Item 14.***                 PrincipalAccountant Fees and Services*

The information required by this Item will be setforth in our definitive Proxy Statement for our 2007 Annual Meeting ofStockholders, to be filed on or before April 9, 2007, and is incorporatedherein by reference.

96

----

**PART IV**

**Item 15.**                 *Exhibits and Financial Statement Schedules*

(a)          1.      *Financial Statements*

Our consolidatedfinancial statements, including the notes thereto and independent auditors’report thereon, are set forth on pages 91 through 161 of the Annual Reporton Form 10-K, and are incorporated herein by reference.

2.                 *Financial Statement schedules*

None

3.                 *Exhibit Index*

| Exhibit No. | ** **  | **Exhibit Name** | ** ** |
|------------------|-------------|-----------------------|------------|
|             | 2.1*   |                  |       | Purchase  and Sale Agreement, dated as of January 15, 2007, by and between Mirant  Americas, Inc. and LS Power (Designated on Form 8-K dated  January 18, 2007 as Exhibit 2.1) |   |
|             | 2.2*   |                  |       | Stock  and Note Purchase Agreement, dated as of December 11, 2006, by and among  Mirant Asia-Pacific Ventures, Inc., Mirant Asia-Pacific  Holdings, Inc., Mirant Sweden International AB (publ), and Tokyo Crimson  Energy Holdings Corporation (Designated on Form 8-K filed  December 13, 2006 as Exhibit 2.1) |   |
|             | 3.1*   |                  |       | Amended  and Restated Certificate of Incorporation of Registrant (Designated on  Form 8-K filed January 3, 2006 as Exhibit 3.1) |   |
|             | 3.2*   |                  |       | Amended  and Restated Bylaws of Registrant (Designated on Form 8-K filed  January 3, 2006 as Exhibit 3.2) |   |
|             | 4.1*   |                  |       | Form of  Warrant Agreement between Registrant and Mellon Investor Services LLC, as  Warrant Agent (Designated on Form 8-K filed January 3, 2006  as Exhibit 4.1) |   |
|             | 10.1*  |                  |       | Tax  Settlement Agreement, dated as of December 13, 2006, by and between  Mirant Corporation, Mirant New York, Inc., Mirant Bowline, LLC, Mirant  Lovett, LLC, Hudson Valley Gas Corporation and the Town of Haverstraw, the  Town of Stony Point, the Haverstraw-Stony Point Central School District, the  County of Rockland, the Village of Haverstraw, and the Village of West  Haverstraw as Exhibit 10.1 (Designated on Form 8-K filed  December 15, 2006) |   |
|             | 10.2*  |                  |       | Settlement  Agreement and Release dated May 30, 2006 by and between Registrant and  PEPCO (Designated on Form 8-K filed May 31, 2006 as  Exhibit 10.1) |   |
|             | 10.3*  |                  |       | Employment  Agreement between Registrant and Robert M. Edgell (Designated on Form 8-K  filed March 4, 2006 as Exhibit 10.1) |   |
|             | 10.4*  |                  |       | Memorandum  of Understanding between Registrant and M. Michele Burns (Designated on  Form 8-K filed November 4, 2005 as Exhibit 10.3) |   |
|             | 10.5*  |                  |       | Employment  Agreement between Registrant and Thomas Legro (Designated on Form 8-K  filed December 1, 2005 as Exhibit 10.1) |   |
|             | 10.6*  |                  |       | Employment  Agreement between Registrant and William von Blasingame (Designated on  Form 8-K filed December 1, 2005 as Exhibit 10.2) |   |
|             | 10.7*  |                  |       | Employment  Agreement between Registrant and James V. Iaco (Designated on Form 8-K  filed November 4, 2005 as Exhibit 10.1) |   |
|             | 10.8*  |                  |       | Employment  Agreement between Registrant and S. Linn Williams (Designated on Form 8-K  filed November 4, 2005 as Exhibit 10.2) |   |
|             | 10.9*  |                  |       | Employment  Agreement between Registrant and Edward R. Muller (Designated on Form 8-K  filed October 3, 2005 as Exhibit 10.1) |   |
|             | 10.10*      |                  |       | Letter  Agreement between Registrant and S. Marce Fuller (Designated on Form 8-K  filed October 20, 2005 as Exhibit 10.1) |   |

97

----

 

|        | 10.11* |   |   | Form of  Stock Option Award Agreement (Designated on Form 8-K filed  November 16, 2006 as Exhibit 10.1)                                                                          |   |
|--------|--------|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
|   | 10.12* |   |   | Form of  Restricted Stock Unit Award Agreement (Designated on Form 8-K  filed November 16, 2006 as Exhibit 10.2)                                                                 |   |
|   | 10.13* |   |   | Description  of Mirant Corporation Special Bonus Plan (Designated on Form 8-K  filed October 11, 2006)                                                                                     |   |
|   | 10.14* |   |   | Mirant  Corporation 2006 Non-Employee Director Compensation Plan (Designated on  Form 8-K filed May 8, 2006 as Exhibit 10.1)                                                          |   |
|   | 10.15* |   |   | 2006  Short-term Incentive Plan Description (Designated on Form 10-K  filed March 14, 2006 as Exhibit 10.55)                                                                          |   |
|   | 10.16* |   |   | 2006  Named Executive Officer Base Compensation and Short-term Incentive Targets  (Designated on Form 10-K filed March 14, 2006 as  Exhibit 10.56)                                    |   |
|   | 10.17* |   |   | Form of  Stock Option Award Agreement (Designated on Form 8-K filed  January 18, 2006 as Exhibit 10.1)                                                                           |   |
|   | 10.18* |   |   | Form of  Restricted Stock Unit Award Agreement (Designated on Form 8-K  filed January 18, 2006 as Exhibit 10.2)                                                                  |   |
|   | 10.19* |   |   | 2005  Omnibus Incentive Compensation Plan (Designated on Form 8-K filed  January 3, 2006 as Exhibit 10.1)                                                                             |   |
|   | 10.20* |   |   | Form of  Amended and Restated Mirant Services Supplemental Executive Retirement Plan  (Designated on Form 10-K filed March 11, 2002 as  Exhibit 10.31)                           |   |
|   | 10.21* |   |   | Form of  First Amendment to the Amended and Restated Mirant Services Supplemental  Executive Retirement Plan (Designated on Form 10-K filed  March 11, 2002 as Exhibit 10.61)    |   |
|   | 10.22* |   |   | Form of  Second Amendment to the Amended and Restated Mirant Services Supplemental  Executive Retirement Plan (Designated on Form 10-K filed  March 11, 2002 as Exhibit 10.62)   |   |
|   | 10.23* |   |   | Form of  Third Amendment to the Amended and Restated Mirant Services Supplemental  Executive Retirement Plan (Designated on Form 10-Q filed  October 28, 2003 as Exhibit 10.86)  |   |
|   | 10.24* |   |   | Form of  Fourth Amendment to the Amended and Restated Mirant Services Supplemental  Executive Retirement Plan (Designated on Form 10-K filed  March 15, 2005 as Exhibit 10.42)   |   |
|   | 10.25* |   |   | Form of  Amended and Restated Mirant Corporation Deferred Compensation Plan for  Directors and Select Employees (Designated on Form 10-K filed  March 11, 2002 as Exhibit 10.55) |   |
|   | 10.26* |   |   | First  Amendment to the Mirant Corporation Deferred Compensation Plan for Directors  and Select Employees (Designated on Form 10-K filed March 11,  2002 as Exhibit 10.56)            |   |
|   | 10.27* |   |   | Second  Amendment to the Mirant Corporation Deferred Compensation Plan for Directors  and Select Employees (Designated on Form 10-Q filed  October 27, 2003 as Exhibit 10.87)         |   |
|   | 10.28* |   |   | Third  Amendment to the Mirant Corporation Deferred Compensation Plan for Directors  and Select Employees (Designated on Form 10-K filed March 15,  2005 as Exhibit 10.43)            |   |
|   | 10.29* |   |   | Fourth  Amendment to the Mirant Corporation Deferred Compensation Plan for Directors  and Select Employees (Designated on Form 10-K filed March 14,  2006 as Exhibit 10.22)           |   |
|   | 10.30* |   |   | 2006  Mirant Corporation Deferred Compensation Plan (Designated on Form 10-K  filed March 14, 2006 as Exhibit 10.23)                                                                  |   |
|   | 10.31* |   |   | Form of  Mirant Services Supplemental Benefit Plan (Designated on Form 10-K  filed March 11, 2002 as Exhibit 10.57)                                                              |   |
|   | 10.32* |   |   | First  Amendment to the Mirant Services Supplement Benefit Plan (Designated on  Form 10-K filed March 11, 2002 as Exhibit 10.58)                                                      |   |
|   | 10.33* |   |   | Second  Amendment to the Mirant Services Supplemental Benefit Plan (Designated on  Form 10-K filed April 30, 2003 as Exhibit 10.72)                                                   |   |
|   | 10.34* |   |   | Third  Amendment to the Mirant Services Supplemental Benefit Plan (Designated on  Form 10-K filed March 15, 2005 as Exhibit 10.40)                                                    |   |

98

----

 

|        | 10.35*                  |   |   | Fourth  Amendment to the Mirant Services Supplemental Benefit Plan (Designated on  Form 10-K filed March 14, 2006 as Exhibit 10.28)                                                                                                                                                                                                                                                                                                                                                        |   |
|--------|-------------------------|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
|   | 10.36*                  |   |   | Mirant  Corporation—Four Year Credit Agreement with Credit Suisse First Boston, Bank  of America, N.A., Commerzbank AG, New York and Grand Cayman Branches, The  Royal Bank of Scotland PC, The Bank of Tokyo-Mitsubishi Ltd., New York  Branch, Bayerische Landesbank Girozentrale, Deutsche Bank AG, New York  Branch, Wachovia Bank, N.A., and the initial lenders listed on the signature  pages thereof. (Designated on Form 8-K filed  February 12, 2003 as Exhibit 10.67) |   |
|   | 10.37*                  |   |   | Mirant  Corporation—Facility C Credit Agreement with Citibank, N.A., the issuing  banks and lenders named therein. (Designated on Form 8-K filed  February 12, 2003 as Exhibit 10.69)                                                                                                                                                                                                                                                                                                 |   |
|   | 10.38*                  |   |   | Mirant  North America, LLC—Credit Agreement with Deutsche Bank Securities Inc.,  Goldman Sachs Credit Partners L.P., and JPMorgan Chase Bank, N.A (Designated  on Form 10-K filed March 14, 2006 as Exhibit 10.33)                                                                                                                                                                                                                                                                    |   |
|   | 10.39*                  |   |   | Mirant  Americas Generation, LLC—Facility B Credit Agreement with Lehman  Brothers, Inc. and Lehman Commercial Paper, Inc. (Designated on  Form 8-K filed February 12, 2003 as Exhibit 10.70)                                                                                                                                                                                                                                                                          |   |
|   | 10.40*                  |   |   | Mirant  Americas Generation, LLC—Facility C Credit Agreement with Lehman  Brothers, Inc. and Lehman Commercial Paper, Inc. (Designated on  Form 8-K filed February 12, 2003 as Exhibit 10.71)                                                                                                                                                                                                                                                                          |   |
|   | 10.41*                  |   |   | Payment  Guaranty, dated as of December 11, 2006, by Mirant Corporation, to and  in favor of Tokyo Crimson Energy Holdings Corporation (Designated on  Form 8-K filed December 13, 2006 as Exhibit 10.1)                                                                                                                                                                                                                                                                              |   |
|   | 10.42*                  |   |   | Payment  Guaranty, dated as of December 11, 2006, made by The Tokyo Electric  Power Company, Incorporated in favor of Mirant Asia-Pacific  Ventures, Inc. and Mirant Asia-Pacific Holdings, Inc. (Designated  on Form 8-K filed December 13, 2006 as Exhibit 10.2)                                                                                                                                                                                                          |   |
|   | 10.43*                  |   |   | Payment  Guaranty, dated as of December 11, 2006, by Marubeni Corporation in  favor of Mirant Asia-Pacific Ventures Inc. and Mirant Asia-Pacific  Holdings, Inc. (Designated on Form 8-K filed  December 13, 2006 as Exhibit 10.3)                                                                                                                                                                                                                                               |   |
|   | 21.1     |   |   | Subsidiaries  of Registrant                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | 23.1     |   |   | Consent  of KPMG dated February 28, 2007                                                                                                                                                                                                                                                                                                                                                                                                                                                             |   |
|   | 24.1     |   |   | Powers  of Attorney                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |   |
|   | 31.1     |   |   | Certification  of Chief Executive Officer                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |   |
|   | 31.2     |   |   | Certification  of Chief Financial Officer                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |   |
|   | 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))                                                                                                                                                                                                                                                                                                             |   |

----

*                    Asteriskindicates exhibits incorporated by reference.

99

----

**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized, on this 1st day of March,2007.
|        | MIRANT CORPORATION |
|--------|--------------------|
|   | By:                | /s/ EDWARD R. MULLER |
|   | * *           | *President and Chief Executive Officer* |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below on March 1, 2007 by the following persons on behalf ofthe registrant and in the capacities indicated.
|                           | **Signatures** | ** **                                                                                  | ** ** | ** ** | **Title** | ** ** |
|---------------------------|----------------|---------------------------------------------------------------------------------------------|------------|------------|-----------|------------|
| /s/ EDWARD R. MULLER |           | Chairman of the Board, President and Chief Executive  Officer (Principal Executive Officer) |
| Edward R.  Muller    |           |
| /s/ JAMES V. IACO    |           | Executive Vice President and Chief Financial Officer  (Principal Financial Officer)         |
| James V.  Iaco       |           |
| /s/ THOMAS LEGRO          |           | Senior Vice President and Controller (Principal  Accounting Officer)                        |
| Thomas  Legro             |           |
| *                         |           | Director                                                                                    |
| A. D.  Correll       |           |
| *                         |           | Director                                                                                    |
| Thomas W. Cason      |           |
| *                         |           | Director                                                                                    |
| Terry G.  Dallas     |           |
| *                         |           | Director                                                                                    |
| Thomas H.  Johnson   |           |
| *                         |           | Director                                                                                    |
| John T.  Miller      |           |
| *                         |           | Director                                                                                    |
| Robert C.  Murray    |           |
| *                         |           | Director                                                                                    |
| John M.  Quain       |           |
| *                         |           | Director                                                                                    |
| William L.  Thacker  |           |

 

*                    Byattorney-in-fact.
| /s/ THOMAS LEGRO |   |   |
|------------------|--------|--------|
| Thomas Legro     |   |   |

 

----