MIRANT CORP - 10-K Annual Report

We are an international energy company incorporated in Delaware on April 20, 1993. Our revenues are primarily generated through the production of electricity in the United States, the Philippines and the Caribbean. As of December 31, 2004, we owned or leased approximately 18,000 megawatts (“MW”) of electric generating capacity.

We manage our business through two principal operating segments: North America and International. Our North America segment consists of the ownership and operation of power generation facilities and energy trading and marketing operations. The International segment includes power generation businesses in the Philippines, Curacao and Trinidad and Tobago, and integrated utilities in the Bahamas and Jamaica. The table below summarizes selected 2004 financial information about our business segments.

	Revenues			%		Gross Margin		%		Operating Income (Loss)				Total Assets			Cash from Operating Activities
	($ in millions)
Business Segment:
North America		$	3,522	77	%	$	1,196	61	%		$	242		$	9,354			$	(168	)
International		1,050		23		756		39			(246		)	4,730				371
Corporate and Eliminations		—		—		—		—			(14		)	(2,660		)		(132		)
Total		$	4,572	100	%	$	1,952	100	%		$	(18	)	$	11,424			$	71

The annual, quarterly and current reports, and any amendments to those reports, that we file with or furnish to the SEC are available free of charge on our website at www.mirant.com as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. General information about us, including our Corporate Governance Guidelines, the charters for our Audit, Compensation, and Nominating and Governance Committees, and our Code of Ethics and Business Conduct, can be found at www.mirant.com. We will provide print copies of these documents to any shareholder upon written request to Corporate Secretary, Mirant Corporation, 1155 Perimeter Center West, Atlanta, Georgia 30338. Information contained in our website is not incorporated into this Form 10-K.

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

Proceedings under Chapter 11 of the Bankruptcy Code

On July 14, 2003 and July 15, 2003 (collectively, the “Petition Date”), Mirant and 74 of its wholly-owned subsidiaries in the United States (collectively, the “Original Debtors”) filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. On August 18, 2003, October 3, 2003 and November 18, 2003, four additional wholly-owned subsidiaries and four affiliates of Mirant commenced Chapter 11 cases under the Bankruptcy Code (together with the Original Debtors, the “Mirant Debtors”). The Chapter 11 cases of the Mirant Debtors are being jointly administered for procedural purposes only under the case caption In re Mirant Corporation et al., Case No. 03-46590 (DML).

Additionally, on the Petition Date, certain of our Canadian subsidiaries, Mirant Canada Energy Marketing, Ltd. and Mirant Canada Marketing Investments, Inc. (together, the “Mirant Canadian Subsidiaries”), filed an application for creditor protection under the Companies’ Creditors Arrangement Act in Canada (“CCAA”), which, like Chapter 11, allows for reorganization under the protection of the court system. The Mirant Canadian Subsidiaries emerged from creditor protection on May 21, 2004. The

accounting for their emergence is reflected in this report and did not have a material impact on our operating results.

Our businesses in the Philippines and the Caribbean were not included in the court-supervised reorganizations.

The Mirant Debtors are operating their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code, the Federal Rules of Bankruptcy Procedure and applicable orders, as well as other applicable laws and rules. In general, each of the Mirant Debtors, as a debtor-in-possession, is authorized under the Bankruptcy Code to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court.

The Office of the United States Trustee has established a committee of unsecured creditors for Mirant Corporation and a committee of unsecured creditors for Mirant Americas Generation, LLC (collectively, the “Creditor Committees”). The Office of the United States Trustee also has established a committee of equity security holders of Mirant Corporation (the “Equity Committee” and, collectively with the Creditor Committees, the “Statutory Committees”). Pursuant to an order of the Bankruptcy Court, the Office of the United States Trustee appointed an examiner (the “Examiner”) in these cases to analyze certain potential causes of action and to act as a mediator with respect to certain disputes that may arise among the Mirant Debtors, the Statutory Committees and other parties in interest.

Subject to certain exceptions in the Bankruptcy Code, the Chapter 11 filings automatically stayed the initiation or continuation of most actions against the Mirant Debtors, including most actions to collect pre-petition indebtedness or to exercise control over the property of the bankruptcy estates. As a result, absent an order of the Bankruptcy Court, creditors of the Mirant Debtors are precluded from collecting pre-petition debts and substantially all pre-petition liabilities are subject to compromise under a proposed plan or plans of reorganization in the bankruptcy proceedings. One exception to this stay of litigation is for an action or proceeding by a governmental agency to enforce its police or regulatory power.

On July 24, 2003, the Bankruptcy Court approved an interim procedure requiring certain direct and indirect holders of claims, preferred securities and common stock to provide at least ten days advance notice of their intent to buy or sell claims against the Mirant Debtors or shares in Mirant Corporation. The Bankruptcy Court entered a final order on September 17, 2003 and such order establishes notice procedures applicable only to those transactions with a person or entity owning (or, because of the transaction, resulting in ownership of) an aggregate amount of claims equal to or in excess of $250 million or such higher amount determined under the order and, with respect to shares, only those persons or entities owning (or, because of the transaction, resulting in ownership of) 4.75% or more of any class of outstanding shares. In addition, each entity or person that owns at least $250 million, or such higher amount determined under the order, of certain claims or preferred securities must provide Mirant and the Creditor Committees with notice of ownership information. The Court’s orders also provide for expedited procedures to impose sanctions for a violation of its orders, including monetary damages and, in some cases, the voidance of any such transactions that violate the order. Upon election, a special regime allowing virtually unlimited trading of claims without having to provide notice thereof may be available to certain claimholders, although such electing claimholders may be required to sell a portion of their claims before a specific date. The emergency and final relief was sought to prevent potential trades of claims of stock that could negatively impact the availability of the Mirant Debtors’ U.S. net operating loss carryforwards and other tax attributes. The U.S. federal net operating loss carryforward is approximately $2.8 billion at December 31, 2004. Even with the relief that has been granted, Mirant cannot guarantee that it will be able to benefit from all, or any portion, of its U.S. federal net operating loss carryforwards and other tax attributes. Similarly, there are approximately $3.9 billion of state net operating loss carryforwards. See “Critical Accounting Policies and Estimates” for further information.

Under the Bankruptcy Code, the Mirant Debtors also have the right to assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and satisfaction of certain other conditions. The Mirant Debtors are continuing to evaluate their executory contracts in order to determine which contracts will be assumed, assigned or rejected.

In response to a motion filed under section 502(c) of the Bankruptcy Code (the “Estimation Motion”) by the Mirant Debtors, the Bankruptcy Court entered an order establishing procedures for estimating proofs of claim under section 502(c) of the Bankruptcy Code that are binding for all purposes, including voting on, feasibility of and distribution under a Chapter 11 plan for the Mirant Debtors. As a result, the Mirant Debtors filed approximately sixty material claim objections and three notices of intent to contest claims.

Plan of Reorganization

On January 19, 2005, the Mirant Debtors filed a proposed Plan of Reorganization and Disclosure Statement (the “Disclosure Statement”) with the Bankruptcy Court. The proposed Plan sets forth a proposed structure of the Company at emergence and how the claims of creditors and stockholders are to be treated. If the Disclosure Statement is found by the Bankruptcy Court to contain adequate information, then we will solicit votes on the proposed Plan from those creditors, security holders and interest holders who are entitled to vote on the proposed Plan.

The proposed Plan implements and includes the following key elements:

· the business of the Mirant Debtors will continue to be operated in substantially its current form, subject to certain internal structural changes that the Mirant Debtors believe will improve operational efficiency, facilitate and optimize their ability to meet financing requirements and accommodate the enterprise’s debt structure as contemplated at emergence;

· the original Mirant Debtors that are parties to the Chapter 11 proceedings, excluding Mirant Americas Generation, LLC (“Mirant Americas Generation”) and its subsidiaries (collectively, the “Mirant Americas Generation Debtors”), are substantively consolidated for all purposes under the proposed Plan;

· the Mirant Americas Generation Debtors are substantively consolidated for all purposes under the proposed Plan;

· the unsecured debt of the Mirant Americas Generation Debtors is to be paid in full through (i) the issuance to the lenders under the Mirant Americas Generation revolving credit facilities and the holders of Mirant Americas Generation senior notes maturing in 2006 and 2008 of (a) new debt securities of a newly formed intermediate holding company under Mirant Americas Generation (“New Mirant Americas Generation Holdco”) in an amount equal to 90% of the full amount owed to such creditors (as determined by the Bankruptcy Court) and (b) common stock in the new corporate parent of the Mirant Debtors (“New Mirant”) having a value equal to 10% of such amount owed; and (ii) the reinstatement of Mirant Americas Generation senior notes maturing in 2011, 2021 and 2031;

· to ensure the feasibility of the proposed Plan with respect to the Mirant Americas Generation Debtors and to resolve intercompany claims, the proposed Plan provides that additional value shall be contributed to Mirant Americas Generation, including the trading business (subject to an obligation to return a portion of the embedded capital in the trading business to Mirant), the Zeeland generating facility and commitments to make prospective capital contributions of up to $150 million (for refinancing) and $265 million (for sulfur dioxide capital expenditures);

· the prospective working capital requirements of Mirant Americas Generation will be met with the proceeds of a new first lien facility in the amount of at least $750 million;

· the bulk of the contingent liabilities of the Mirant Debtors associated with the California energy crisis and certain related matters will be resolved pursuant to a global settlement as described in “Item 3. Legal Proceedings” contained elsewhere in this report;

· substantially all of the assets of Mirant will be transferred to a new company to be formed pursuant to the proposed Plan, which will serve as the corporate parent of our business enterprise on and after the effective date of the proposed Plan and which shall have no successor liability for any unassumed obligations of Mirant Corporation, including any obligations to Potomac Electric Power Company (“PEPCO”) under the back-to-back agreement discussed under “Item 3. Legal Proceedings”; similarly, the trading business shall be transferred to Mirant Energy Trading, LLC, which shall have no successor liability for any unassumed obligations of Mirant Americas Energy Marketing, L.P. (“Mirant Americas Energy Marketing”), including any obligations to PEPCO under the back-to-back agreement discussed under “Item 3. Legal Proceedings” ; and

· the outstanding common stock in Mirant Corporation will be cancelled and the holders thereof will receive any surplus value after creditors are paid in full, plus the right to receive a pro rata share of warrants issued by New Mirant if they vote to accept the proposed Plan.

At present, the proposed Plan has not been approved by any of the Statutory Committees. As such, the Mirant Debtors anticipate that negotiations (which, whether or not successful, could lead to material changes to certain components of the proposed Plan) will continue between the Mirant Debtors and each of the Statutory Committees until the hearing to approve the adequacy of the Disclosure Statement. At present, the Bankruptcy Court has set the following schedule with respect to the Disclosure Statement: the First Amended Disclosure Statement is to be filed by March 25, 2005; objections to the draft Disclosure Statement are to be filed by April 1, 2005; the Second Amended Disclosure Statement is to be filed by April 15, 2005; and the Disclosure Statement adequacy hearing in the Bankruptcy Court is set for April 20, 2005.

At this time, it is not possible to accurately predict if or when the proposed Plan will be approved by the creditors and security holders and confirmed by the Bankruptcy Court, or if and when some or all of the Mirant Debtors may emerge from Bankruptcy Court protection under Chapter 11.

U.S. Competitive Environment

The power industry is one of the largest industries in the United States and has an influence on practically every aspect of the U.S. economy. Historically, the power generation industry in the United States was characterized by electric utility monopolies selling to franchised customer bases. In response to increasing customer demand for access to low-cost electricity and enhanced services, regulatory initiatives were adopted, primarily to increase wholesale and retail competition in the power industry. Following the resulting industry restructuring, merchant companies purchased plants from regulated utilities, built new capacity and began marketing to customers. At the same time, Independent System Operators (“ISOs”) and/or Regional Transmission Organizations (“RTOs”) were created to administer the new markets while maintaining system reliability. In recent years, state and federal restructuring efforts have stalled, primarily in response to the California energy crisis and financial troubles of many merchant energy companies. In addition, ISOs have begun exerting more control over market prices. The result is a blend of competitive and regulatory constructs, often different by state, under which merchant generators must compete with regulated utilities.

The substantial increase in new generation capacity that followed the restructuring of the U.S. power markets, utility capital investments to extend lives of older units, and the inability to decommission plants

for reliability reasons have created a prolonged oversupply situation. We do not expect our primary markets to reach target reserve margins, approximately 15% of excess capacity over peak demand, until 2008 to 2010. The market oversupply situation, price controls during periods of high demand or local constraint, and lack of appropriate compensation for locational capacity value currently limit fixed cost recovery for merchant generators.

With the expansion of the Pennsylvania-New Jersey-Maryland Interconnection, LLC (“ PJM”) market and the ongoing development of Midwest Independent System Operators (“MISO”), the markets themselves continue to evolve. This evolution has changed not only the utilization of generation and transmission resources, but also the voting interests among market participants.

Recently, natural gas has been the fuel of choice for new power generation facilities for economic, operational and environmental reasons. While this trend is expected to continue, some regulated utilities are now constructing clean coal units and renewable resources, often with subsidies or under legislative mandate. These utilities enjoy a lower cost of capital than most merchants and often are able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation without relying exclusively on market clearing prices to recover their investments.

Market liquidity stabilized or improved in most regions in 2004, as compared to 2003, allowing us to economically hedge portions of our expected electricity production up to 24 months in advance, primarily through exchange-traded contracts. However, market conditions, as well as conditions specific to us, have significantly reduced our marketing and risk management activities as compared to previous years.

Business Segments

For selected financial information about our business segments and information about geographic areas, see Note 20 to our consolidated financial statements contained elsewhere in this report. See “Item 2. Properties” for a complete list of our assets.

North America

Overview

In our North America segment, our core business is the production and sale of electrical energy, electrical capacity (essentially the ability to produce electricity on demand) and ancillary services. Our customers in the United States are utilities, municipal systems, aggregators, electric-cooperative utilities, producers, generators, marketers and large industrial customers. In the United States, we serve four primary geographic areas: (i) the Mid-Atlantic Region, (ii) the Northeast Region, (iii) the Mid-Continent Region, and (iv) the West Region.

Ownership and Operations of Electricity Generation Assets

As of December 31, 2004, we owned or leased generation facilities in the United States with an aggregate generation capacity of over 14,500 MW (including our Coyote Springs facility, the sale of which closed in January 2005, and our Wrightsville facility, which we expect to sell during 2005). Our domestic generating portfolio is diversified across fuel types, power markets and dispatch types and serves customers located near many major metropolitan load centers. Our total generation capacity included approximately 28% baseload units, 46% intermediate units and 26% peaking units. Mirant Americas Generation owns or controls approximately two-thirds of our U.S. generating capacity. We have six facilities in our North America business unit operating under long term contracted capacity contracts. At December 31, 2004, our contracted capacity was approximately 4,325 MW pursuant to agreements with terms expiring May 2005 through December 2014.

Commercial Operations

Our commercial operations, which are conducted through our Mirant Americas Energy Marketing subsidiary, consist of fuel procurement, power dispatch, logistics, asset hedging and risk management, and optimization trading. Mirant Americas Energy Marketing conducts its business in the markets in which we have an asset presence, which enhances our ability to deliver additional value as compared to only buying fuel and selling power in the spot market.

Pursuant to agreements with our subsidiaries that own generation facilities, Mirant Americas Energy Marketing enters into transactions for the benefit of such subsidiaries pursuant to which Mirant Americas Energy Marketing procures the appropriate fuel, formulates the daily dispatch decisions and sells the electricity generated in the wholesale market for the generation facilities. Mirant Americas Energy Marketing uses dispatch models to make daily decisions regarding the quantity and the price of the power it will sell into the markets. In most markets governed by ISOs/RTOs, Mirant Americas Energy Marketing bids the energy from our generation facilities into the ISO-run day-ahead energy market. Mirant Americas Energy Marketing also sells ancillary services through the ISO markets. In real-time, Mirant Americas Energy Marketing works with the ISOs/RTOs to ensure that our generation facilities are dispatched economically to meet the reliability needs of the market. In non-ISO markets, Mirant Americas Energy Marketing conducts business through bilateral transactions, on a day-ahead basis, pursuant to which Mirant Americas Energy Marketing provides the generation facilities with firm schedules to follow.

Mirant Americas Energy Marketing enters into contracts of varying terms to secure appropriate quantities of fuel that meet the varying specifications of our generating facilities. For our coal fired generation facilities, Mirant Americas Energy Marketing purchases coal from a variety of suppliers under both short-term and multi-year contracts. For our oil fired units, fuel is typically purchased under short-term contracts usually linked to a transparent oil index price. For our gas fired units, fuel is typically purchased under short-term contracts with a variety of suppliers.

Mirant Americas Energy Marketing enters into transactions to economically hedge our power price exposure by selling power into the wholesale market over a variety of tenors through over-the-counter transactions, exchanges and structured transactions. Mirant Americas Energy Marketing sells both energy and energy-linked commodities, including capacity and ancillary services. Mirant Americas Energy Marketing economically hedges the energy component of gross margin through futures, forwards, swaps and options. All of Mirant Americas Energy Marketing’s commercial activities are governed by our Risk Management Policy (“RMP”). The RMP requires that Mirant Americas Energy Marketing engage only in risk reducing activities with respect to hedging our assets.

While over-the-counter transactions make up a substantial portion of our economic hedge portfolio, Mirant Americas Energy Marketing also has a marketing function that serves as the interface between our generation facilities and customers. The marketing organization is focused on selling non-standard, structured products to customers. In addition to load following energy sales, these products typically include capacity, ancillary services, transmission losses and other energy products. Mirant Americas Energy Marketing views these transactions as a method of mitigating the risk of certain portions of our business that are not easy to economically hedge in the over-the-counter market. Typically, Mirant Americas Energy Marketing is able to sell these products at a higher premium than standard products. For certain generation facilities, Mirant Americas Energy Marketing has sought to enter into longer-term transactions to provide certainty of cash flows over an extended period. These transactions are typically tolling transactions whereby we receive a fixed capacity payment and, in return, grant an exclusive right for the counterparty to procure the fuel for the generation facility and take title to the power generated.

In addition to the risk management services that Mirant Americas Energy Marketing provides to our subsidiaries that own generation facilities, Mirant Americas Energy Marketing engages in optimization trading for its own account. Mirant Americas Energy Marketing generates gross margin by taking market

positions based, in part, on market and other information gathered from its relationship with our generation facilities. The optimization trading activities also are governed by the RMP, which sets forth limits on the size of trading positions and value-at-risk that Mirant Americas Energy Marketing can bear at any given time. By participating in the markets in this way, Mirant Americas Energy Marketing is better able to avoid disclosing to the markets the direction of its trading and hedging activity—to the benefit of our subsidiaries that own generation facilities. We also benefit from tighter bid/offer spreads because Mirant Americas Energy Marketing is active in the markets as both a buyer and seller.

Mid-Atlantic Region

We own, directly and indirectly, or lease four generation facilities comprising 5,256 MW of generation capacity in the Mid-Atlantic region: Chalk Point, Morgantown, Dickerson and Potomac River Station. Our Mid-Atlantic facilities were acquired from Potomac Electric Power Company (“PEPCO”) in December 2000. These facilities consist of coal and oil fired baseload units as well as coal, gas and oil fired intermediate and peaking units in Maryland and Virginia. Our largest facility in the region, the Chalk Point facility, has two coal fired baseload units, two oil and gas fired intermediate units and seven either oil fired or oil and gas fired peaking units, totaling 2,429 MW of capacity. The next largest facility, the Morgantown facility, consists of two coal and oil fired baseload units and six oil fired peaking units, totaling 1,492 MW of capacity. The Dickerson facility has three coal fired baseload units and three peaking units, totaling 853 MW of capacity, and the Potomac River Station, a coal fired facility, has three baseload and two intermediate units, totaling 482 MW of capacity.

Power generated by our Mid-Atlantic facilities is sold into the PJM market. For a discussion of the PJM market, see “Regulatory Environment—U.S. Public Utility Regulation” below. In connection with the acquisition of the Mid-Atlantic facilities from PEPCO in 2000, we, through Mirant Americas Energy Marketing, agreed to supply PEPCO its full load requirement in the District of Columbia under a transition power agreement (“TPA”), which expired in January 2005 (the “DC TPA”). There was also a similar TPA in place to supply PEPCO’s load in Maryland, which expired in June 2004 (the “Maryland TPA”).

Also, in connection with our acquisition of the Mid-Atlantic facilities from PEPCO in 2000, we agreed to purchase from PEPCO all power it received under long-term power purchase agreements with Ohio Edison Company (“Ohio Edison”) and Panda-Brandywine L.P. (“Panda”) that expire in 2005 and 2021, respectively. We and PEPCO entered into a contractual arrangement (the “PEPCO Back-to-Back Agreement”) with respect to PEPCO’s agreements with Panda and Ohio Edison under which (1) PEPCO agreed to resell to us all “capacity, energy, ancillary services and other benefits” to which it is entitled under those agreements; and (2) we agreed to pay PEPCO each month all amounts due from PEPCO to Panda or Ohio Edison for the immediately preceding month associated with such capacity, energy, ancillary services and other benefits. Under the PEPCO Back-to-Back Agreement, we are obligated to purchase power from PEPCO at prices that are significantly higher than existing market prices for power in the PJM market. On August 28, 2003, we filed a motion with the Bankruptcy Court to reject the PEPCO Back-to-Back Agreement. On December 9, 2004, we notified PEPCO and the Bankruptcy Court that we were suspending all future payments to PEPCO under the PEPCO Back-to-Back Agreement. For further information, see “Item 3. Legal Proceedings.”

Since the expiration of the Maryland TPA in June 2004 and the expiration of the DC TPA in January 2005, Mirant Americas Energy Marketing has been hedging the output of the Mid-Atlantic portfolio in the bilateral market as described previously. The terms for these transactions extend into 2006. In addition, Mirant Americas Energy Marketing enters into structured transactions with entities serving load in the greater Washington, D.C. area. Structured transactions are inherently more complicated than bilateral transactions, and we look to extract value over the mid-point of the market for such transactions. The terms for these transactions extend into 2006 as well.

Mirant Americas Energy Marketing also has participated in standard offer service auctions in Maryland and Washington, D.C. Power sales, made either directly through these functions or indirectly through subsequent market transactions that are a result of the auction process, serve as economic hedges for the Mid-Atlantic assets.

Northeast Region

We directly own or operate generating facilities in the Northeast region consisting of approximately 3,063 MW of capacity. The Northeast region is comprised of the New York and New England sub-regions.

The Mirant New York facilities were acquired from Orange and Rockland Utilities, Inc. and Consolidated Edison Company of New York, Inc. in June 1999. The New York generating facilities consist of the Bowline and Lovett facilities and various smaller generating facilities comprising a total of approximately 1,675 MW of capacity. The Bowline facility is a 1,133 MW dual fueled (natural gas and oil) facility comprised of two intermediate units. The Lovett facility consists of two baseload units capable of burning coal and gas comprising a total of 348 MW and a peaking unit capable of burning gas or oil comprising 63 MW. The smaller New York plant operations include two peaking units (the Hillburn gas turbine station and the Shoemaker gas turbine station), three hydroelectric stations (Mongaup 1-4, Swinging Bridge 1-2 and Rio 1-2) and an operational interest in the Grahamsville Hydroelectric Station comprising a total of 132 MW. An expansion at the Bowline facility, a 750 MW natural gas and distillate oil fired combined cycle unit, is currently suspended.

The Mirant New England facilities, with a total capacity of 1,388 MW, were acquired from subsidiaries of Commonwealth Energy System and Eastern Utilities in December 1998. The New England generating facilities consist of the Canal station, the Kendall station, the Martha’s Vineyard diesels and the Wyman Unit 4 interest. The Canal and Kendall facilities, consisting of approximately 1,109 MW and 256 MW of generating capacity, respectively, are designed to operate during periods of intermediate and peak demand, and are located in close proximity to Boston. The Kendall facility has been repowered since its acquisition and is now a natural gas combined cycle facility capable of producing both steam and electricity for sale. Both the Canal and Kendall facilities possess the ability to burn both natural gas and fuel oil. The Martha’s Vineyard diesels, with 14 MW of capacity, supply electricity on the island of Martha’s Vineyard during periods of high demand or in the event of a transmission interruption. The Wyman Unit 4 interest is an approximate 1.4% ownership interest (equivalent to 8.8 MW) in the 614 MW Wyman Unit 4 located on Cousin’s Island, Yarmouth, Maine. It is primarily owned and operated by the Florida Power and Light Group.

Generation is sold from our Northeast assets through a combination of bilateral contracts and spot market transactions, as well as structured transactions. The Mirant New York plants participate in a market operated by the Independent System Operator of New York (“NYISO”). The capacity, energy and ancillary services from the Mirant New England generating units are sold into the New England Power Pool (“NEPOOL”) through our commercial operations. NEPOOL is administered by the ISO of New England (“ISO-NE”). For a discussion of the NYISO, NEPOOL and the ISO-NE, see “Regulatory Environment—U.S. Public Utility Regulation” below.

Market fundamentals in the NYISO do not permit us to operate the Lovett facility on an economic basis as a merchant generation facility because of upcoming required environmental capital expenditures and property taxes associated with the facility. Our current plan is to retire the Lovett facility, starting with Unit 5 in 2007 and Units 3 and 4 in 2008. Market fundamentals in NEPOOL do not permit us to operate the Kendall facility on an economic basis as a merchant facility. Our plan has been to shutdown, at least temporarily, the Kendall facility from January 2006 through December 2007, with the possibility of restarting operations as early as January 2008. However, the ISO-NE has determined that a small part of the capacity of the Kendall facility is needed for reliability and has negotiated a Reliability-Must-Run (“RMR”) contract with respect to the Kendall facility with a term of approximately one year. We filed this contract with the Federal Energy Regulatory Commission (“FERC”) for RMR status under the existing tariff on October 7, 2004 and are currently waiting for FERC approval or acceptance of the agreement and the revenue requirements contained within it. We and the other parties in this proceeding are currently in settlement negotiations. We and NStar Electric & Gas Corp., the local contracting utility, have reached a preliminary agreement that, once finalized and accepted or approved by the FERC, will resolve virtually all of the issues raised in this proceeding.

Mid-Continent Region

The Mirant Mid-Continent facilities, consisting of an equity interest in roughly 2,668 MW, are located in the Midwest and Southeast markets. The Midwest facilities, which include our Sugar Creek and Mirant Zeeland facilities, consist of over 1,372 MW of generating capacity and are all natural gas fired peaking and/or intermediate units. The Southeast facilities include three facilities, Wrightsville, West Georgia and Shady Hills, with a net equity interest of 1,296 MW.

The Sugar Creek facility is a combined cycle facility with the capability to produce 535 MW. Located in West Terre Haute, Indiana, the Sugar Creek facility has the physical capability to be interconnected with either the Cinergy or American Electric Power, Inc. (“AEP”) systems. Cinergy is a member of the MISO, and AEP is a member of the PJM market. The facility is eligible to deliver energy and participate in the energy, capacity and ancillary markets of the PJM market.

The Mirant Zeeland facility, a combined cycle facility in Zeeland, Michigan, has generating capacity of 837 MW and is interconnected with the International Transmission Company, which is a member of the MISO. Both the Zeeland and Sugar Creek facilities operate under the East Central Area Reliability Coordination Agreement (“ECAR”).

The West Georgia facility in Thomaston, Georgia and the Shady Hills facility in Pasco County, Florida consist of gas and oil fired combustion turbines serving peak loads of approximately 605 MW and 468 MW, respectively.

The Wrightsville facility consists of gas fired intermediate/peaking units with generating capacity of 438 MW. In 2004, we mothballed this facility, pending regional recovery of power prices. In February 2005, we entered into an agreement to sell the Wrightsville facility to Arkansas Electric Cooperative Corporation (“AECC”), subject to Bankruptcy Court approval and certain other regulatory and third-party consents and approvals. We expect the sale of the Wrightsville facility to close in 2005.

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

West Region

Our West region facilities consist of a net equity interest in 3,602 MW of gas fired generating capacity in California, Oregon, Nevada and Texas.

The generating assets in California provide a total capacity of 2,347 MW and consist of the Pittsburg, Contra Costa and Potrero plants, which include facilities operating at both intermediate and peak demand levels located in, or in close proximity to, San Francisco. The Pittsburg and Contra Costa plants consist of five intermediate natural gas fired steam generating units with approximately 1,985 MW of generating capacity located approximately ten miles apart along the Sacramento/San Joaquin River Delta. The Potrero plant has one baseload natural gas fired conventional steam generating unit and three peaking distillate fueled combustion turbines with a combined capacity of 362 MW.

The majority of our California assets are subject to RMR agreements with the California Independent System Operator (“CAISO”). These agreements are described further under “Regulatory Environment—U.S. Public Utility Regulation” below. The Mirant California subsidiaries currently have the largest portfolio of units which operate under RMR contracts, reflecting the fact that the location of these units is key to the electric system reliability. Contra Costa Unit 6 is not a party to an RMR agreement, and thus functions solely as a merchant facility in the CAISO. Mirant Americas Energy Marketing sells the output of Contra Costa Unit 6 into the market through bilateral transactions with utilities and other merchant players.

In October 2004, the CAISO notified us that the RMR contract for Pittsburg Unit 7 would not be renewed for 2005. On January 3, 2005, Mirant Americas Energy Marketing announced that it was seeking proposals for a one-, two- or three-year tolling arrangement for Pittsburg Unit 7 and Contra Costa Unit 6. We received bids on January 28, 2005, and we are in the process of evaluating these bids at this time. If this request for proposal does not result in an acceptable contract for Pittsburg Unit 7, we intend to retire Pittsburg Unit 7, consisting of 682 MW, by the middle of 2005, due to new nitrogen oxide (“NOx”) emissions standards that would require significant capital and operating and maintenance expenditures.

Coyote Springs is a 280 MW intermediate combined-cycle gas fired plant, located in Boardman, Oregon, that began commercial operations in July 2003. In October 2004, we entered into an agreement to sell our 50% interest in Coyote Springs to Avista Utilities, subject to Bankruptcy Court and the FERC approval. The Bankruptcy Court and the FERC approved the sale in December 2004 and the sale was completed for $63 million in January 2005.

The Apex generating facility, a 500 MW intermediate gas combined-cycle facility located near Las Vegas, Nevada, was developed by us and began commercial operations in May 2003.

We operate two facilities in Texas: the Bosque facility and the Wichita Falls facility. The Bosque facility consists of a gas fired combustion turbine with a corresponding steam turbine (combined cycle unit) with a capacity of 230 MW that is available to serve baseload and intermediate demand. Additionally, Bosque Units 1 and 2 are gas fired peakers with a capacity of 154 MW each. The Wichita Falls facility is a combined cycle facility and consists of three gas turbines and a steam turbine with a total capacity of 77 MW. The Wichita Falls facility primarily sells its electrical output to the merchant market.

Both the Bosque and Wichita Falls facilities operate in the Electric Reliability Council of Texas (“ERCOT”) market. For a discussion of ERCOT, see “Regulatory Environment—U.S. Public Utility Regulation” below.

International

Through various subsidiaries, we own or control under operating agreements various generation, transmission and distribution operations in the Philippines and the Caribbean. A complete list of our international properties is contained in “Item 2. Properties.”

Philippines

We, indirectly through our Philippine subsidiaries, have ownership, leasehold or similar interests in nine generating facilities in the Philippines. As of December 31, 2004, our net ownership interest in the generating capacity of these facilities was approximately 2,300 MW. Over 80% of the generation capacity in the Philippines facilities is sold under long-term energy conversion agreements with the Philippine government-owned National Power Corporation (“NPC”). NPC acts as both the fuel supplier and the energy purchaser under the energy conversion agreements for our Pagbilao, Sual, Navotas II and Ilijan facilities. NPC procures all of the fuel necessary for generation under an energy conversion agreement, at no cost to the respective subsidiary or associate, and has substantially all fuel risks and fuel related obligations under the agreement other than those relating to the fuel burning efficiency of the facility. In addition to the energy conversion agreements with NPC, our Sual and Pagbilao subsidiaries have joint marketing agreements with NPC for excess capacity of 218 MW and 35 MW, respectively. Currently, electricity from the excess capacity of our Sual facility is provided to select markets such as economic zones, industries and private electric distribution companies and cooperatives.

Under the energy conversion agreements, our respective subsidiaries and associates receive both fixed capacity fees and variable energy fees. Currently, approximately 90% of our revenues with respect to our Philippine operations come from fixed capacity charges under long-term contracts that are paid without regard to the dispatch level of the facility. Nearly all of our capacity fees are denominated in U.S. dollars. Energy fees have both U.S. dollar and Philippine peso components that are indexed to inflation. The majority of the obligations of NPC under the energy conversion agreements are guaranteed by the full faith and credit of the Philippine government. The energy conversion agreements are executed under the Philippine government’s build-operate-transfer program. At the end of the term of each energy conversion agreement, the facility is to be transferred to NPC, free from any lien or payment of compensation. The energy conversion agreements for our Navotas II, Sual, Pagbilao and Ilijan facilities expire in July 2005, October 2024, August 2025 and January 2022, respectively.

Our larger Philippine projects have been granted preferred or pioneer status that, among other things, has qualified them for income tax holiday incentives of three to six years. The income tax holiday incentive expired in June 2002 for our Pagbilao facility and will expire in October 2005 and January 2008 for our Sual and Ilijan facilities, respectively. The amount of benefit from these holiday incentives is $54 million, $50 million, and $69 million for 2004, 2003, and 2002, respectively.

Deregulation and Privatization

In June 2001, the Philippine Congress approved and passed into law the Electric Power Industry Reform Act (“EPIRA”), providing the mandate and the framework to introduce competition in the Philippine electricity market. EPIRA also provides for the privatization of the assets of NPC, including its generation and transmission assets, as well as its contracts with independent power producers (“IPPs”). The deregulation of the Philippine electricity industry and the privatization of NPC have been long anticipated, and EPIRA is not expected to have a material impact on our existing Philippine assets or our operations.

EPIRA provides that competition in the retail supply of electricity and open access to the transmission and distribution systems would occur within three years from its effective date. Prior to June 2002, concerned government agencies were to establish a wholesale electricity spot market, ensure the unbundling of transmission and distribution wheeling rates and remove existing cross-subsidies provided by industrial and commercial users to residential customers. As of December 2004, most of these changes have started to occur but are considerably behind the schedule set by the Philippine Department of Energy.

Under EPIRA, NPC’s generation assets are to be sold through transparent, competitive public bidding, while all transmission assets are to be transferred to the Transmission Company, initially a government-owned entity that is to eventually be privatized. The privatization of these NPC assets has been delayed and is considerably behind the schedule set by the Philippine Department of Energy.

EPIRA also created the Power Sector Assets and Liabilities Management Corporation (“PSALM”), which is to accept transfers of all assets and assume all outstanding obligations of NPC, including its obligations to IPPs. One of PSALM’s responsibilities is to manage these contracts with IPPs after NPC’s privatization. PSALM also is responsible for privatizing at least 70% of the transferred generating assets and IPP contracts no later than three years from the effective date of the law. As of December 2004, the work related to the planned privatization has commenced, but is considerably behind schedule.

Consistent with the announced policy of the Philippine government, EPIRA contemplates continued payment of NPC’s obligations under its energy conversion agreements. The energy conversion agreements of our Philippine subsidiaries are not assignable without consent. We are in continuing discussions with NPC and PSALM on a proposal to add PSALM as an additional obligor under its existing IPP contracts. Additionally, the Philippine government issued performance undertakings to guarantee the performance of NPC’s obligations under certain energy conversion agreements.

Philippine IPP Review

Pursuant to EPIRA, a governmental inter-agency committee reviewed all IPP contracts and reported that some contracts had legal or financial issues requiring further review or action, including contracts with our subsidiaries. Subsequently, we, along with PSALM, the Philippine Department of Energy and the Philippine Department of Justice entered into a letter of agreement establishing a general framework (the “General Framework Agreement”) for resolving all outstanding issues raised by the committee about IPP contracts with our subsidiaries.

In March 2003, the conditions precedent for our Sual and Pagbilao components of the General Framework Agreement were satisfied and the implementation agreements relating to both became effective. As a result of the General Framework Agreement, the original energy conversion agreements for our Sual and Pagbilao facilities remain intact and are reaffirmed with no resultant material financial impact.

Caribbean

Our net ownership interest in the generating capacity of our Caribbean plants is approximately 1,000 MW.

Grand Bahama Power Company (“Grand Bahama Power”)

We own a 55.4% interest in Grand Bahama Power, an integrated electric utility company that generates, transmits, distributes and sells electricity on Grand Bahama Island. Grand Bahama Power has the exclusive right and obligation to supply electric power to the residential, commercial and industrial customers on Grand Bahama Island. Grand Bahama Power’s rates are approved by the Grand Bahama Port Authority.

The Power Generation Company of Trinidad and Tobago (“PowerGen”)

We own a 39% interest in PowerGen, a power generation company that owns and operates three plants located on the island of Trinidad. The electricity produced by PowerGen is provided to the Trinidad and Tobago Electricity Commission (“T&T EC”), the state-owned transmission and distribution monopoly, which serves approximately 347,000 customers on the islands of Trinidad and Tobago and

which holds a 51% interest in PowerGen. PowerGen has a power purchase agreement for approximately 820 MW of capacity and spinning reserve with the T&T EC, which expires in 2009 and is unconditionally guaranteed by the government of Trinidad and Tobago. Under this contract, the fuel is provided by the T&T EC.

In response to a September 3, 2004 request for proposals issued by National Gas Company of Trinidad and Tobago Limited (“NGC”), on November 30, 2004, PowerGen submitted a bid to build new generation and provide electric generation capacity under long term power purchase agreements to National Energy Corporation (“NEC”) and T&T EC. The request for proposals contemplates a need of between 200 MW and 250 MW for T&T EC and possibly a further need of between 400 MW and 540 MW for NEC with commercial operations dates between the third quarter of 2006 and March 2008. PowerGen will likely have definite resolution related to this bid by mid-2005.

Jamaica Public Service Company Limited (“JPS”)

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. JPS operates under a 20-year All-Island Electric License that expires in 2021 and that provides JPS with the exclusive right to sell power in Jamaica. JPS has installed generation capacity of 600 MW, and it purchases an additional 146 MW of firm capacity from three IPPs under long-term purchase agreements and an additional 20 MW of energy from a wind farm on an as-available basis. JPS supplies electric power to approximately 540,000 residential, commercial and industrial customers in Jamaica. At present, JPS is regulated by the Office of Utilities and Regulation under a price cap model with rate cases held every five years and with interim adjustments indexed to inflation and foreign exchange movements.

Curacao Utilities Company (“CUC”)

We own a 25.5% interest in CUC at the Isla Refinery in Curacao, Netherlands Antilles. The 133 MW facility provides electricity, steam, desalinated water and compressed air to the refinery and up to 45 MW of electricity to the Curacao national grid.

Aqualectra

We own a $40 million convertible preferred equity interest in Aqualectra, an integrated water and electric company in Curacao, Netherlands Antilles, owned and operated by the government. Aqualectra has electric generating capacity of 235 MW and drinking water production capability of 69,000 cubic meters per day. Aqualectra serves approximately 65,000 electricity and water customers. We receive 16.75% preferred dividends on our $40 million investment on a quarterly basis. Aqualectra has a call option and we have a put option, both of which became exercisable for the three-year period beginning on December 19, 2004. We also have an option to convert our convertible preferred equity interest in Aqualectra to common shares during the same three-year period beginning December 19, 2004.

Regulatory Environment

U.S. Public Utility Regulation

The U.S. electricity industry is subject to comprehensive regulation at the federal, state and local levels. At the federal level, the FERC has exclusive jurisdiction under the Federal Power Act (the “Federal Power Act”), over sales of electricity at wholesale and the transmission of electricity in interstate commerce. A Mirant subsidiary that owns generating facilities selling at wholesale or that markets electricity at wholesale outside of ERCOT is a “public utility” subject to the FERC’s jurisdiction under the Federal Power Act. These Mirant subsidiaries must comply with certain FERC reporting requirements and FERC-approved market rules and are subject to FERC oversight of mergers and acquisitions, the

disposition of FERC-jurisdictional facilities, and the issuance of securities, for which blanket authority has been granted. In addition, under the Natural Gas Act (“NGA”), the FERC has limited jurisdiction over certain sales for resale of natural gas, but does not regulate the prices received by the Mirant subsidiary that markets natural gas.

The FERC has authorized the public utility Mirant subsidiaries to sell energy and capacity at wholesale market-based rates and has authorized some of the public utility Mirant subsidiaries to sell certain ancillary services at wholesale market-based rates. The majority of the output of the generation facilities owned by Mirant’s public utility subsidiaries in the United States is sold pursuant to this authorization, although certain of our facilities sell their output under cost-based RMR agreements, as explained below. The FERC may revoke or limit our market-based rate authority if it determines that we possess market power. The FERC requires that our subsidiaries with market-based rate authority, as well as those with blanket certificate authorization permitting market-based sales of natural gas, adhere to certain market behavior rules and codes of conduct, respectively. If our subsidiary violates the market behavior rules or codes of conduct, the FERC may require a disgorgement of profits or revoke its market-based rate authority or blanket certificate authority. If the FERC were to revoke market-based rate authority, the Mirant subsidiary would have to file a cost-based rate schedule for all or some of its sales of electricity at wholesale. If the FERC revoked the blanket certificate authority of a Mirant subsidiary, it would no longer be able to make certain sales of natural gas.

In an effort to promote greater competition in wholesale electricity markets, the FERC has encouraged the formation of ISOs and RTOs. In those areas where ISOs or RTOs control the regional transmission systems, market participants have expanded access to transmission service. ISOs and RTOs also may operate real-time and day-ahead energy and ancillary services markets, which are governed by FERC-approved tariffs and market rules. Some RTOs and ISOs also operate capacity markets. Changes to the applicable tariffs and market rules may be requested by market participants, state regulatory agencies and the system operator, and such proposed changes, if approved by the FERC, could have an impact on our operations and business plan. While participation by transmission-owning public utilities in ISOs and RTOs has been and is expected to continue to be voluntary, the majority of such public utilities in New England, New York, the Mid-Atlantic, the Midwest and California have joined the existing ISO/RTO for their respective region. The majority of our facilities operate in these ISO/RTO regions.

We are not currently subject to the Public Utility Holding Company Act of 1935, as amended (“PUHCA”), and do not anticipate becoming so unless we acquire the securities of a public utility company or public utility facility that does not qualify as an exempt wholesale generator, a foreign utility company, or a qualifying small power production or cogeneration facility. Currently, our subsidiaries owning generation in the United States are exempt wholesale generators under PUHCA, and all of our subsidiaries owning generation outside the United States are either foreign utility companies or exempt wholesale generators.

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

Mid-Atlantic Region—Our Mid-Atlantic assets sell power into the markets operated by PJM, which the FERC approved to operate as an ISO in 1997 and as an RTO in 2002. We have access to the PJM transmission system pursuant to PJM’s Open Access Transmission Tariff. PJM operates the PJM Interchange Energy Market, which is the region’s spot market for wholesale electricity, provides ancillary

services for its transmission customers and performs transmission planning for the region. To account for transmission congestion and losses, PJM calculates electricity prices using a locational-based marginal pricing model and dispatches electricity on a security constrained least cost basis. On January 24, 2005, the FERC issued an order changing PJM’s mitigation rules for frequently mitigated units (those mitigated in excess of 80% of annual running hours), as well as the retirement policy rules. The revised policy provides some opportunity for increased compensation for frequently mitigated units. Under the old rules, such units were restricted to bidding variable costs plus 10% when a transmission constraint caused the unit to be selected out of economic merit order. Under the new rules, the restriction is variable costs plus $40/megawatt hour (“MWh”). Units mitigated less than 80% of the time remain under the old “cost plus 10%” policy. PJM also proposed a revised generation retirement policy that sets forth a process by which PJM will address a request by a generation owner to deactivate a unit, determine whether established reliability criteria would be violated if the unit were deactivated, and provide compensation to the generation owner when a unit proposed for deactivation is required to continue operating for reliability. This proposal was also approved. Both changes are currently effective, although possibly subject to revision via requests for rehearing. PJM is also developing a redesign of its capacity obligations, referred to as a Reliability Pricing Model (“RPM”), and the RPM is anticipated to be filed at the FERC in late March 2005. If filed in a form resembling stakeholder discussions to date, and ultimately approved by the FERC, this proposal would also provide some opportunity for an improved revenue stream for Mirant-owned capacity. However, the FERC’s response to these issues and the final impact, if any, on our facilities cannot be determined at this time.

PJM has greatly expanded its system over the last two years with the addition of the service areas of Allegheny Power, Commonwealth Edison, AEP, Duquesne Light and Dayton Power & Light (“DP&L”) and the anticipated addition of Dominion-Virginia Power in 2005. In the fall of 2004, PJM completed its integration of AEP and DP&L into the PJM RTO. For purposes of determining deliverability to the unforced capacity market (“UCAP market”), AEP and DP&L were deemed to be capable of providing capacity to all areas of PJM. This effectively provided the same comparability of delivery for a generator in western Ohio to deliver capacity to the PEPCO zone where our assets are located. The deliverability standard and the additional capacity that the new entrants are now capable of providing to the UCAP market in PJM has severely depressed forward pricing for capacity. PJM has proposed a new RPM that will provide for recognition of locational deliverability zones. The model proposes a phase in to locational zones over a four-year period. In addition, PJM and MISO have been directed by the FERC to establish a common and seamless market, an effort that is largely dependent upon MISO’s ability to first establish and operate its markets.

Northeast Region—Our New York plants participate in a market controlled by NYISO, which replaced the New York Power Pool (“NYPP”). NYISO provides statewide transmission service under a single tariff and interfaces with neighboring market control areas. To account for transmission congestion and losses, NYISO calculates energy prices using a locational-based marginal pricing model that is similar to that used in the PJM and ISO-NE. NYISO also administers a spot market for energy, as well as markets for installed capacity, operating reserves and regulation service. NYISO employs an Automated Mitigation Procedure (“AMP”) in its day-ahead market that automatically caps energy bids when certain established bid screens indicate a bidder may have market power. On January 14, 2005, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded the FERC’s orders approving the AMP. The AMP provisions of the NYISO’s tariff remain in effect pending further proceedings. In addition, the NYISO’s locational capacity market rules use a “demand curve” mechanism to determine for every month the required amount of installed capacity as well as installed capacity prices for three locational zones: New York City, Long Island and the rest of New York. Our facilities operate outside of New York City and Long Island. The demand curve is derived for each of the three zones by setting the price of installed capacity for 118% of peak load (peak load plus an 18% reserve margin) at the assumed price for a new generating plant to serve peak demand (“new entrant”) and then sloping the “demand curve” for installed capacity downward to reflect

additional amounts of capacity beyond the 118%. The FERC approved the new entrant price for use from the summer of 2003 to the spring of 2005, and required NYISO to file three proposed new entrant prices that would be applicable from the summer of 2005 through the spring of 2008. On January 7, 2005, NYISO filed revisions to its services tariff to define the demand curves for capability years 2005/2006, 2006/2007 and 2007/2008. A FERC order is expected on the 2005 through 2008 demand curves in March 2005. The FERC’s 2003 order approving the existing demand curves has been appealed by a trade association to the U.S. Court of Appeals for the D.C. Circuit.

Our New England plants also participate in a market administered by ISO-NE, under contract to NEPOOL, which is a voluntary association of electric utilities and other market participants in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. The FERC has approved a RTO for the New England region (“RTO-NE”), which assumed responsibility for the operation of transmission systems and administration and settlement of the wholesale electric energy, capacity and ancillary services markets on February 1, 2005. ISO-NE utilizes a locational marginal pricing model, with a price mitigation method similar to NYISO’s AMP. In 2004, the FERC approved a locational installed capacity market for ISO-NE based on the “demand curve” concept also used by NYISO, to be implemented in January 2006. A hearing on the demand curve parameters was held in late February and early March and a FERC order on these proposals is expected in mid to late-2005.

Mid-Continent Region—Our Mid-Continent plants are located in the Midwest and Southeast markets. In the Midwest markets, our plants participate in a market to be administered by MISO. The FERC approved the formation of MISO in 2001, and it currently administers transmission operations. MISO intends to operate energy markets similar to those operated by PJM and has received FERC approval to commence operating energy markets on March 1, 2005. However, due to a desire to test thoroughly before implementation, MISO has voluntarily elected to delay actual implementation until April 1, 2005. MISO plans to use locational marginal pricing for energy and associated financial transmission rights so that market participants may manage the risks associated with moving energy from generation sources to load. The market plan also includes both a day-ahead energy market based on firm financial commitments to provide energy and a real-time market for physical supply and demand. MISO proposes to implement a capacity market by June 1, 2006, but has not yet identified a specific capacity market design. MISO also proposes to implement mitigation rules similar to those of NYISO, but will likely not implement an automatic price cap. While tangible progress continues to be made toward actual implementation, we still cannot provide assurance regarding whether or when MISO will commence operation of its new market or what the impact on our earnings could be. The Sugar Creek facility is interconnected to both MISO and PJM, through Cinergy and AEP’s transmission system, and can sell into either market (though not into both simultaneously). Sugar Creek is eligible to participate in the PJM capacity and energy markets.

In the Southeast, we currently sell electric energy and capacity from our facilities under bilateral contracts that contain terms and conditions that are not standardized and that have been negotiated on an individual basis. Customers in this region include investor-owned, vertically integrated utilities, municipalities and electric cooperatives.

West Region—Our West plants are located in the Western Interconnection and the ERCOT market in Texas. California accounts for roughly 40% of the energy consumption in the Western Interconnection. Approximately 75% of California’s demand is served from facilities in the CAISO control area, which includes our California facilities. The CAISO schedules transmission transactions, arranges for necessary ancillary services and administers a real-time balancing energy market. The CAISO has proposed changes to its market design to more closely mirror the eastern RTO markets. The market redesign has been delayed several times, with full implementation now expected in 2007 or 2008. The California Public Utility Commission (“CPUC”) has taken the lead role for establishing capacity requirements in California and has ordered California’s load-serving entities to meet specific load and reserve requirements beginning in the summer of 2006. The CAISO has not proposed a capacity market mechanism in its market redesign.

The majority of our assets in California are subject to RMR agreements with the CAISO. These agreements require certain of our facilities, under certain conditions and at the CAISO’s request, to operate at specified levels in order to support grid reliability. Under the RMR agreements, we recover through fixed charges either a portion (RMR Contract Condition 1) or all (RMR Contract Condition 2) of the annual fixed revenue requirement of the generation assets as approved by the FERC (the “Annual Requirement”). Our California generation assets operating under RMR Contract Condition 1 depend on revenue from sales of the output of the plants at market prices to recover the portion of the plant’s fixed costs not recovered in RMR payments. For these generation assets, only a percentage of the Annual Requirement, as approved by the FERC, can be recovered through RMR payments, whereas RMR Contract Condition 2 Units recover 100%. The contracts require yearly filings for FERC approval of the Annual Requirement for the following calendar year.

The CAISO imposes a $250/MWh cap on prices for energy and capacity and has implemented an AMP similar to that used by NYISO. Owners of non-hydroelectric generation in California, including certain of our facilities, must offer power in the CAISO’s spot markets if the output is not scheduled for delivery within the hour. For the remaining units located outside of California, but within the Western Interconnection, there is no single entity responsible for a centralized bid-based market. Outside of California, the primary markets in the West today are bilateral and adhere to the reliability standards of the Western Electricity Coordinating Council (“WECC”). Although we are active participants in initiatives to establish new ISOs or RTOs in the West, we can neither predict when, nor if, such entities will emerge nor if market developments will have a positive or negative impact on future earnings from our Western assets.

Our Texas plants participate in a market administered by the ERCOT ISO, which manages a major portion of the state’s electric power grid. ERCOT ISO oversees competitive wholesale and retail markets resulting from electricity restructuring in Texas and protects the overall reliability of the ERCOT grid. ERCOT ISO, the only ISO that manages both wholesale and retail market operations, is regulated by the Public Utility Commission of Texas (“PUCT”). The PUCT conducts market monitoring within ERCOT. Price mitigation measures in ERCOT include a $1,000 per MWh price cap and RMR-type contracts for congested areas. To improve congestion management, the PUCT recently established a rulemaking proceeding on wholesale market design issues that will focus on adding a congestion management mechanism based on locational pricing, similar to that used in PJM, and a day-ahead market. A revised market design is expected to be in place by 2005 but, as with other evolving market structures, we cannot provide assurance as to when the enhancements will be completed and implemented, or what the impact on earnings in the ERCOT market will be.

Environmental Regulation

United States

Air Emissions Regulations: Our business is subject to extensive environmental regulation by federal, state and local authorities, which requires continuous compliance with regulations and conditions established by their operating permits. Our most significant environmental requirements in the United States arise under the federal Clean Air Act of 1990, as amended (the “Clean Air Act”), and similar state laws. Under the Clean Air Act, we are required to comply with a broad range of requirements and restrictions concerning air emissions, operating practices and pollution control equipment. Several of our facilities are located in or near metropolitan areas, such as New York City, Boston, San Francisco and Washington D.C., which are classified by the U.S. Environmental Protection Agency (“EPA”) as not achieving certain federal ambient air quality standards. The regulatory classification of these areas subjects our operations in these areas to more stringent air regulation requirements, potentially including, in some cases, required emission reductions. Also, states are required by Section 185 of the Clean Air Act to impose additional fees for air emissions from major sources in areas that are classified as severe non-attainment for ozone and that fail to meet the attainment deadline. For example, the Virginia and

Maryland suburbs of Washington D.C. are part of the Washington, D.C. non-attainment area and currently are classified as severe non-attainment for ozone, applying a one-hour ozone standard. The EPA has designated this area as moderate non-attainment applying a new eight-hour standard and has indicated that it will rescind the one-hour ozone standard in June 2005. If it does not rescind the one-hour standard and the November 2005 attainment deadline under the one hour standard is not met, Section 185 of the Clean Air Act would require Virginia and Maryland to begin imposing additional fees on major sources of ozone beginning in 2006. The formula for determining this fee has not been finally established, but is likely to be a significant cost for our Mid-Atlantic plants. On September 27, 2004, we entered into a conditional consent decree resolving an enforcement proceeding with the state of Virginia and EPA. The consent decree was also entered into by the state of Maryland and the Department of Justice (the “DOJ”) on behalf of the EPA. The consent decree creates annual and ozone season caps on NOx emissions, provides for certain additional pollution controls, supplemental environmental projects to be done at the Potomac River plant and a $500,000 fine. Approvals by the Federal District Court in Alexandria and the Bankruptcy Court are being sought.

In the future, we anticipate increased regulation of generation facilities under the Clean Air Act and applicable state laws and regulations concerning air quality. The EPA and several states in which we operate are in the process of enacting more stringent air quality regulatory requirements.

For example, the EPA promulgated regulations (referred to as the “NOx SIP Call”), which establish emission cap and trade programs for NOx emissions from electric generating units in most of the Eastern states. These programs were implemented beginning May 2003 in the Northeast and May 2004 in the rest of the region. Under these regulations, a plant receives an allocation of NOx emission allowances, and if a plant exceeds its allocated allowances, the plant must purchase additional, unused allowances from other regulated plants or reduce emissions, which could require the installation of emission controls. Our plants in Maryland, New York and Massachusetts complied with similar state and regional NOx emission cap and trade programs from 1999 to 2002, which has been superseded by the EPA NOx cap and trade program. Some of our plants in these states are required to purchase additional NOx allowances to cover their emissions and maintain compliance. The cost of these allowances may increase in future years and may result in some of our plants reducing NOx emissions through additional controls, the cost of which could be significant but would be offset in part by the avoided cost of purchasing NOx allowances to operate the plant.

The EPA also has promulgated regulations that establish emission cap and trade programs for sulfur dioxide (“SO2”) emissions (the “Acid Rain Program”) from electric generating units in the United States. This Acid Rain Program was implemented in two phases. Phase I began in 1995 and affected 263 units at 110 mostly coal-burning electric utility plants located in 21 Eastern and Midwestern states. Phase II, which began in 2000, tightened the annual emissions limits imposed on Phase I plants and also set restrictions on smaller, cleaner plants fired by coal, oil and gas encompassing over 2,000 units in all. The Acid Rain Program affects existing utility units serving generators with an output capacity of greater than 25 MW and all new utility units. The Acid Rain Program represents a dramatic departure from traditional command and control regulatory methods, which establish specific, inflexible emissions limitations with which all affected sources must comply. Instead, the Acid Rain Program introduces an allowance trading system that harnesses the incentives of the free market to reduce pollution. Under this system, affected utility units were allocated allowances based on their historic fuel consumption and a specific emissions rate. Each allowance permits a unit to emit one ton of SO2 during or after a specified year. Allowances may be bought, sold or banked. Anyone may acquire allowances and participate in the trading system. The Acid Rain Program set a permanent ceiling (or cap) of 8.95 million allowances for total annual allowance allocations to utilities. All of our facilities are in compliance with the requirements of the Acid Rain Program. Some of our plants have surplus allowances and some are required to purchase additional SO2 allowances to cover their emissions and maintain compliance. The costs of these allowances may increase in future years and may result in some of our plants reducing SO2 emissions through additional controls,

the cost of which could be significant but would be offset in part by the avoided cost of purchasing SO2 allowances to operate the plant.

The Acid Rain Program also has a NOx emission reduction program. This program only affects coal fired units and also was implemented in a two-phase approach in 1995 and 2000. This program is not a cap and trade program but identifies specific emission rates and/or control technology requirements. We have installed the NOx control technology and/or are meeting applicable emission rates. All our coal units are in compliance with requirements of the Acid Rain Program’s NOx emission reduction program. We foresee no additional expense to comply with this program.

The EPA has proposed regulations to govern mercury air emissions from coal fired power plants. This proposal offers alternate regulatory approaches, which include a cap and trade program that would go into effect in January 2010 and a maximum achievable control technology standard (unit specific emission standard) that would go into effect in December 2007, which may be extended by the EPA to December 2008. The mercury regulations are likely to require significant emission reductions from coal fired power plants. This rulemaking also proposes new regulations governing nickel air emissions from oil fired power plants, which would either go into effect in December 2007, with a possible one-year extension by the EPA to December 2008, or go into effect January 2010. The cost to comply with such requirements could be significant.

During the course of this decade, the EPA will be implementing new, more stringent ozone and particulate matter ambient air quality standards. It will also address regional haze visibility issues, which will result in new regulations that will likely require further emission reductions from power plants, along with other emission sources such as vehicles. To implement these air quality standards, the EPA promulgated the Clean Air Interstate Rule (“CAIR”) on March 10, 2005. The CAIR establishes in the eastern United States a more stringent SO2 cap and allowance-trading program and a year round NOx cap and allowance-trading program applicable to power plants. These cap and trade programs will be implemented in two phases, with the first phase going into effect in 2009 and more stringent caps going into effect in 2015.

These future mercury and nickel regulations and the CAIR would increase compliance costs for our operations and would likely require emission reductions from some of our power plants, which would necessitate significant expenditures on emission controls or have other impacts on operations. These rulemakings are likely to be finalized in early 2005. Until the final regulations are promulgated, we cannot predict whether the regulations will have a material adverse effect on our financial condition, cash flows and results of operations.

In addition to implementation of statutes already in existence, there are additional environmental requirements under strong consideration by the federal and various state legislatures. The Bush Administration has submitted Clean Air Act multi-emission reform legislation to Congress, which would promulgate a new emissions cap and trade program for NOx, SO2 and mercury emissions from power plants. This legislation would require overall reductions in these pollutants from national power plant emissions of approximately 50-75% phased in during the 2008 - 2016 timeframe, which is similar to the types of overall reductions likely to be required under the future EPA regulations discussed above. Other more stringent multi-emission reform legislation also has been proposed in Congress by some lawmakers. There are many political challenges to the passage of multi-emission reform legislation through Congress, and it is unclear whether any of this legislation ultimately will be enacted into law.

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

For example, the Commonwealth of Massachusetts has finalized regulations to further reduce NOx and SO2 emissions from certain power plants and to regulate carbon dioxide and mercury emissions for the first time. Mercury emission reductions will be required exclusively from coal fired facilities. These regulations, which become effective in the 2004-2008 timeframe, will apply to our oil fired Canal plant in the state, will increase our operating costs and will likely necessitate the installation of additional emission control technology.

Another example is in the San Francisco Bay Area, where we own power plants. NOx emission standards have become increasingly stringent on a specified schedule over a several year period, culminating in 2005. We will continue to apply our NOx implementation plan for these plants, which includes the installation of emission controls as well as the gradual curtailment and phasing out of one or more of our higher NOx emitting units.

Additionally, in 2003, the State of New York finalized air regulations that significantly reduced allowances for NOx and SO2 emissions from power plants through a state emissions cap and allowance-trading program, which will become effective during the 2004-2008 timeframe. This regulation will necessitate that we act on one, or a combination of the following options: install emission controls at some of our units to reduce emissions, purchase additional state NOx and SO2 allowances under the regulatory program or reduce the number of hours that units operate. We expect to incur additional compliance costs as a result of these additional state requirements, which could include significant expenditures on emission controls or have other impacts on operations.

These examples are illustrative but not a complete discussion of the additional federal and state air quality laws and regulations that we expect to become applicable to our plants and operations in the coming years. We will continue to evaluate these requirements and attempt to develop compliance plans that enable us to appropriately manage the costs and impacts.

Other Environmental Regulations: There are other environmental laws in the United States, in addition to air quality laws, that also affect our operations. We are required under the Clean Water Act to comply with effluent and intake requirements, technological controls and operating practices. Our wastewater discharges are permitted under the Clean Water Act, and our permits under the Clean Water Act are subject to review every five years. As with air quality regulations, federal and state water regulations are expected to increase and impose additional and more stringent requirements or limitations in the future. For example, in 2004, the EPA issued a new rule that imposes more stringent standards on the cooling water intakes for power plants. We expect to incur additional compliance costs to comply with this new rule.

Our facilities also are subject to several waste management laws and regulations in the United States. The Resource Conservation and Recycling Act sets forth very comprehensive requirements for handling of solid and hazardous wastes. The generation of electricity produces non-hazardous and hazardous materials, and we incur substantial costs to store and dispose of waste materials from our facilities. The EPA may develop new regulations that impose additional requirements on facilities that store or dispose of fossil fuel combustion materials, including types of coal ash. If so, we may be required to change the current waste management practices at some facilities and incur additional costs for increased waste management requirements.

Additionally, the Federal Comprehensive Environmental Response, Compensation and Liability Act, known as the Superfund, establishes a framework for dealing with the cleanup of contaminated sites. Many states have enacted state superfund statutes. Some of the landfills that are used for the disposal of ash may be subject to these regulations.

Current Enforcement Issues: In 1999, the DOJ on behalf of the EPA commenced enforcement actions against the power generation industry for alleged violations of the new source review regulations promulgated under the Clean Air Act (“NSR”), which require permitting and other requirements for maintenance, repairs and replacement work on plants. This action ultimately came to encompass the vast

majority of coal fired plants, with litigation against many of the largest utilities. These enforcement actions concern maintenance, repair and replacement work (“MRR work”) at power plants that the EPA alleges violated permitting and other requirements under the NSR law, which, among other things, could require the installation of emission controls at a significant cost. As a general proposition, the power generation industry disagrees with the EPA’s positions in the lawsuits and contends that this work was “routine” and exempt from the permit requirement. In 2003, there were two trial court decisions that most directly addressed the issue of whether certain MRR work triggers permitting and other NSR requirements, and the courts are split on the issue.

To date, no lawsuits or administrative actions alleging similar NSR violations have been brought by the EPA against us or our power plants. However, in 2001 the EPA requested information concerning some of our Mid-Atlantic plants covering a time period that predates our ownership and leases.

In addition, there were two regulatory developments concerning NSR in 2003 that will affect the EPA’s application of NSR in the future and, potentially, the NSR enforcement actions. In a new NSR rule, the EPA promulgated an exemption from NSR for MRR work that does not exceed 20% of the replacement value of a unit, which is generally consistent with power plant MRR work practices. In the rulemaking, the EPA also announced a policy of interpreting NSR in a way that seems generally consistent with reasonable industry practices. The new rule is being challenged in federal court and has been stayed pending judicial review, and, most recently, the EPA has announced that it is reconsidering the rule. It is unclear whether this rule will be changed or what effect these developments will have on the EPA’s NSR enforcement action.

In 2000, the State of New York issued a notice of violation (“NOV”) to the previous owner of our Lovett facility alleging NSR violations associated with the operation of that plant prior to its acquisition by us. On June 11, 2003, we and the State of New York entered into a consent decree that releases us from all potential liability for matters addressed in the NOV previously issued by the State to the prior owner. The consent decree also releases us for any other potential violation of NSR or related New York air laws prior to and through the date of entry of the consent decree by the court.

Under the decree we committed to install comprehensive emissions reduction technology on Lovett’s two coal-fired units by 2007 to 2008. The consent decree also allows us to shut down or convert one of the units to burning natural gas only rather than install the prescribed emission controls on the unit.

We cannot provide assurance that lawsuits or other administrative actions against the power plants under NSR will not be filed or taken in the future. If an action is filed against us or our power plants and we are judged to not be in compliance, we could be required to make substantial expenditures to bring the power plants into compliance, which could have a material adverse effect on our financial condition, results of operations or cash flows.

International

Some of our international operations are subject to comprehensive environmental regulations similar to those in the United States, and these regulations are expected to become more stringent in the future. Additionally, other countries in which our subsidiaries have operations, such as Trinidad and Jamaica, are developing increased environmental regulation of many industrial activities, including increased regulation of air quality, water quality and solid waste management.

Over the past several years, federal, state and foreign governments and international organizations have debated the issue of global climate change and policies regarding the regulation of greenhouse gases (“GHGs”), one of which is carbon dioxide emitted from the combustion of fossil fuels by sources such as vehicles and power plants. Recently, the European Union and certain developed countries ratified the Kyoto Protocol, an international treaty regulating GHGs, and it became effective on February 16, 2005. The current U.S. administration is opposed to the treaty, and the United States has not ratified, and is not expected to ratify, the treaty. Therefore, the treaty does not bind the United States. None of the countries

in which we or our subsidiaries presently own or operate power plants has any binding obligations under the treaty. The Commonwealth of Massachusetts has promulgated carbon dioxide (“CO2”) emission standards for certain power plants, as discussed above in this section. We cannot provide assurances that such laws or regulations will not be enacted in the future in a state or country in which we own or operate power plants, and in such event the impact on our business would be uncertain but could be material.

Employees

At December 31, 2004, our corporate offices and majority owned or controlled subsidiaries employed approximately 4,700 persons. This number includes approximately 550 employees in the corporate and North America headquarters in Atlanta, approximately 1,350 employees at operating facilities in the United States and approximately 2,800 international employees. Approximately 900 of our domestic employees are subject to collective bargaining agreements with one of the following unions: International Brotherhood of Electrical Workers, Utilities Workers of America or United Steel Workers.

Union	Location	Number of Employees Covered	Contract Expiration Date
International Brotherhood of Electrical Workers Local 1900	Maryland and Virginia	515	6/1/2010
International Brotherhood of Electrical Workers Local 503	New York	150	6/1/2008
International Brotherhood of Electrical Workers Local 1245	California	140	10/31/2005
Utility Workers of America Local 369	Cambridge, Massachusetts	30	2/28/2009
Utility Workers of America Local 480	Sandwich, Massachusetts	50	5/1/2006
United Steel Workers Local 12502	Indiana and Michigan	25	1/1/2007
Oilfield Workers’ Trade Union	Trinidad	325	12/31/2005
The Senior Staff Association	Trinidad	35	2/28/2006
Bahamas Industrial Engineers, Managerial, and Supervisory Union(1)	Grand Bahama	33	1/1/2005
Commonwealth Electrical Workers Union(2)	Grand Bahama	131	3/31/2005
Jamaica Public Service Managers’ Association(3)	Jamaica	190	11/30/2004
Union of Clerical Administrative & Supervisory Employees; National Workers Union; Bustamante Industrial Trade Union(3)	Jamaica	1,130	12/31/2004

(1) Neither side has submitted a contract proposal yet. This is not uncommon and there is no work stoppage expected.

(2) Management is currently communicating with the union to agree on a start date for negotiations. Overall, the industrial climate is stable.

(3) All unions in Jamaica were requested in writing to submit claims (proposals) prior to the expiration of the contracts. To date, only the UCASE union has submitted a claim that is being reviewed. Negotiations have not begun, as management would prefer to receive all claims prior to initiation of talks. Overall, the industrial climate is stable.

To mitigate and reduce the risk of disruption during labor negotiations, we engage in contingency planning for continuation of our generation and/or distribution activities to the extent possible during an adverse collective action by one or more of our unions. Additionally, if our non-unionized workforce moved toward unionization, we could be materially impacted through increased employee costs, work stoppages or both.

Item 2. Properties

The following properties were owned or leased as of December 31, 2004:

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)
NORTH AMERICA
West Region:
Mirant California	California	Peaking/Intermediate	Natural Gas		100		2,347		2,347
Mirant Texas	Texas	Peaking/Baseload	Natural Gas		100		538		538
Apex	Nevada	Intermediate	Natural Gas		100		500		500
Coyote Springs(3)(4)	Oregon	Intermediate	Natural Gas/Steam		50		280		140
Mirant Wichita Falls	Texas	Peaking	Natural Gas		100		77		77
Subtotal							3,742		3,602
Northeast Region:
Mirant New England(5)	Massachusetts	Intermediate/Peaking	Natural Gas/Oil		100		1,993		1,388
Mirant New York	New York	Intermediate/Peaking/Baseload	Natural Gas/Hydro/Coal/Oil		100		1,675		1,675
Subtotal							3,668		3,063
Mid-Atlantic Region:
Mirant Mid-Atlantic	Maryland	Intermediate/Peaking/Baseload	NaturalGas/Coal/Oil		100		4,252		4,252
Mirant Peaker and Mirant Potomac River	Maryland/Virginia	Intermediate/Peaking/Baseload	NaturalGas/Coal/Oil		100		1,004		1,004
Subtotal							5,256		5,256
Mid-Continent Region:
Mirant Zeeland	Michigan	Peaking/Intermediate	Natural Gas		100		837		837
West Georgia(3)	Georgia	Peaking	Natural Gas/Oil		100		605		605
Sugar Creek	Indiana	Peaking	Natural Gas		100		535		535
Shady Hills(3)	Florida	Peaking	Natural Gas		100		468		468
Wrightsville(6)	Arkansas	Peaking/Intermediate	Natural Gas		51		438		223
Subtotal							2,883		2,668
North America Total							15,549		14,589
INTERNATIONAL
Philippines:
Sual(7)	Philippines	Baseload	Coal		94.9		1,218		1,155
Ilijan	Philippines	Baseload	Natural Gas		20		1,200		240
Pagbilao	Philippines	Baseload	Coal		95.7		735		704
Navotas II(8)	Philippines	Standby	Diesel		100		95		95
Sangi	Philippines	Baseload/Peaking/Standby	Coal/Oil		50		75		38
Panay	Philippines	Peaking/Intermediate/Baseload	Oil		50		71		35
Carmen	Philippines	Standby/Peaking	Heavy Fuel Oil		50		37		19
Avon River	Philippines	Peaking/Intermediate/Baseload	Oil		50		18		9
Mindoro	Philippines	Peaking/Intermediate/Baseload	Heavy Fuel Oil		50		6		3
Subtotal							3,455		2,298
Caribbean:
PowerGen	Trinidad & Tobago	Intermediate/Peaking/Baseload	Natural Gas		39		1,157		451
JPS	Jamaica	Intermediate/Baseload/Peaking	Oil/Hydro		80		600		480
Grand Bahama Power	Bahamas	Peaking/Intermediate/Baseload	Oil		55.4		133		74
CUC	Netherlands Antilles	Baseload/Peaking	Pitch/Refinery Gas		25.5		133		34
Subtotal							2,023		1,039
International Total							5,478		3,337
Total							21,027		17,926

Distribution Business	Location	Mirant’s % Ownership Interest			Customers/ end-users
					(in thousands)
Grand Bahama Power	Bahamas		55.4	%		18
JPS	Jamaica		80.0			540
Visayan Electric Company Inc	Philippines		1.95			273
Total						831

Other 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)

Bowline expansion(9)

New York

Intermediate

Natural Gas

100

750

Contra Costa expansion(9)

California

Intermediate

Natural Gas

100

580

Wyandotte(9)

Michigan

Intermediate

Natural Gas

100

560

Longview Mint Farm(9)

Washington

Intermediate

Natural Gas

100

298

Bahamas(10)

Grand Bahamas

Baseload

Diesel

55.4

Nabas(11)

Philippines

Baseload

Oil

50.0

New Washington(11)

Philippines

Baseload

Oil

50.0

(1) Amounts reflect Mirant’s percentage economic interest in the total MW.

(2) MW amounts reflect net dependable capacity.

(3) Generating plant is operated by an independent third party

(4) In October 2004, Mirant Oregon LLC (“Mirant Oregon”), our wholly-owned subsidiary, entered into an agreement to sell its 50% undivided interest in Coyote Springs 2 to Avista Energy, subject to Bankruptcy Court and regulatory approval. Mirant completed the sale in January 2005.

(5) Total MW reflects a 1.4% ownership interest, or 8.8 MW, in the 614 MW Wyman plant.

(6) Mirant temporarily shutdown this facility in January 2004. In February 2005, we entered into an agreement to sell the Wrightsville facility to AECC, subject to Bankruptcy Court approval and certain other regulatory and third-party consents and approvals. We expect the sale of the Wrightsville facility to close in 2005.

(7) Mirant acquired an additional 2.94% ownership interest in the Sual project in the first quarter of 2004, bringing its ownership interest to 94.9%.

(8) The Build-Operate-Transfer (“BOT”) agreement related to Navotas II is scheduled to expire in July 2005.

(9) Mirant does not expect to independently complete these construction projects and will either pursue partnerships to complete, sell or abandon these projects. Abandon as used in this document means ceasing to operate the affected generation asset.

(10) The Bahamas facility is scheduled to be operational in 2005.

(11) The Nabas and New Washington facilities are scheduled to be in operation by mid 2005.

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

Item 3. Legal Proceedings

As debtors-in-possession, the Mirant Debtors are authorized under Chapter 11 to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court. As of the Petition Date, most pending litigation (including some of the actions described below) is stayed, and absent further order of the Bankruptcy Court, no party, subject to certain exceptions, may take any action, again subject to certain exceptions, to recover on pre-petition claims against the Mirant Debtors. One exception to this stay of litigation is for an action or proceeding by a governmental agency to enforce its police or regulatory power. The claims asserted in litigation and proceedings to which the stay applies may be fully and finally resolved in connection with the administration of the bankruptcy proceedings and, to the extent not resolved, will need to be addressed in the Plan. On November 19, 2003, the Bankruptcy Court entered an order staying most litigation pending against current or former officers, directors and managers of the Mirant Debtors arising out of the performance of their duties and against certain potential indemnitees of the Mirant Debtors. The Bankruptcy Court took that action to avoid the risk that the continuation of such litigation would impede the Mirant Debtors’ ability to reorganize or would have a negative impact upon the assets of the Mirant Debtors. At this time, it is not possible to predict the outcome of the Chapter 11 filings or their effect on the business of the Mirant Debtors or outstanding legal proceedings. The Mirant Debtors intend to resolve as many of these claims as possible through the claims resolution process in the bankruptcy proceeding or the Plan.

California Litigation by Governmental Units and Certain Other Parties

General. The high prices for wholesale electricity and natural gas experienced in the western markets during 2000 and 2001 prompted several governmental entities to investigate the western power markets, including activities by Mirant, Mirant Americas Energy Marketing and several of Mirant Americas Generation’s wholly-owned subsidiaries. These governmental entities include the FERC, the DOJ, CPUC, the California Senate, the California State Auditor, California’s Electricity Oversight Board (the “EOB”), the General Accounting Office of the United States Congress, the San Joaquin District Attorney and the Attorney General’s offices of the States of Washington, Oregon and California. These investigations, some of which are civil and some criminal, resulted in the issuance of civil investigative demands, subpoenas, document requests, requests for admission and interrogatories directed to several Mirant entities.

General FERC Investigation. On February 13, 2002, the FERC directed its staff to undertake a fact-finding investigation into whether any entity manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000 and forward. On March 26, 2003, the FERC staff issued its final report regarding its investigation. Although the staff reaffirmed the FERC’s conclusion set forth in an order issued December 15, 2000 that significant supply shortfalls and a fatally flawed market design were the root causes of the problems that occurred in the California wholesale electricity market in 2000 and 2001, the staff also found that significant market manipulation had occurred in both the gas and electricity markets. The staff concluded that trading strategies of the type engaged in by Enron Corporation and its affiliates (“Enron”) as described in certain Enron memos released by the FERC in May 2002 violated provisions of the CAISO and the California Power Exchange Corporation (“Cal PX”) tariffs that prohibited gaming. It identified Mirant, without being specific as to the particular Mirant entities involved, as being one of a number of entities that had engaged in one or more of those practices. The FERC staff also found that bidding generation resources to the Cal PX and CAISO at prices unrelated to costs constituted economic withholding and violated the antigaming provisions of the CAISO and Cal PX tariffs. Mirant was one of the entities identified as engaging in that bidding practice, with the FERC staff again not being specific as to the Mirant entities involved.

On March 26, 2003, the FERC staff issued a separate report addressing allegations of physical withholding by Mirant and four other out of state owners of generation assets in California made by the CPUC in reports issued in September 2002 and January 2003. The CPUC asserted that on days in the fall of 2000 through the spring of 2001 during which the CAISO had to declare a system emergency requiring interruption of interruptible load or imposition of rolling blackouts, Mirant and four other out of state owners of generation assets in California had generating capacity that either was not operated or was out of service due to an outage and that could have avoided the problem if operated. The CPUC reports identified the Mirant entity discussed in the reports as Mirant Americas Energy Marketing, although Mirant’s generating facilities in California are owned by subsidiaries of Mirant Americas Generation. The FERC staff concluded that the CPUC’s contention that thirty-eight service interruptions could have been avoided had those five generators produced all of their available power was not supported by the evidence. The staff also indicated, however, that the FERC was continuing to investigate whether withholding by generators had occurred during 2000 and 2001.

As discussed below under “California Settlement,” on January 14, 2005, Mirant and certain of its subsidiaries entered into a Settlement and Release of Claims Agreement (the “California Settlement”) with Pacific Gas and Electric Company (“PG&E”), Southern California Edison Company (“SCE”), San Diego Gas and Electric Company, the CPUC, the California Department of Water Resources (“DWR”), the EOB and the Attorney General of the State of California (collectively, the “California Parties”) and with the Office of Market Oversight and Investigations of the FERC. If the California Settlement becomes effective, it will result in the termination of the FERC’s investigation of potential withholding by generators (the “FERC Withholding Investigation”) as to Mirant and its subsidiaries.

FERC Bidding Investigation. On June 25, 2003, the FERC issued an order (the “Bidding Order”) initiating an investigation by its staff into bidding practices in the Cal PX and CAISO markets between May 1, 2000 and October 1, 2000 of more than 50 parties, including Mirant Americas Energy Marketing. The entities subject to investigation under the Bidding Order were previously identified in the report issued by the FERC staff on March 26, 2003 as having bid generation resources to the Cal PX and CAISO at prices unrelated to costs. The Bidding Order requires those entities, including Mirant Americas Energy Marketing, to demonstrate why bids in the Cal PX and CAISO markets from May 1, 2000 through October 1, 2000 that were in excess of $250 per MWh did not constitute a violation of the CAISO and Cal PX tariffs.

As discussed below under “California Settlement,” if the California Settlement becomes effective, it will result in the termination of the FERC’s investigation under the Bidding Order of Mirant Americas Energy Marketing’s bidding practices.

FERC Show Cause Proceeding Relating to Trading Practices. On June 25, 2003, the FERC issued a show cause order (the “Trading Practices Order”) to more than 50 parties, including Mirant Americas Energy Marketing and subsidiaries of Mirant Americas Generation, that the FERC staff report issued on March 26, 2003 identified as having potentially engaged in one or more trading strategies of the type employed by Enron, as described in the Enron memos released by the FERC in May 2002. The Trading Practices Order identified certain specific trading practices that the FERC indicated could constitute gaming or anomalous market behavior in violation of the CAISO and Cal PX tariffs. The Trading Practices Order requires the CAISO to identify transactions between January 1, 2000 and June 20, 2001 that may involve the identified trading strategies, and then requires the applicable sellers involved in those transactions to demonstrate why such transactions were not violations of the CAISO and Cal PX Tariffs. On September 30, 2003, the Mirant entities filed with the FERC for approval of a settlement agreement (the “Trading Settlement Agreement”) entered into between certain Mirant entities and the FERC Trial Staff, under which Mirant Americas Energy Marketing would pay $332,411 to settle the trading practices proceeding, but did not admit any wrongdoing.

In a November 14, 2003 order in a different proceeding, the FERC ruled that certain allegations of improper trading conduct with respect to the selling of ancillary services during 2000 also should be resolved in the show cause proceeding. On December 19, 2003, the Mirant entities filed with the FERC for approval of an amendment to the Trading Settlement Agreement reached with the FERC Trial Staff with respect to the sale of ancillary services. Under the proposed amendment, the FERC would have an allowed unsecured claim in Mirant Americas Energy Marketing’s bankruptcy proceeding for $3.67 million in settlement of the allegations with respect to the sale of ancillary services (the “Ancillary Amount”).

The Trading Settlement Agreement and its amendment must be approved by the FERC and the Bankruptcy Court to become effective. The Mirant entities are in the process of obtaining FERC approval and will seek approval from the Bankruptcy Court thereafter. On March 11, 2004, a FERC administrative law judge (the “ALJ”) recommended that the FERC approve the Trading Settlement Agreement, finding that the settlement amounts were reasonable. The ALJ, however, suggested that approval of the settlement be conditioned on the Ancillary Amount being treated as an administrative claim or a setoff rather than as an allowed pre-petition claim. If the Ancillary Amount were to be treated as an administrative claim, that amount would receive priority status in the payment of claims against Mirant Americas Energy Marketing in the bankruptcy proceedings.

As discussed below under “California Settlement,” if the California Settlement becomes effective, it will result in the California Parties withdrawing their opposition to the Trading Settlement Agreement as amended and supporting approval of the Trading Settlement Agreement as proposed by Mirant and the FERC Trial Staff without change or modification.

California Receivables. In 2001, SCE and PG&E suspended payments to the Cal PX and the CAISO for certain power purchases, including purchases from Mirant Americas Energy Marketing. Both the Cal PX and PG&E filed for bankruptcy protection in 2001. As discussed below under “California Settlement,” if the California Settlement becomes effective, it will result in Mirant Americas Energy Marketing assigning to the California Parties its outstanding receivables for sales made in the Cal PX and CAISO markets from January 1, 2000 through June 20, 2001.

FERC Refund Proceedings. As a result of the increase in electricity prices in 2000 and 2001, the California Parties have pursued litigation at the FERC, claiming that the prices charged by Mirant Americas Energy Marketing and other market participants in the California energy markets during certain periods in 2000 and 2001 were excessive. In July 2001, the FERC issued an order requiring proceedings (the “FERC Refund Proceedings”) to determine the amount of any refunds and amounts owed for sales made to the CAISO or the Cal PX from October 2, 2000 through June 20, 2001 (the “Refund Period”). Various parties have appealed these FERC orders to the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) seeking review of a number of issues, including changing the Refund Period to include periods prior to October 2, 2000 and expanding the sales of electricity subject to potential refund to include bilateral sales made to the DWR. Any such expansion of the Refund Period or the types of sales of electricity potentially subject to refund could significantly increase the refund exposure of Mirant Americas Energy Marketing in this proceeding. Although Mirant Americas Energy Marketing is the Mirant entity that engaged in transactions with the CAISO and the Cal PX, the orders issued by the FERC in the refund proceedings, and the filings made by other parties in those proceedings, generally refer to the Mirant entity involved as Mirant without being more specific. Mirant believes that the Mirant entity that would actually be liable to third parties for any refunds determined by the FERC to be owed, or that would be due any receivables found to be owed to Mirant, is Mirant Americas Energy Marketing. Agreements that were in effect at the time of the transactions at issue between Mirant Americas Energy Marketing and the Mirant Americas Generation subsidiaries that own Mirant’s generating facilities in California would shift some of the economic burden of such refunds or the benefit of such receivables from Mirant Americas Energy Marketing to those Mirant Americas Generation subsidiaries.

On December 12, 2002, a FERC ALJ determined the preliminary amounts owed to and by each entity acting as a scheduling coordinator in the CAISO and Cal PX markets, including Mirant Americas Energy Marketing. Based on the ALJ’s determination, the initial amounts owed to Mirant Americas Energy Marketing totaled approximately $122 million, which is net of refunds owed by Mirant Americas Energy Marketing to the CAISO and the Cal PX. The ALJ decision indicated that these amounts did not reflect the final mitigated market clearing prices, interest that would be applied under the FERC’s regulations, offsets for emission costs or the effect of certain findings made by the ALJ in the initial decision. A December 2002 errata issued by the ALJ to his initial decision indicated that the amounts identified by the initial decision as being owed to Mirant Americas Energy Marketing and other participants in the Cal PX market failed to reflect an adjustment for January 2001 that the ALJ concluded elsewhere in his initial decision should be applied. If that adjustment is applied, the amount owed Mirant Americas Energy Marketing by the Cal PX, and the net amount owed Mirant Americas Energy Marketing by the CAISO and the Cal PX after taking into account the proposed refunds, would increase by approximately $37 million.

On March 26, 2003, the FERC largely adopted the findings the ALJ made in his December 12, 2002 order with the exception that the FERC concluded that the price of gas used in calculating the mitigated market prices used to determine refunds should not be based on published price indices. Instead, the FERC ruled that the price of gas should be based upon the price at the producing area plus transportation costs. This adjustment by the FERC to the refund methodology is expected to increase the refunds owed by Mirant Americas Energy Marketing and therefore to reduce the net amount that would remain owed to Mirant Americas Energy Marketing from the CAISO and Cal PX after taking into account any refunds. Based solely on the staff’s formula, the amount of the reduction could be as much as approximately $110 million, which would reduce the net amount owed to Mirant Americas Energy Marketing by the CAISO and Cal PX to approximately $49 million. The FERC indicated that it would allow any generator that could demonstrate it actually paid a higher price for gas to recover the differential between that higher price and the proxy price for gas adopted by the FERC. Mirant Americas Energy Marketing has filed information with the FERC indicating that its actual cost of gas used to make spot sales of electricity was higher than the amounts calculated under the staff’s formula, which, if accepted, would decrease significantly the $110 million and increase the resulting net amount owed to Mirant Americas Energy Marketing, although the amount of such potential decrease that will be accepted by the FERC and the resulting net amount owed to Mirant Americas Energy Marketing cannot at this time be determined. On October 16, 2003, the FERC issued an order addressing motions for rehearing filed with respect to its March 26, 2003 order, and in that October 16, 2003 order the FERC changed how certain power sales made to the CAISO were to be treated. Mirant Americas Energy Marketing estimates that the effect of the October 16, 2003 order will be to decrease the refunds owed by Mirant Americas Energy Marketing, and therefore to increase the net amounts owed to Mirant Americas Energy Marketing, by $27 million. On May 12, 2004, the FERC issued an order on rehearing of the October 16, 2003 order that further modified how certain power sales made to the CAISO are to be treated and that may reduce significantly the potential benefit to Mirant Americas Energy Marketing of the October 16, 2003 order. In another order issued May 12, 2004, the FERC also further refined the methodology to be used to determine the costs of gas that a generator can recover where it can demonstrate that it paid a higher price for gas than the proxy price for gas previously adopted by the FERC in its March 23, 2003 order, and those changes may have the effect of reducing the costs that Mirant Americas Energy Marketing is able to recover. Mirant Americas Energy Marketing sought rehearing of the May 12, 2004 order, but the FERC denied that request for rehearing on September 24, 2004. Mirant Americas Energy Marketing is unable at this time to quantify further the impact of the May 12, 2004 orders.

The amount owed to Mirant Americas Energy Marketing from sales made to either the CAISO or the Cal PX, the amount of any refund that Mirant Americas Energy Marketing might be determined to owe the CAISO or the Cal PX, and whether Mirant Americas Energy Marketing may have any refund obligation to the DWR may be affected materially by the ultimate resolution of the issues described above related to which gas indices should be used in calculating the mitigated market clearing prices, allegations of market manipulation, whether the Refund Period should include periods prior to October 2, 2000, and whether the sales of electricity potentially subject to refund should include sales made to the DWR. In addition, in the Chapter 11 proceedings the Mirant Debtors initiated adversary actions against PG&E, SCE, the CAISO, the Cal PX, and the DWR seeking a determination that the Bankruptcy Code prohibits the offsetting of any refunds that Mirant Americas Energy Marketing is found to owe by the FERC in the FERC Refund Proceedings against amounts owed to Mirant Americas Energy Marketing for sales made into the CAISO and Cal PX markets.

In the July 25, 2001 order, the FERC also ordered that a preliminary evidentiary proceeding be held to develop a factual record on whether there had been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest from December 25, 2000 through June 20, 2001. In the proceeding, the California Attorney General, the CPUC and the EOB filed to recover certain refunds from parties, including Mirant Americas Energy Marketing, for bilateral sales of electricity to the DWR at the California/Oregon border, claiming that such sales took place in the Pacific Northwest. The refunds sought from Mirant Americas Energy Marketing totaled approximately $90 million. If Mirant Americas Energy Marketing were required to refund such amounts, subsidiaries of Mirant Americas Generation could be required under inter-company agreements with Mirant Americas Energy Marketing to refund amounts previously received from Mirant Americas Energy Marketing pursuant to sales made on their behalf during the refund period. In addition, those Mirant Americas Generation subsidiaries would be owed amounts for refunds received by Mirant Americas Energy Marketing related to purchases made on their behalf by Mirant Americas Energy Marketing from other sellers in the Pacific Northwest. In an order issued June 25, 2003, the FERC ruled that no refunds were owed and terminated the proceeding. On November 10, 2003, the FERC denied requests for rehearing filed by various parties. Various parties have appealed the FERC’s decision to the Ninth Circuit.

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

As discussed below under “California Settlement,” the California Settlement, once effective, will result in the release of most of Mirant Americas Energy Marketing’s potential liability in the FERC Refund Proceedings and the other FERC proceedings described in this section. Under the California Settlement, the California Parties will release Mirant and its subsidiaries from any liability to the California Parties related to sales of electricity and natural gas in the western markets from January 1, 1998 through July 14, 2003, including any claims for refunds in the FERC Refund Proceedings or in any proceedings conducted by FERC as a result of the Ninth Circuit’s ruling with respect to the complaint filed by the California Attorney General. Also, the California Parties will assume the obligation of Mirant Americas Energy Marketing to pay any refunds determined by the FERC to be owed by Mirant Americas Energy Marketing to other parties for transactions in the CAISO and Cal PX markets during the Refund Period. Some of the consideration to be received by the California Parties under the settlement will be available to

other market participants that choose to opt into the settlement. Any market participant that elects to opt into the settlement will give releases of liability to Mirant Americas Energy Marketing that are the same as those given by the California Parties. Subject to applicable bankruptcy law, however, Mirant Americas Energy Marketing will continue to be liable for any refunds that FERC determines it to owe (1) to participants in the Cal PX and CAISO markets that are not California Parties (or that do not elect to opt into the settlement) for periods outside of the Refund Period and (2) to participants in bilateral transactions with Mirant Americas Energy Marketing that are not California Parties (or that do not elect to opt into the settlement).

DWR Power Purchases Proceeding. On May 22, 2001, Mirant Americas Energy Marketing entered into a 19-month agreement with the DWR to provide the State of California with approximately 500 MW of electricity during peak hours through December 31, 2002 (the “DWR Contract”). On February 25, 2002, the CPUC and the EOB filed separate complaints at the FERC against Mirant Americas Energy Marketing and other sellers of electricity under long term agreements with the DWR, alleging that the terms of these contracts were unjust and unreasonable and that the contracts should be abrogated or the prices under the contracts should be reduced. The complaints allege that the prices the DWR was forced to pay pursuant to these long-term contracts were unreasonable due to dysfunctions in the California market and the alleged market power of the sellers. Under inter-company agreements, subsidiaries of Mirant Americas Generation bear the risk of any abrogation of or revision to the terms of the May 22, 2001 contract between Mirant Americas Energy Marketing and the DWR. On June 26, 2003, the FERC issued an order dismissing the complaints filed by the CPUC and the EOB against Mirant Americas Energy Marketing. On November 10, 2003, the FERC denied motions for rehearing filed by the CPUC and the EOB. The CPUC and EOB have appealed the FERC’s decision to the Ninth Circuit.

As discussed below under “California Settlement,” if the California Settlement becomes effective, it will result in the release of Mirant Americas Energy Marketing by the DWR and the other California Parties of any liability with respect to the DWR Contract and the dismissal by the CPUC and the EOB of their appeal of the FERC’s decision dismissing their complaints.

Reliability Must Run Agreements Proceeding. Certain of the generating facilities acquired by subsidiaries of Mirant Americas Generation from PG&E are operated subject to reliability-must-run agreements (“RMR Agreements”), which those subsidiaries assumed from PG&E. These agreements allow the CAISO to require the Mirant Americas Generation subsidiaries, under certain conditions, to operate these facilities to support the California electric transmission system. The rates that the Mirant Americas Generation subsidiaries could charge the CAISO under those agreements, where they were also making sales into the market and were retaining the revenues from those sales, were the subject of an ongoing disputed rate proceeding before the FERC at the time of the acquisition of the plants from PG&E and were being collected subject to refund. For the plants that are subject to the RMR Agreements and from which the Mirant Americas Generation subsidiaries have exercised their rights to also make market sales, the Mirant Americas Generation subsidiaries have been collecting from the CAISO since April 1999 an amount equal to 50% of the annual fixed revenue requirement (the “Annual Requirement”) of those plants. The amounts the Mirant Americas Generation subsidiaries collect from the CAISO are subject to refund pending final review and approval by the FERC. While the CAISO is the party to the RMR Agreements with the Mirant Americas Generation subsidiaries, the CAISO’s obligations under those agreements are funded by PG&E and PG&E is the real party in interest with respect to any refunds owed by the Mirant Americas Generation subsidiaries for sales made previously under those agreements. In June 2000, the ALJ issued a decision finding that the amount the Mirant Americas Generation subsidiaries should be allowed to charge the CAISO for such plants was approximately 3½% on average of the Annual Requirement. In July 2000, the Mirant Americas Generation subsidiaries sought review by the FERC of the ALJ decision, and a decision is pending at the FERC.

The Mirant Americas Generation subsidiaries recognize revenue related to these agreements based on the rates ruled to be reasonable by the ALJ. If the Mirant Americas Generation subsidiaries are unsuccessful in seeking modification of the ALJ’s decision by the FERC, they will be required to refund amounts collected in excess of those rates for the period from June 1, 1999. For the Potrero plant and Pittsburg Units 1 through 4 the period for which such refunds would be owed would run through December 31, 2001, for Mirant America Generation’s other California plants except Pittsburg Unit 5 the refund period would run through December 31, 2002, and for Pittsburg Unit 5 the refund period would run through December 31, 2003. Amounts collected in excess of those rates and other significantly smaller amounts collected under the RMR Agreements that are also subject to refund due to other issues pending at the FERC totaled $293 million, of which $288 million is included in liabilities subject to compromise and $5 million is deferred and included in revenues subject to refund as of December 31, 2004 and December 31, 2003. In addition, Mirant Americas Generation records accrued interest on such amounts, which amounted to $42 million and is included in liabilities subject to compromise as of December 31, 2004 and December 31, 2003, respectively.

As discussed below under “California Settlement,” if the California Settlement becomes effective, it will result in PG&E releasing the Mirant Americas Generation subsidiaries from any potential refund liability under the RMR Agreements for the period prior to September 30, 2004 in return for certain consideration as described below. In addition, the CAISO has separately agreed with Mirant to release its claims for refunds with respect to the RMR Agreements for the period through September 30, 2004 upon the California Settlement becoming effective.

California Attorney General Litigation. On March 11, 2002, the California Attorney General filed a civil suit against Mirant, Mirant Americas, Inc., Mirant Americas Energy Marketing and several Mirant Americas Generation subsidiaries (the “Mirant Defendants”). The lawsuit alleges that, between 1998 and 2001, the Mirant Defendants effectively double-sold capacity by selling both ancillary services and energy from the same generating units in violation of the CAISO tariff and the California Unfair Competition Act. The suit seeks both restitution and penalties in unspecified amounts. The Mirant Defendants removed this suit from the state court in which it was originally filed to the United States District Court for the Northern District of California. The district court, on March 25, 2003, granted the Mirant Defendants’ motion seeking dismissal of this suit. The California Attorney General appealed that dismissal to the Ninth Circuit. On July 6, 2004, the Ninth Circuit affirmed the dismissal of the suit by the district court. On July 27, 2004, the California Attorney General filed a petition with the Ninth Circuit seeking rehearing of the July 6, 2004 decision, and the Ninth Circuit denied that request on October 29, 2004. On January 27, 2005, the California Attorney General filed a petition for writ of certiorari with the United States Supreme Court seeking to appeal the Ninth Circuit’s decision.

On March 20, 2002, the California Attorney General filed a complaint with the FERC against certain power marketers and their affiliates, including Mirant Americas Energy Marketing and subsidiaries of Mirant Americas Generation, alleging that market based sales of energy made by such generators to the CAISO and the Cal PX and in bilateral transactions with the DWR were in violation of the Federal Power Act in part because such transactions were not filed appropriately with the FERC. The complaint requests, among other things, refunds for any prior short-term sales of energy that are found not to be just and reasonable along with interest on any such refunded amounts. The FERC dismissed the California Attorney General’s complaint and denied the California Attorney General’s request for rehearing. On September 9, 2004, the Ninth Circuit reversed the FERC’s dismissal of the California Attorney General’s complaint and remanded the case back to the FERC for further proceedings. The Ninth Circuit found that while the FERC has the authority to allow market based rates, the alleged failure of certain entities selling electric energy at market-based rates, including the Mirant parties, to comply with reporting regulations established by the FERC for entities with authority to sell at market-based rates was more than a technical compliance issue as the FERC had found. Mirant Americas Energy Marketing and other parties have filed

a petition with the Ninth Circuit seeking rehearing of the September 9, 2004 ruling. This ruling could result in the expansion of the Refund Period to include dates from January 1, 2000 through June 20, 2001, and could result in refunds being ordered for transactions outside the CAISO and Cal PX markets.

On April 9, 2002, the California Attorney General filed a second civil suit against the Mirant Defendants. That lawsuit alleges that the Mirant Defendants violated the California Unfair Competition Act by failing to properly file their rates, prices, and charges with the FERC as required by the Federal Power Act, and by charging unjust and unreasonable prices in violation of the Federal Power Act. The complaint seeks unspecified penalties, costs and attorney fees. The Mirant Defendants removed this suit from the state court in which it was originally filed to the United States District Court for the Northern District of California. The district court, on March 25, 2003, granted the Mirant Defendant’s motion seeking dismissal of this suit. On October 12, 2004, the Ninth Circuit affirmed the district court’s dismissal of the suit.

On April 15, 2002, the California Attorney General filed a third civil lawsuit against the Mirant Defendants in the United States District Court for the Northern District of California. The lawsuit alleges that the acquisition and possession of the Potrero and Delta power plants by subsidiaries of Mirant Americas Generation has substantially lessened, and will continue to substantially lessen, competition in violation of the Clayton Act of 1914, as amended (the “Clayton Act”) and the California Unfair Competition Act. The lawsuit seeks equitable remedies in the form of divestiture of the plants and injunctive relief, as well as monetary damages in unspecified amounts to include disgorgement of profits, restitution, treble damages, statutory civil penalties and attorney fees. On March 25, 2003, the court dismissed the California Attorney General’s state law claims and his claim for damages under the Clayton Act, but did not dismiss the California Attorney General’s claims for divestiture. On December 3, 2003, the district court stayed the suit during the pendency of the Company’s bankruptcy proceedings. The California Attorney General appealed that ruling to the Ninth Circuit, and on February 10, 2005, the Ninth Circuit vacated the stay and remanded the proceeding to the district court.

On August 18, 2004, the California Attorney General filed a fourth civil suit in the Superior Court of California, San Francisco County, against the Mirant Defendants. The suit asserts claims under the California Unfair Competition Act and the California Commodity Law of 1990. The California Attorney General alleges that beginning in 1999 and continuing through 2001, the Mirant Defendants engaged in manipulative and fraudulent schemes in the California wholesale electricity markets, including allegedly obtaining congestion relief payments for actions that did not relieve any congestion, receiving payment for excessive generation through the submission of false schedules, circumventing price caps by falsely representing the source of energy, receiving payment for ancillary services they did not and could not provide, and falsely reporting generating units as unavailable to produce electricity when they were available. The suit seeks damages, restitution, disgorgement of profits, civil penalties and injunctive relief. The Mirant Defendants have removed the suit to the United States District Court for the Northern District of California and have filed a motion seeking dismissal of the claims asserted on the grounds that they are barred by the doctrine of preemption and the filed rate doctrine.

As discussed below under “California Settlement,” if the California Settlement becomes effective, the California Attorney General will dismiss with prejudice the four civil suits described above and will release all claims against Mirant entities asserted in the complaint filed with the FERC on March 20, 2002 described above.

California-Related Claims in the Bankruptcy Proceedings. Various entities have filed proofs of claim in bankruptcy proceedings in undetermined amounts against Mirant, Mirant Americas Energy Marketing, Mirant Americas Generation and other Mirant subsidiaries on account of the various proceedings described above. Those entities include the California Attorney General, the DWR, the CPUC, PG&E, SCE, San Diego Gas & Electric Company, the Cal PX and the CAISO. In addition, the FERC has filed

proofs of claim concerning the FERC Refund Proceedings, the proceedings related to the RMR Agreements and the proceedings and investigations described above in “General FERC Investigation,” “FERC Bidding Investigation” and “FERC Show Cause Proceeding Related to Trading Practices.” Some of these claims also assert a right to set off the amount of any refunds owed by Mirant Americas Energy Marketing to the claimant against any amounts owed by such claimant to Mirant Americas Energy Marketing.

As discussed below under “California Settlement,” if the California Settlement becomes effective, it will result in the withdrawal with prejudice of the claims filed in the bankruptcy proceedings by the California Attorney General, the DWR, the CPUC, PG&E, SCE and San Diego Gas & Electric Company in return for the specific allowed claims and other consideration provided for in the California Settlement. Also, although the California Settlement will not result in the withdrawal of the claims filed by the CAISO or the Cal PX, under its terms the FERC’s approval of the settlement will constitute its direction to the CAISO and Cal PX to conform their books and records to the terms of the California Settlement and to withdraw with prejudice all claims filed by them in the bankruptcy proceedings that seek to recover amounts or otherwise obtain relief on behalf of or for the benefit of any of the California Parties. In addition, the CAISO has separately agreed with Mirant to release its claims upon the California Settlement becoming effective.

California Settlement. On January 14, 2005, Mirant and certain of its subsidiaries entered into the California Settlement with the California Parties and the Office of Market Oversight and Investigations of the FERC settling a variety of disputed matters described above. The Mirant entities that are parties to the California Settlement are Mirant, Mirant Americas Inc., Mirant Americas Energy Marketing, Mirant Americas Generation, Mirant California Investments, Inc., Mirant California, LLC, Mirant Delta, LLC, Mirant Potrero, LLC, Mirant Special Procurement, Inc., Mirant Services, LLC and Mirant Americas Development, Inc. (collectively, the “Mirant Settling Parties”). The California Parties are PG&E, Southern California Edison Company, San Diego Gas and Electric Company, the CPUC, the DWR, the EOB and the Attorney General of the State of California. The effectiveness of the California Settlement is conditioned upon its approval by the CPUC, the Bankruptcy Court, the bankruptcy court having jurisdiction over PG&E’s bankruptcy proceedings initiated in 2001, and the FERC. While CPUC has approved the California Settlement, as signified by its execution of the California Settlement, the other approvals have not yet been obtained.

If the California Settlement becomes effective, (1) Mirant Americas Energy Marketing and the other Mirant Settling Parties will assign to the California Parties all receivables owed to Mirant Americas Energy Marketing for transactions in the markets administered by the Cal PX or the CAISO for the period January 1, 2000 through June 20, 2001, which are currently estimated by the parties to the California Settlement to be approximately $283 million, and (2) the California Parties will receive an allowed, unsecured claim against Mirant Americas Energy Marketing in its Chapter 11 case for $175 million and the DWR will receive an additional allowed, unsecured claim against Mirant Americas Energy Marketing of $2.25 million. In return, the California Parties will release all claims they may have against the Mirant Settling Parties related to sales of electricity or natural gas at wholesale in western markets in the period from January 1, 1998 through July 14, 2003, including all such claims filed by the California Parties in the Mirant Debtors’ Chapter 11 cases, in proceedings currently pending before the FERC, or in the four pending suits filed by the California Attorney General. Mirant estimates that, excluding duplicative claims, this settlement will compromise the bulk of the California energy market claims at issue in the FERC Refund Proceedings. Also, the California Parties will assume Mirant Americas Energy Marketing’s obligation to pay any refunds determined by the FERC to be owed by Mirant Americas Energy Marketing to other parties for transactions in the CAISO and Cal PX markets during the Refund Period. Subject to applicable bankruptcy law, Mirant Americas Energy Marketing will continue to be liable for any refunds that the FERC determines it to owe to (1) participants in the Cal PX or CAISO markets other than the

California Parties for periods outside the Refund Period or (2) parties with which Mirant Americas Energy Marketing engaged in bilateral electricity or natural gas transactions other than the California Parties.

Some of the consideration to be received by the California Parties under the California Settlement will be available to other market participants that choose to opt into the California Settlement. Any market participant that elects to opt into the California Settlement will give releases of liability to the Mirant Settling Parties that are the same as those given by the California Parties. In addition to the claims filed by the California Parties seeking to recover refunds from Mirant Americas Energy Marketing and other Mirant entities for sales of electricity made by Mirant Americas Energy Marketing into the CAISO and Cal PX markets in 2000 and 2001, the CAISO and the Cal PX have filed claims against Mirant Americas Energy Marketing and other Mirant Settling Parties seeking to recover refunds on behalf of participants in the markets for which they were responsible. While the California Settlement will not result in the withdrawal of the claims filed in the Chapter 11 cases by the CAISO or the Cal PX, the FERC’s approval of the California Settlement (if obtained) will, upon the California Settlement becoming effective, constitute the FERC’s direction to the CAISO and the Cal PX to conform their books and records to the terms of the settlement and to withdraw with prejudice all claims filed by them in the Chapter 11 cases that seek to recover amounts or otherwise obtain relief on behalf of, or for the benefit of, any of the California Parties or any other market participants that opt into the California Settlement. In addition, the CAISO has separately agreed with Mirant to release its claims upon the California Settlement becoming effective. The California Parties also release the Mirant Settling Parties from any liability or refund claims related to the DWR Contract, including claims asserted in complaints filed by CPUC and EOB with the FERC in February 2002. The FERC’s approval of the California Settlement, under its terms, will also have the effect, once the California Settlement becomes effective, of terminating any pending investigations by the FERC of the conduct of the Mirant Settling Parties in the western energy markets in 2000 and 2001, including pending investigations pursuant to the Bidding Order or the FERC Withholding Investigation.

The California Settlement will also resolve all claims asserted by PG&E against Mirant Delta, Mirant Potrero, and the other Mirant Settling Parties in the Chapter 11 cases or in proceedings before the FERC that relate to refunds potentially owed as described under “Reliability-Must-Run Agreements Proceeding” above. Under the California Settlement, PG&E will release Mirant Delta and Mirant Potrero from any potential refund liability under the RMR Agreements for the period prior to September 30, 2004, and the claims filed by PG&E in the Chapter 11 cases seeking to recover refunds from Mirant Delta and Mirant Potrero for sales made under the RMR Agreements will be withdrawn with prejudice. Although the California Settlement will not result in the withdrawal of the claims filed in the Chapter 11 cases by the CAISO, under the terms of the California Settlement, the FERC’s approval of the California Settlement will constitute its direction to CAISO to conform its books and records to the terms of the California Settlement and to withdraw with prejudice all claims filed by it in the Chapter 11 cases that seek to recover amounts related to sales made under the RMR Agreements in the period prior to September 30, 2004. In addition, the CAISO has separately agreed with Mirant to release its claims upon the California Settlement becoming effective.

In return for the releases it grants to the Mirant Settling Parties described in the previous paragraph, PG&E will receive allowed, unsecured claims against Mirant Delta that will receive a distribution of proceeds of $63 million, and either (1) the partially constructed Contra Costa 8 project, which is a planned 530 MW combined cycle generating facility, and related equipment (collectively, the “CC8 Assets”) will be transferred to PG&E or (2) PG&E will receive additional alternative consideration in an amount of as much as $85 million (the “CC8 Alternative Consideration”). If the Mirant Settling Parties and PG&E are unable by April 30, 2005 to agree upon definitive agreements for the transfer of the CC8 Assets to PG&E, or if any approval of the Bankruptcy Court required for the transfer of the CC8 Assets to PG&E is not obtained, the CC8 Alternative Consideration is to be $85 million. Once such definitive agreements have been executed and any such required approval by the Bankruptcy Court of the transfer of the CC8 Assets has been obtained, the CC8 Alternative Consideration is reduced to $70 million.

To fund the CC8 Alternative Consideration, PG&E will receive an allowed, unsecured claim against Mirant Delta that will receive a distribution of either $85 million or $70 million depending on the maximum CC8 Alternative Consideration at the time of such distribution. PG&E will liquidate any securities received as part of such distribution and place the net resulting amount plus any cash received into an escrow account. To the extent that the net amount resulting from the liquidation of the securities received by PG&E plus any cash received by it is less than the CC8 Alternative Consideration, the difference will be made up by PG&E withholding and paying into the escrow account amounts it owes to Mirant Delta over a three month period under the power purchase agreement described below or by payments from Mirant Delta or Mirant Americas Generation. If the transfer of the CC8 Assets to PG&E does not occur on or before June 30, 2008, or if certain specified events occur prior to that date, such as the failure of the Mirant Settling Parties and PG&E to execute definitive agreements for the transfer of the CC8 Assets or the CPUC fails to approve PG&E’s acquisition of the CC8 Assets, then the CC8 Alternative Consideration is to be paid to PG&E and the Mirant Settling Parties will retain the CC8 Assets. If PG&E closes on its acquisition of the CC8 Assets, the funds in the escrow account will be paid to Mirant Delta.

PG&E also has entered into two power purchase agreements with Mirant Delta and Mirant Potrero that will allow PG&E to dispatch and purchase the power output of all units of the generating plants owned by those entities that have been designated by the CAISO as RMR units under the RMR Agreements. The first agreement is for 2005 and will be effective regardless of whether the California Settlement becomes effective. The second agreement will be for 2006 through 2012 and will become effective only if the California Settlement becomes effective. If the California Settlement has not become effective by January 1, 2006 and has not been terminated, the first power purchase agreement will be extended through December 31, 2006 and the second agreement will start January 1, 2007 if the settlement becomes effective.

Under the California Settlement, PG&E and Mirant Delta also are to negotiate by April 30, 2005 an agreement (the “Option Agreement”) under which PG&E would have separate options to purchase each of Mirant Delta’s existing Contra Costa generating plant and its existing Pittsburg generating plant, in both cases once no unit at the plant has operated for a certain period of years. The price at which each plant could be purchased pursuant to the option would be equal to the amount of certain capital costs not recovered by Mirant Delta under the terms of the RMR Agreement applicable to that plant at the time of the exercise of the option. If Mirant Delta and PG&E do not reach agreement on the Option Agreement by April 30, 2005, or if PG&E cannot obtain CPUC approval of the Option Agreement or its exercise of its rights thereunder, Mirant Delta and the other Mirant Settling Parties will have no further obligations to PG&E with respect to the Option Agreement or the rights it was to provide to PG&E.

Rate Payer Litigation

California Rate Payer Litigation. Various lawsuits are pending that assert claims under California law based on allegations that certain owners of electric generation facilities in California and energy marketers, including Mirant, Mirant Americas Energy Marketing and several Mirant Americas Generation subsidiaries, engaged in various unlawful and anti-competitive acts that served to manipulate wholesale power markets and inflate wholesale electricity prices in California.

Six such suits were filed between November 27, 2000 and May 2, 2001 in various California Superior Courts. Three of these suits seek class action status, while two of the suits are brought on behalf of all citizens of California. One lawsuit alleges that, as a result of the defendants’ conduct, customers paid approximately $4 billion more for electricity than they otherwise would have and seeks an award of treble damages as well as other injunctive and equitable relief. One lawsuit also names certain of Mirant’s officers individually as defendants and alleges that the state had to spend more than $6 billion purchasing

electricity. The other suits likewise seek treble damages and equitable relief. One such suit names Mirant itself as a defendant. A listing of these six cases is as follows:

Caption	Date Filed	Court of Original Filing
People of the State of California v.
Dynegy, et al.	January 18, 2001	Superior Court of California—San Francisco County
Gordon v. Reliant Energy, Inc., et al.	November 27, 2000	Superior Court of California—San Diego County
Hendricks v. Dynegy Power
Marketing, Inc., et al.	November 29, 2000	Superior Court of California—San Diego County
Sweetwater Authority, et al. v.
Dynegy, Inc., et al.	January 16, 2001	Superior Court of California—San Diego County
Pier 23 Restaurant v. PG&E Energy
Trading, et al.	January 24, 2001	Superior Court of California—San Francisco County
Bustamante, et al. v. Dynegy, Inc., et al.	May 2, 2001	Superior Court of California—Los Angeles County

These six suits (the “Six Coordinated Suits”) were coordinated for purposes of pretrial proceedings before the Superior Court for San Diego County. In the spring of 2002, two of the defendants filed crossclaims against other market participants who were not parties to the actions. Some of those crossclaim defendants then removed the Six Coordinated Suits to the United States District Court for the Southern District of California. The plaintiffs filed a motion seeking to have the actions remanded to the California state court, and the defendants filed motions seeking to have the claims dismissed. On December 13, 2002, the United States District Court for the Southern District of California granted the plaintiffs’ motion seeking to have the six cases remanded to the California state court. The defendants that filed the crossclaims appealed that decision remanding the Six Coordinated Suits to the California state courts to the Ninth Circuit. On December 8, 2004, the Ninth Circuit affirmed the district court’s remand decision. These actions are stayed with respect to the Mirant entities that are defendants by the filing of the Chapter 11 proceedings of those entities, but are proceeding with respect to the other defendants.

Two plaintiffs in the Six Coordinated Suits, Oscar’s Photo Lab and Mary L. Davis (the “Claimants”), filed proofs of claim (the “Oscar Claims”) in the bankruptcy proceedings against Mirant, Mirant Americas Energy Marketing, Mirant Americas Generation and other subsidiaries of Mirant on behalf of themselves and a purported class of all persons or entities in California who purchased electricity or natural gas for purposes other than resale or distribution at any time since January 1, 1999. Claimants alleged that various misconduct by Mirant and several of its subsidiaries caused inflated prices in the California wholesale power markets. Claimants listed the damage amount of their claims as “unliquidated.” On October 18, 2004, the Mirant Debtors filed an objection to the Oscar Claims. On November 5, 2004, the Mirant Debtors filed a motion requesting that the Bankruptcy Court strike the portions of the Oscar Claims that purported to have been filed on behalf of unnamed absent members of a purported class. On January 26, 2005, the Bankruptcy Court issued an order embodying a ruling made orally on December 1, 2004 granting this motion and disallowing the Oscar Claims with prejudice to the extent they sought to recover on account of any claims other than the claims of Oscar Photo Labs and Mary L. Davis in their individual capacities. The Claimants have filed a motion to amend their claims to add allegations of improper conduct by Mirant entities with respect to the reporting of information about natural gas transactions to trade publications that publish price indices, and the Mirant Debtors have also filed a motion to disallow the Oscar Claims. The Bankruptcy Court has not acted upon either motion.

The Mirant Debtors have entered into a stipulation with the Claimants entitling each plaintiff to receive an allowed, general, prepetition unsecured claim against Mirant Americas Energy Marketing in the amount of $1,000 without the Mirant Debtors’ admission of the validity of the Oscar Claims or any of the factual or legal assertions of these Claimants and with a full reservation of any rights, claims and defenses any of the Mirant Debtors may have against any person asserting the same or similar factual or legal assertions as those contained in the Oscar Claims. On March 9, 2005, the Bankruptcy Court entered the order and approved the stipulation.

Eight additional rate payer lawsuits were filed between April 23, 2002 and October 18, 2002 alleging that certain owners of electric generation facilities in California, as well as certain energy marketers, including Mirant, Mirant Americas Energy Marketing and several Mirant Americas Generation subsidiaries, engaged in various unlawful and fraudulent business acts that served to manipulate wholesale markets and inflate wholesale electricity prices in California during 1999 through 2002. Each of the complaints alleges violation of California’s Unfair Competition Act. One complaint also alleges violation of California’s antitrust statute. Each of the plaintiffs seeks class action status for their respective case. Some of these suits also allege that contracts between the DWR and certain marketers of electricity, including a nineteen month power sales agreement entered into by Mirant Americas Energy Marketing with the DWR in May 2001 that terminated in December 2002, contain terms that were unjust and unreasonable. The actions seek, among other things, restitution, compensatory and general damages, and to enjoin the defendants from engaging in illegal conduct. The captions of each of these eight cases follow:

Caption	Date Filed	Court of Original Filing
T&E Pastorino Nursery, et al. V. Duke Energy
Trading and Marketing, LLC, et al.	April 23, 2002	Superior Court of California—San Mateo County
RDJ Farms, Inc., et al. v. Allegheny Energy Supply
Company, LLC, et al.	May 10, 2002	Superior Court of California—San Joaquin County
Century Theatres, Inc., et al. v. Allegheny Energy
Supply Company, LLC, et al.	May 14, 2002	Superior Court of California—San Francisco County
El Super Burrito, Inc., et al. v. Allegheny Energy
Supply Company, LLC, et al.	May 15, 2002	Superior Court of California—San Mateo County
Leo’s Day and Night Pharmacy, et al. v. Duke
Energy Trading and Marketing, LLC, et al.	May 21, 2002	Superior Court of California—Alameda County
J&M Karsant Family Limited Partnership, et al. v.
Duke Energy Trading and Marketing, LLC, et al.	May 21, 2002	Superior Court of California—Alameda County
Bronco Don Holdings, LLP, et al. v. Duke Energy
Trading and Marketing, LLC, et al.	May 24, 2002	Superior Court of California—San Francisco County
Kurtz v. Duke Energy Trading et al.	October 18, 2002	Superior Court of California—Los Angeles County

These suits were initially filed in California state courts by the plaintiffs and removed to United States district courts. These eight cases were consolidated for purposes of pretrial proceedings with the Six Coordinated Suits described above. These actions are stayed with respect to the Mirant defendants by the filing of the Chapter 11 proceedings of those entities, but are proceeding with respect to the other defendants. On August 28, 2003, the district court granted the motions to dismiss filed by the defendants in the Pastorino, RDJ Farms, Century Theatres, El Super Burrito, Leo’s Day and Night Pharmacy, J&M Karsant and Bronco Don Holdings suits, finding that the plaintiffs’ claims were barred by the filed rate

doctrine and federal preemption. The plaintiffs have appealed that dismissal to the Ninth Circuit. The plaintiff in the Kurtz suit voluntarily dismissed his case without prejudice on February 18, 2004. None of the plaintiffs in these eight cases have filed proofs of claim in the bankruptcy proceedings.

On July 15, 2002, an additional rate payer lawsuit, Public Utility District No. 1 of Snohomish Co. v. Dynegy Power Marketing, et al., was filed in the United States District Court for the Central District of California against various owners of electric generation facilities in California, including Mirant, by Public Utility District No. 1 of Snohomish County, which is a municipal corporation in the state of Washington that provides electric and water utility service. The plaintiff public utility district alleges that defendants violated California’s antitrust statute by conspiring to raise wholesale power prices, injuring plaintiff through higher power purchase costs. The plaintiff also alleges that defendants acted both unfairly and unlawfully in violation of California’s Unfair Competition Act through various unlawful and anticompetitive acts, including the purportedly wrongful acquisition of plants, engagement in “Enron-style” trading and withholding power from the market. The plaintiff seeks restitution, disgorgement of profits, injunctive relief, treble damages and attorney’s fees. The Snohomish suit was consolidated for purposes of pretrial proceedings with the other rate payer suits pending before the United States District Court for the Southern District of California. On January 6, 2003, the district court granted a motion to dismiss filed by the defendants. On September 10, 2004, the United States Court of Appeals for the Ninth Circuit upheld the dismissal of the suit by the district court. The court of appeals ruled that the plaintiff’s claims under California’s antitrust statute and Unfair Competition Act are barred by the doctrine of preemption and the filed rate doctrine, concluding that if prices in the California wholesale electricity markets were not just and reasonable or if the defendants sold electricity in violation of the applicable tariffs, the plaintiff’s only option was to seek a remedy before the FERC under the Federal Power Act. On November 5, 2004, the plaintiff filed a petition for writ of certiorari with the United States Supreme Court seeking to appeal the Ninth Circuit’s decision. The plaintiff in the Snohomish suit has not filed a claim in the bankruptcy proceedings.

On November 20, 2002, a class action suit, Bustamante v. The McGraw-Hill Companies, Inc., et al., was filed in the Superior Court for the County of Los Angeles against certain publishers of index prices for natural gas, gas distribution or marketing companies, owners of electric generation facilities in California and energy marketers, including Mirant, Mirant Americas Energy Marketing and subsidiaries of Mirant Americas Generation. The plaintiff in the Bustamante suit alleged that the defendants violated California Penal Code sections 182 and 395 and California’s Unfair Competition Act by reporting false information about natural gas transactions to the defendants that published index prices for natural gas causing the prices paid by Californians for natural gas and for electricity to be artificially inflated. The suit sought, among other things, disgorgement of profits, restitution, and compensatory and punitive damages. On July 8, 2003, the Superior Court for the County of Los Angeles dismissed the suit, finding that the plaintiffs had failed to allege facts sufficient to warrant relief. The court granted the plaintiffs leave to file an amended complaint, and on August 13, 2003, the plaintiff filed an amended complaint asserting claims under California’s Unfair Competition Act and state antitrust statute against gas distribution or marketing companies, owners of electric generation facilities in California and energy marketers, including the Company and various of its subsidiaries. The amended complaint alleged that the defendants engaged in a scheme to report false gas prices and volumes to companies that published index prices for natural gas in order to manipulate the price indices to benefit themselves. This conduct, the plaintiff asserted, violated California Penal Code section 395 and caused the prices paid by Californians for natural gas to be artificially inflated. The suit was brought as a representative action on behalf of all similarly situated persons, the general public and all taxpayers. The suit sought, among other things, disgorgement of profits, restitution, treble damages and injunctive relief. In November 2003, the plaintiff dismissed the Mirant entities identified as defendants in the amended complaint filed in August 2003.

On December 15, 2003, the plaintiff in the Bustamante suit filed proofs of claim in the bankruptcy proceedings on behalf of a putative class (the “Bustamante Claims”) listing the total amount claimed as

$500 million and attaching the original and first amended complaints. On October 18, 2004, the Debtors filed an objection to the Bustamante Claims. On November 19, 2004, the Debtors filed a motion requesting that the Bankruptcy Court strike the portions of the Bustamante Claims that purported to have been filed on behalf of unnamed absent members of a purported class. On January 26, 2005, the Bankruptcy Court entered an order embodying a ruling made orally on December 1, 2004 granting the motion and striking the Bustamante Claims to the extent they sought to recover on account of any claims other than the claim of Bustamante, in his individual capacity. The Mirant Debtors have also filed a motion to disallow the remaining Bustamante Claims.

On April 28, 2003, a purported class action suit, Egger et al. v. Dynegy, Inc. et al., was filed in the Superior Court for the County of San Diego, California, against various owners of electric generation facilities in California and marketers of electricity and natural gas, including Mirant and various of subsidiaries of Mirant Americas Generation, on behalf of all persons who purchased electricity in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana from January 1, 1999. The plaintiffs allege that the defendants engaged in unlawful, unfair, and deceptive practices in the California and western wholesale electricity markets, including withholding energy from the market to create artificial shortages, creating artificial congestion over transmission lines, selling electricity bought in California to out of state affiliates to create artificial shortages and then selling the electricity back into the state at higher prices. The plaintiffs contend that the defendants conspired among themselves and with subsidiaries of Enron Corporation to withhold electricity from the Cal PX and CAISO markets and to manipulate the price of electricity sold at wholesale in the California and western markets. The defendants’ unlawful manipulation of the wholesale energy market, the plaintiffs allege, resulted in supply shortages and skyrocketing energy prices in the western United States, which in turn caused drastic rate increases for retail consumers. The plaintiffs assert claims under California’s antitrust statute and its Unfair Competition Act. The plaintiffs contend that the defendants’ alleged wrongful conduct has caused damages in excess of one billion dollars and seek treble damages, injunctive relief, restitution, and an accounting of the wholesale energy transactions entered into by the defendants from 1998. The defendants removed the suit to the United States District Court for the Southern District of California. The plaintiffs filed an amended complaint in October 2003 that did not include any Mirant entities as defendants due to the stay of litigation resulting from the filing of the Mirant Chapter 11 proceedings, but identified them as “relevant actors.”

Five plaintiffs in the Egger suit (the “Proposed Representatives”) filed proofs of claim (the “Egger Claims”) in the bankruptcy proceedings purportedly on behalf of a class of “all persons and businesses residing in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana who were purchasers of electrical energy during the period beginning January 1, 1999 to the present.” Claimants alleged that various misconduct by Mirant and several of its subsidiaries caused inflated prices in wholesale power markets. Claimants listed the damage amount of their claims as “TBD/in excess of $100 million.” Claimants attached the first amended complaint to their proofs of claims. On October 18, 2004, the Debtors filed an objection to the Egger Claims. On November 10, 2004, the parties jointly presented to the Bankruptcy Court a scheduling order in which they agreed that the Egger Claims were sufficiently similar to the Oscar Claims so that the Bankruptcy Court’s ruling on Mirant’s motion to strike the Oscar Claims would also be dispositive as to the Egger Claims. Thus, the Egger Claims were disallowed with prejudice to the extent they sought to recover on account of any claims other than those of the Proposed Representatives in their individual capacities. On January 19, 2005, the Bankruptcy Court approved a settlement agreement with the Proposed Representatives pursuant to which each of the Proposed Representatives will be entitled to receive an allowed, general unsecured claim against Mirant Americas Energy Marketing in the amount of $1,000 in full and final satisfaction of the Egger Claims.

Montana Attorney General Suit

On June 30, 2003, the Montana Attorney General and Flathead Electric Cooperative, Inc. filed a suit in the First Judicial District of Montana, County of Lewis and Clark, against various owners of generating facilities and marketers of electricity and natural gas in western states, including Mirant, alleging that the defendants had engaged in unlawful and unfair business practices in 2000 and 2001 involving the sale of wholesale electricity and natural gas and had manipulated the markets for wholesale electricity and natural gas. The plaintiffs alleged, among other things, that the defendants fixed prices and restricted supply into the markets operated by the Cal PX and CAISO, gamed the power market, provided false information to trade publications to inflate natural gas price indices published by such publications, and engaged in other manipulative practices, including withholding generation, selling generation at inflated prices, submitting false load schedules in order to increase electricity scarcity, creating fictitious congestion and counterflows, and double-selling the same generation to the CAISO. The plaintiffs contended that the defendants conspired with each other and acted in concert with each other in engaging in the conduct alleged. The plaintiffs asserted claims for violation of Montana’s Unfair Trade Practices and Consumer Protection Act and fraud. They seek treble damages, injunctive relief, and attorneys’ fees. The suit was removed to the United States District Court for the District of Montana on July 23, 2003, and on December 5, 2003 the district court remanded the proceeding to the state court. The Montana Attorney General has not filed any proof of claim in the bankruptcy proceedings.

On February 12, 2004, the Montana Public Service Commission initiated an investigation of the Montana retail electricity market affected by transactions involving the western electricity grid. The purpose of the investigation is to determine whether there is evidence of unlawful manipulation of that market related to the high prices for electricity in the western wholesale markets that occurred in 2000 and 2001. The Commission ordered this investigation in response to petitions filed by the Montana Attorney General and Flathead Electric Cooperative, Inc. making allegations similar to those asserted in their suit described above. Mirant and its subsidiaries are not engaged in the generation of electricity or the sale of electricity at retail in Montana and, therefore, do not believe they are subject to the regulatory jurisdiction of the Montana Public Service Commission.

Shareholder-Bondholder Litigation

Mirant Securities Consolidated Action. Twenty lawsuits have been filed since May 29, 2002 against Mirant and four of its officers alleging, among other things, that the defendants violated Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Rule 10b-5 promulgated thereunder by making material misrepresentations and omissions to the investing public regarding Mirant’s business operations and future prospects during the period from January 19, 2001 through May 6, 2002. The suits have each been filed in the United States District Court for the Northern District of Georgia, with the exception of three suits filed in the United States District Court for the Northern District of California. The three suits filed in California have been transferred by the court to the United States District Court for the Northern District of Georgia and consolidated with the seventeen consolidated suits already pending before that court. The complaints seek unspecified damages, including compensatory damages and the recovery of reasonable attorneys’ fees and costs. The captions of each of the cases follow:

Caption				Date Filed
Kornfeld v. Mirant Corp., et al.				May 29, 2002
Holzer v. Mirant Corp., et al.				May 31, 2002
Abrams v. Mirant Corp., et al.				June 3, 2002
Froelich v. Mirant Corp., et al.				June 4, 2002
Rand v. Mirant Corp., et al.				June 5, 2002
Purowitz v. Mirant Corp., et al.				June 10, 2002
Kellner v. Mirant Corp., et al.				June 14, 2002
Sved v. Mirant Corp., et al.				June 14, 2002
Teaford v. Mirant Corp., et al.				June 14, 2002
Woff v. Mirant Corp., et al.				June 14, 2002
Peruche v. Mirant Corp., et al.				June 14, 2002
Thomas v. Mirant Corp., et al.				June 18, 2002
Urgenson v. Mirant Corp., et al.				June 18, 2002
Orlofsky v. Mirant Corp., et al.				June 24, 2002
Jannett v. Mirant Corp.				June 28, 2002
Green v. Mirant Corp., et al.				July 9, 2002
Greenberg v. Mirant Corp., et al.				July 16, 2002
Law v. Mirant Corp., et al.				July 17, 2002
Russo v. Mirant Corp., et al.				July 18, 2002
Delgado v. Mirant Corp., et al.				October 4, 2002

In November 2002, the plaintiffs in the consolidated suits in the United States District Court for the Northern District of Georgia filed an amended complaint that added additional defendants and claims. The plaintiffs added as defendants Southern Company (“Southern”), the directors of Mirant immediately prior to its initial public offering of stock, and various firms that were underwriters for the initial public offering by the Company. In addition to the claims set out in the original complaint, the amended complaint asserts claims under Sections 11 and 15 of the Securities Act of 1933, alleging that the registration statement and prospectus for the initial public offering of Mirant’s stock misrepresented and omitted material facts. In the amended complaint, the plaintiffs expand their claims under sections 10(b) and 20 of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder to include statements made to the investing public regarding Mirant’s business operations and future prospects during the period from September 26, 2000 through September 5, 2002. The amended complaint alleges, among other things, that Mirant’s stock price was artificially inflated because the Company failed to disclose in various filings, public statements, and registration statements: (1) that Mirant allegedly reaped illegal profits in California by manipulating energy prices through a variety of alleged improper tactics; (2) that Mirant allegedly failed to take a timely charge to earnings through a write off of its interest in Western Power Distribution; and (3) the accounting errors and internal controls issues that were disclosed in July and November of 2002. On July 14, 2003, the district court dismissed the claims asserted by the plaintiffs based on the Company’s California business activities but allowed the case to proceed on the plaintiffs’ other claims.

This action is stayed as to Mirant by the filing of its Chapter 11 proceeding. On November 19, 2003, the Bankruptcy Court entered an order staying this action also with respect to the other defendants to avoid the suit impeding the ability of Mirant to reorganize or having a negative effect upon Mirant’s assets. The Bankruptcy Court has modified the stay to allow the plaintiffs to proceed with discovery of documentary materials from Mirant and the other defendants. On December 11, 2003, the plaintiffs filed a proof of claim against the estate of Mirant, which was subsequently withdrawn on or about October 10, 2004. Because of the stay applicable to the litigation, Mirant has not yet been released as a defendant in the consolidated lawsuits.

Under a master separation agreement between Mirant and Southern, Southern is entitled to be indemnified by Mirant for any losses arising out of any acts or omissions by Mirant and its subsidiaries in the conduct of the business of Mirant and its subsidiaries. The underwriting agreements between Mirant and the various firms added as defendants that were underwriters for the initial public offering by the Company also provide for Mirant to indemnify such firms against any losses arising out of any acts or omissions by Mirant and its subsidiaries.

Mirant Americas Generation Bondholder Suit. On June 10, 2003, certain holders of senior notes of Mirant Americas Generation maturing after 2006 filed a complaint in the Court of Chancery of the State of Delaware, California Public Employees’ Retirement System, et al. v. Mirant Corporation, et al., that named as defendants Mirant, Mirant Americas Inc., Mirant Americas Generation, certain past and present Mirant directors, and certain past and present Mirant Americas Generation managers. Among other claims, the plaintiffs assert that a restructuring plan pursued by the Company prior to its filing a petition for reorganization under Chapter 11 was in breach of fiduciary duties allegedly owed to them by Mirant, Mirant Americas Inc., and Mirant Americas Generation managers. In addition, the plaintiffs challenge certain dividends and distributions made by Mirant Americas Generation. The plaintiffs seek damages in excess of one billion dollars. Mirant has removed this suit to the United States District Court for the District of Delaware. This action is stayed with respect to the Mirant entities that are defendants by the filing of the Chapter 11 cases. On November 19, 2003, the Bankruptcy Court entered an order staying this action also with respect to the individual defendants to avoid the suit impeding the ability of the Mirant Debtors to reorganize or having a negative effect upon the assets of the Mirant Debtors. The Mirant Americas Generation Creditor Committee filed a motion in Mirant’s bankruptcy proceedings seeking to pursue claims against Mirant, Mirant Americas Inc., certain past and present Mirant directors, and certain past and present Mirant Americas Generation managers similar to those asserted in this suit. The Bankruptcy Court ruled that while the Mirant Americas Generation Creditor Committee has standing to assert claims on behalf of the estate of Mirant Americas Generation, no such claims could be filed without the Bankruptcy Court’s approval and no motions seeking such approval could be filed at least through April 2004. No such motion has been filed with the Bankruptcy Court since April 2004, and the Bankruptcy Court has not authorized any such litigation at this time.

On December 15, 2003, Lehman Commercial Paper Inc. (“Lehman”), as agent for various lenders under certain pre-petition credit agreements, filed a claim against Mirant Americas Generation in the bankruptcy proceedings. On December 15, 2003, Wells Fargo Bank, N.A. (“Wells Fargo”) also filed claims in the bankruptcy proceedings as successor indenture trustee for bond indebtedness under a certain indenture against Mirant Americas Generation. In addition to their original claims, on that same date, Lehman and Wells Fargo filed supplemental claims against Mirant Americas Generation, Mirant and a number of other subsidiaries of Mirant (the “Supplemental Claims”) seeking recovery of principal, interest, fees, and costs under the Mirant Americas Generation loan documents and bond documents, respectively. In their Supplemental Claims, Lehman and Wells Fargo essentially seek to preserve for themselves the claims previously sought to be asserted by the Mirant Americas Generation Creditor Committee.

On November 3, 2004, the Mirant Debtors objected to the Supplemental Claims against Mirant Americas Generation and the other Mirant entities on the grounds that: (1) Lehman and Wells Fargo lack standing to pursue the Supplemental Claims, which are derivative claims belonging to each respective Mirant Debtor’s estate; (2) there is no factual basis for any of the “potential” causes of action against Mirant Americas Generation and no basis whatsoever for the claims against any other Mirant entities; and (3) the Supplemental Claims are duplicative and contingent. In addition to the objection, the Mirant Debtors also filed a motion to dismiss the Supplemental Claims on the basis that the Supplemental Claims do not allege any independent harm to Lehman and Wells Fargo and assert nothing more than derivative claims belonging to the Mirant Debtors’ estates that cannot be asserted by Lehman and Wells Fargo.

On January 24, 2005, the Mirant Debtors filed an expedited motion requesting entry of an order specifying procedures to resolve the Supplemental Claims. The Bankruptcy Court held, on February 15, 2005, that (1) the Supplemental Claims will be withdrawn; (2) the withdrawal of the Supplemental Claims, to the extent that they are not property of the estates of or derivative of a Debtor (“Withdrawn Claims”), will be without prejudice, and the Bar Date will not apply to such claims; and (3) the Withdrawn Claims will not be barred until confirmation of a Plan addresses or extinguishes them and Lehman or Wells Fargo can only raise these claims as issues in the confirmation process.

Shareholder Derivative Litigation. Four purported shareholders’ derivative suits have been filed against Mirant, its directors and certain officers of Mirant. These lawsuits allege that the directors breached their fiduciary duties by allowing the Company to engage in alleged unlawful or improper practices in the California energy market during 2000 and 2001. The practices complained of in the purported derivative lawsuits largely mirror those alleged in the shareholder litigation, the rate payer litigation, and the California Attorney General lawsuits described above. One suit also alleges that the defendant officers engaged in insider trading. The complaints seek unspecified damages on behalf of Mirant, including attorneys’ fees, costs and expenses and punitive damages. The captions of each of the cases follow:

Caption				Date Filed
Kester v. Correll, et al.				June 26, 2002
Pettingill v. Fuller, et al.				July 30, 2002
White v. Correll, et al.				August 9, 2002
Cichocki v. Correll, et al.				November 7, 2002

The Kester and White suits were filed in the Superior Court of Fulton County, Georgia, and were consolidated on March 13, 2003 under the name In re Mirant Corporation Derivative Litigation. The consolidated action has been removed by Mirant to the United States District Court for the Northern District of Georgia. The Pettingill suit was filed in the Court of Chancery for New Castle County, Delaware and was removed by Mirant to the United States District Court for the District of Delaware. The Cichocki suit was filed in the United States District Court for the Northern District of Georgia. These actions are stayed as to Mirant by the filing of its Chapter 11 proceeding. On November 19, 2003, the Bankruptcy Court entered an order staying these actions also with respect to the individual defendants to avoid the suit impeding the ability of Mirant to reorganize or having a negative effect upon Mirant’s assets. On December 8, 2003, the court in the Cichocki suit took notice of the Bankruptcy Court’s Order dated November 19, 2003 staying the litigation and administratively closed the action. No proofs of claims were filed in the Chapter 11 proceedings with respect to the shareholder derivative suits.

ERISA Litigation. On April 17, 2003 and June 3, 2003, two purported class action lawsuits alleging violations of the Employee Retirement Income Security Act (“ERISA”) were filed in the United States District Court for the Northern District of Georgia, under the captions James Brown v. Mirant Corporation, et al. and Greg Waller, Sr. v. Mirant Corporation et al. (the “ERISA Litigation”). The ERISA Litigation names as defendants Mirant, certain of its current and former officers and directors, and Southern. The plaintiffs, who seek to represent a putative class of participants and beneficiaries of Mirant’s 401(k) plans (the “Plans”), allege that defendants breached their duties under ERISA by, among other things, (i) concealing information from the Plans’ participants and beneficiaries; (ii) failing to ensure that the Plans’ assets were invested prudently; (iii) failing to monitor the Plans’ fiduciaries; and (iv) failing to engage independent fiduciaries to make judgments about the Plans’ investments. The factual allegations underlying these lawsuits are substantially similar to those described with respect to the shareholder litigation, the rate payer litigation, and the California Attorney General lawsuits described above. The plaintiffs seek unspecified damages, injunctive relief, attorneys’ fees and costs. On September 2, 2003, the district court issued an order consolidating the two suits. On September 23, 2003, the plaintiffs filed an

amended and consolidated complaint. The amended and consolidated complaint asserted similar factual allegations as the previously filed lawsuits and added as defendants T. Rowe Price Trust Company and certain additional current and former officers of Mirant. The consolidated action is stayed as to Mirant by the filing of its Chapter 11 proceeding. On November 19, 2003, the Bankruptcy Court entered an order staying this action also with respect to the other defendants to avoid the suit impeding the ability of Mirant to reorganize or having a negative effect upon Mirant’s assets. By agreement, however, the suit has been allowed to proceed through the filing of, and ruling by the district court upon, motions to dismiss. On January 9, 2004, T. Rowe Price Trust Company answered the amended and consolidated complaint. All other defendants filed motions on that date seeking dismissal of the plaintiffs’ claims for failure to state a claim upon which relief can be granted. On February 19, 2004, the plaintiffs dismissed their claims against Southern without prejudice. On June 14, 2004, the plaintiffs filed a motion seeking to amend their consolidated complaint to add as defendants Mirant Services, LLC and its board of managers.

On August 4, 2004, the United States District Court for the Northern District of Georgia entered an order staying the ERISA Litigation until the Bankruptcy Court lifts the stays resulting from the filing of Mirant’s bankruptcy proceedings and the order entered by the Bankruptcy Court on November 19, 2003 staying the action with respect to the other defendants. In the order issued August 4, 2004, the district court also denied the motions to dismiss filed by various defendants, including Mirant, and the motion filed by the plaintiffs seeking to amend their consolidated complaint to add as defendants Mirant Services and its board of managers. With respect to both motions, the district court granted the party filing the motion leave to refile the motion once the stays have been lifted by the Bankruptcy Court.

In December 2003, attorneys purporting to act on behalf of the plaintiffs in the ERISA Litigation filed proofs of claim against the Mirant Debtors’ estates, totaling approximately $50 million (the “Brown & Waller Claims”). On October 18, 2004, the Mirant Debtors objected to the Brown & Waller Claims. The parties recently announced to the Bankruptcy Court that they have settled the Brown & Waller Claims, subject to Bankruptcy Court approval. Under the proposed settlement agreement, the claimants agreed to limit their recovery against the Mirant Debtors and any related defendants in the ERISA Litigation to the proceeds paid or payable under certain insurance policies issued to Southern Company and Mirant. The Brown & Waller Claims in the bankruptcy proceedings will be amended to be for a zero dollar amount, and the parties agreed that the Brown & Waller claims will not be further amended.

Mirant Americas Generation Securities Class Action. On June 11, 2003, a purported class action lawsuit alleging violations of Sections 11 and 15 of the Securities Act of 1933 was filed in the Superior Court of Fulton County, Georgia, entitled Wisniak v. Mirant Americas Generation, LLC, et al. The lawsuit names as defendants Mirant Americas Generation and certain current and former officers and managers of Mirant Americas Generation. The plaintiff seeks to represent a putative class of all persons who purchased debt securities of Mirant Americas Generation pursuant to or traceable to an exchange offer completed by Mirant Americas Generation in May 2002 in which $750 million of bonds registered under the Securities Act were exchanged for $750 million of previously issued senior notes of Mirant Americas Generation. The plaintiff alleges, among other things, that Mirant Americas Generation ‘s restatement in April 2003 of prior financial statements rendered the registration statement filed for the May 2002 exchange offer materially false. The complaint seeks damages, interest and attorneys’ fees. The defendants have removed the suit to the United States District Court for the Northern District of Georgia. This action is stayed as to Mirant Americas Generation by the filing of its Chapter 11 proceeding. On November 19, 2003, the Bankruptcy Court entered an order staying these actions also with respect to the individual defendants to avoid the suit impeding the ability of Mirant Americas Generation to reorganize or having a negative effect upon its assets. On December 8, 2003, the court took notice of the Bankruptcy Court’s Order dated November 19, 2003 staying the litigation and administratively closed the action. On December 16, 2003, the plaintiff dismissed Mirant Americas Generation as a defendant, without prejudice,

and filed a proof of claim against Mirant Americas Generation in the bankruptcy proceedings asserting the same claims set forth in the lawsuit.

Mirant Americas Generation and the plaintiff have entered into a stipulation of settlement of the Wisniak suit and the claim filed against Mirant Americas Generation that was approved by the Bankruptcy Court on January 19, 2005. Under the terms of the stipulation of settlement, the plaintiff will seek certification of a class by the district court that will receive $2.25 million to be paid by insurers for Mirant Americas Generation, and an allowed, unsecured claim of $2 million against Mirant subordinated to the claims of its other unsecured creditors. Members of the plaintiff class will have the opportunity to opt out of the settlement, and if class members who choose to opt out own in the aggregate more than 1% of the Mirant Americas Generation bonds that are the subject of the suit, then the Mirant defendants have the option to withdraw from the settlement. The stipulation of settlement must also be approved by the district court to become effective.

PEPCO Litigation

In 2000, Mirant purchased certain power generating assets and certain other assets from PEPCO, including certain power purchase agreements (“PPAs”). Under the terms of the Asset Purchase and Sale Agreement (the “APSA”) Mirant and PEPCO entered into a contractual arrangement (the “Back-to-Back Agreement”) with respect to certain PPAs, including PEPCO’s long-term PPAs with Ohio Edison Company (“Ohio Edison”) and Panda-Brandywine L.P. (“Panda”) under which (1) PEPCO agreed to resell to Mirant all “capacity, energy, ancillary services and other benefits” to which it is entitled under those agreements; and (2) Mirant agreed to pay PEPCO each month all amounts due from PEPCO to Panda or Ohio Edison for the immediately preceding month associated with such capacity, energy, ancillary services and other benefits. The Panda and Ohio Edison PPAs run until 2021 and 2005 respectively. Under the Back-to-Back Agreement, Mirant is obligated to purchase power from PEPCO at prices that are significantly higher than existing market prices for power.

Back-to-Back Agreement Litigation. On August 28, 2003, the Mirant Debtors filed a motion in the bankruptcy proceedings to reject the Back-to-Back Agreement (the “Rejection Motion”), along with an adversary proceeding to enjoin PEPCO and the FERC from taking certain actions against the Mirant Debtors (the “Injunction Litigation”). On October 9, 2003, the United States District Court for the Northern District of Texas entered an order that had the effect of transferring to that court from the Bankruptcy Court the motion filed by the Mirant Debtors seeking to reject the Back-to-Back Agreement and the Injunction Litigation. In December 2003, the district court denied the Rejection Motion and, thereafter, dismissed the Injunction Litigation. The district court ruled that the Federal Power Act preempts the Bankruptcy Code and that a bankruptcy court cannot affect a matter within the FERC’s jurisdiction under the Federal Power Act, including the rejection of a wholesale power purchase agreement regulated by the FERC.

The Mirant Debtors appealed the district court’s orders to the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”). The Fifth Circuit reversed the district court’s decision, holding that the Bankruptcy Code authorizes a district court (or bankruptcy court) to reject a contract for the sale of electricity that is subject to the FERC’s regulation under the Federal Power Act as part of a bankruptcy proceeding and that the Federal Power Act does not preempt that authority. The Fifth Circuit remanded the proceeding to the district court for further action on that motion. The Fifth Circuit indicated that on remand the district court could consider applying a more rigorous standard than the business judgment standard typically applicable to contract rejection decisions by debtors in bankruptcy, which more rigorous standard would take into account the public interest in the transmission and sale of electricity.

that if the Fifth Circuit overturned the district court’s ruling with respect to severability, the Back-to-Back Agreement should be rejected only if Mirant can prove that the Back-to-Back Agreement burdens the bankrupt estates; that, after scrutiny and giving significant weight to the comments of the FERC relative to the effect of rejection on the public interest, the equities balance in favor of rejecting the Back-to-Back Agreement; and that rejection of the Back-to-Back Agreement would further the Chapter 11 goal of permitting the successful rehabilitation of the Mirant Debtors. The Mirant Debtors have appealed the district court’s December 9, 2004, decision to the Fifth Circuit and requested that the Fifth Circuit hear this appeal on an expedited basis. On March 8, 2005, the Fifth Circuit denied Mirant’s request to have the appeal expedited.

On January 21, 2005, the Mirant Debtors filed a motion in the bankruptcy proceedings to reject the APSA, including the Back-to-Back Agreement but not including other agreements entered into between Mirant and its subsidiaries and PEPCO under the terms of the APSA (the “Second Rejection Motion”). On February 10, 2005, PEPCO filed a motion requesting the district court to assert jurisdiction over and rule upon the Second Rejection Motion rather than having the Bankruptcy Court rule on that motion, arguing that the motion required the consideration of laws other than the Bankruptcy Code. On March 1, 2005, the district court ruled that it would withdraw the reference to the Bankruptcy Court of the Mirant Debtors’ January 21, 2005 motion seeking to reject the APSA and would itself hear that motion.

Suspension of PEPCO Back-to-Back Payments. On December 9, 2004, in an effort to halt excessive out-of-market payments under the Back-to-Back Agreement while awaiting resolution of issues related to the potential rejection of the Back-to-Back Agreement (but prior to notice of entry of the district court’s order of December 9, 2004), Mirant filed a notice in the Bankruptcy Court that Mirant was suspending further payments to PEPCO under the Back-to-Back Agreement absent further order of the court (the “Suspension Notice”). On December 10, 2004, in response to the Suspension Notice, PEPCO filed a motion in the district court seeking a temporary restraining order and injunctive relief to require Mirant to perform under the Back-to-Back Agreement (the “Injunctive Relief Motion”). On December 13, 2004, the district court issued an order referring the Injunctive Relief Motion to the Bankruptcy Court. On December 21, 2004, the Bankruptcy Court issued an order denying the temporary restraining order sought by PEPCO.

On December 14, 2004, PEPCO filed the following additional litigation: (i) a motion seeking relief from the automatic stay provision of Bankruptcy Code section 362(a) to permit PEPCO to terminate performance under the APSA (the “Lift Stay Motion”); (ii) a motion to compel the Mirant Debtors to pay, as administrative expenses, payments that had been suspended under the Back-to-Back Agreement (the “Administrative Expense Motion”); and (iii) an adversary proceeding seeking to compel the Mirant Debtors to make payments under the Back-to-Back Agreement (the “PEPCO Lawsuit”). On December 16, 2004, PEPCO filed a motion requesting the district court to withdraw the reference to the Bankruptcy Court with respect to the litigation filed by PEPCO on December 14, 2004, as well as the Injunctive Relief Motion (the “Second Withdrawal Motion”). On January 4, 2005, the district court denied the Second Withdrawal Motion in its entirety. On January 19, 2005, the Bankruptcy Court entered an order embodying a ruling made orally by the Court on January 14, 2005, in which it denied the Lift Stay Motion and the Administrative Expense Motion, but required the Mirant Debtors to pay amounts due under the Back-to-Back Agreement in January 2005 and thereafter until (i) the Mirant Debtors filed a motion to reject the APSA, (ii) the Fifth Circuit issued an order reversing the district court’s order of December 9, 2004 denying the motion to reject the Back-to-Back Agreement, or (iii) the Mirant Debtors were successful in having the obligations under the Back-to-Back Agreement recharacterized as debt obligations. PEPCO filed an appeal of the Bankruptcy Court’s January 19 order. On March 1, 2005, the district court ordered the Mirant Debtors to pay PEPCO all past-due, unpaid obligations under the Back-to-Back Agreement by March 10, 2005, withdrew the reference to the Bankruptcy Court of the Administrative Expense Motion, and dismissed PEPCO’s appeal of the January 19 order denying the

Administrative Expense Motion as moot. The Mirant Debtors on March 4, 2005 filed a motion requesting the district court to reconsider its order of March 1, 2004 or alternatively to stay that order while the Mirant Debtors appeal it to the Fifth Circuit. On March 7, 2005, the district court modified the March 1 order to require PEPCO to file a response to the Mirant Debtors’ motion for reconsideration by March 14 and to delay until March 18, 2005, the date by which the Mirant Debtors are to pay past-due, unpaid obligations under the Back-to-Back Agreement.

Potential Adjustment Related to Panda Power Purchase Agreement. At the time of the acquisition of the Mirant Mid-Atlantic assets from PEPCO, Mirant also entered into an agreement with PEPCO that, as subsequently modified, provided that the price paid by Mirant for its December 2000 acquisition of PEPCO assets would be adjusted if by March 19, 2005 a binding court order has been entered finding that the Back-to-Back Agreement violates PEPCO’s power purchase agreement with Panda (“Panda PPA”) as a prohibited assignment, transfer or delegation of the Panda PPA or because it effects a prohibited delegation or transfer of rights, duties or obligations under the Panda PPA that is not severable from the rest of the Back-to-Back Agreement. If a court order is entered that triggers the purchase price adjustment, the amount of the adjustment is to be negotiated in good faith by the parties or determined by binding arbitration so as to compensate PEPCO for the termination of the benefit of the Back-to-Back Agreement while also holding Mirant economically indifferent from such court order. Panda initiated legal proceedings in 2000 asserting that the Back-to-Back Agreement violated provisions in the Panda PPA prohibiting PEPCO from assigning the Panda PPA or delegating its duties under the Panda PPA to a third party without Panda’s prior written consent. On June 10, 2003, the Maryland Court of Appeals, Maryland’s highest court, ruled that the assignment of certain rights and delegation of certain duties by PEPCO to Mirant did violate the non-assignment provision of the Panda PPA and was unenforceable. The court, however, left open the issues whether the provisions found to violate the Panda PPA could be severed and the rest of the Back-to-Back Agreement enforced and whether Panda’s refusal to consent to the assignment of the Panda PPA by PEPCO to Mirant was unreasonable and violated the Panda PPA. If the June 10, 2003 decision by the Maryland Court of Appeals or a subsequent decision addressing the Back-to-Back Agreement is determined to have triggered the adjustment to the purchase price paid by Mirant to PEPCO, such adjustment would not be expected to have a material adverse effect on our financial position or results of operations.

City of Alexandria Zoning Action

On December 18, 2004, the City Council for the City of Alexandria, Virginia (the “City Council”) adopted certain zoning ordinance amendments recommended by the City Planning Commission that result in the zoning status of Mirant Potomac River, LLC’s (“Mirant Potomac”) generating plant being changed from “noncomplying use” to “nonconforming use subject to abatement.” Under the nonconforming use status, unless Mirant Potomac applies for and is granted a special use permit for the plant during the seven-year abatement period, the operation of the plant must be terminated within a seven-year period, and no alterations that directly prolong the life of the plant will be permitted during the seven-year period. Typically, the City Council grants special use permits with various conditions and stipulations as to the permitted use.

At its December 18, 2004, meeting, the City Council also approved revocation of two special use permits issued in 1989 (the “1989 SUPs”), one applicable to the administrative office space at Mirant Potomac’s plant and the other for the plant’s transportation management plan. Under the terms of the approved action, the revocation of the 1989 SUPs will take effect 120 days after the City Council revocation, provided, however, that if Mirant Potomac files an application for a special use permit for the entire plant operations within such 120-day period, the effective date of the revocation of the 1989 SUPs will be stayed until final decision by the City Council on such applications. The approved action further provides that if such special use permit application is approved by the City Council, revocation of the 1989

SUPs will be dismissed as moot, and if the City Council does not approve the application, the revocation of the 1989 SUPs will become effective and the plant will be considered an illegal use.

On January 18, 2005, Mirant Potomac and Mirant Mid-Atlantic, LLC filed a complaint against the City of Alexandria and the City Council in the Circuit Court for the City of Alexandria. The complaint seeks to overturn the actions taken by the City Council on December 18, 2004 changing the zoning status of Mirant Potomac’s generating plant and approving revocation of the 1989 SUPs, on the grounds that those actions violated federal, state and city laws. The complaint asserts, among other things, that the actions taken by the City Council constituted unlawful spot zoning, were arbitrary and capricious, constituted an unlawful attempt by the City Council to regulate emissions from the plant, and violated Mirant Potomac’s due process rights. Mirant Potomac and Mirant Mid-Atlantic request the court to enjoin the City of Alexandria and the City Council from taking any enforcement action against Mirant Potomac or from requiring it to obtain a special use permit for the continued operation of its generating plant.

Utility Choice Suit

On February 18, 2005, two providers of electricity at retail in Texas, Utility Choice, L.P. and Cirro Group, Inc., filed a suit in the United States District Court for the Southern District of Texas, entitled Utility Choice, L.P., et al. v. TXU Corp., et al., against numerous owners of generating facilities and power marketers in Texas, including Mirant Americas Energy Marketing, Mirant Americas Development, Inc., and two subsidiaries of Mirant Americas Generation owning generating facilities in Texas. The plaintiffs allege that the defendants, including the Mirant defendants, acting individually and in collusion with each other, engaged in various types of unlawful manipulation of the short term and bilateral wholesale power markets in the Electric Reliability Council of Texas region beginning in 2001 and continuing to the period immediately prior to the filing of the suit that caused the plaintiffs to pay significantly higher prices for power they purchased and to incur other significant costs. The types of conduct that the plaintiffs allege were engaged in by the defendants, including the Mirant defendants, include submitting false schedules and bids, “hockey stick” bidding, withholding generation resources from the market and bidding generation resources at artificially high prices, in each case with the intent to create artificially high market prices. The complaint asserts various causes of action, including without limitation claims under the federal and Texas antitrust acts and the federal Racketeer Influenced and Corrupt Organizations (RICO) Act, as well as state law claims for fraud, negligent misrepresentation, and promissory estoppel. The plaintiffs seek lost profits and other compensatory damages of an unspecified amount, treble damages, exemplary damages and attorneys’ fees.

Environmental Proceedings

EPA Information Request. In January 2001, the Environmental Protection Agency (“EPA”) issued a request for information to Mirant concerning the air permitting and air emission control implications under the EPA’s new source review regulations promulgated under the Clean Air Act of past repair and maintenance activities at Mirant Potomac’s plant in Virginia and Mirant Americas Generation’s Chalk Point, Dickerson and Morgantown plants in Maryland. The requested information concerns the period of operations that predates Mirant’s ownership and lease of the plants. Mirant has responded fully to this request. Under the sales agreement with PEPCO for those plants, PEPCO is responsible for fines and penalties arising from any violation associated with historical operations prior to Mirant’s acquisition of the plants. If a violation is determined to have occurred at any of the plants, the Mirant entity owning the plant may be responsible for the cost of purchasing and installing emission control equipment, the cost of which may be material. If such violation is determined to have occurred after Mirant acquired the plants or, if occurring prior to the acquisition, is determined to constitute a continuing violation, the Mirant entity owning the plant at issue would also be subject to fines and penalties by the state or federal government for the period subsequent to its acquisition of the plant, the cost of which may be material.

California Department of Toxic Substances Control Claim. On January 7, 2004, the California Department of Toxic Substances Control filed a proof of claim in the Mirant Debtors’ bankruptcy proceedings based on civil penalties for alleged non-compliance with state hazardous waste laws and regulations requiring proper documentation of financial assurance for the ultimate closure and post-closure costs, and third-party liability coverage, related to the power plant in Pittsburg, California owned by Mirant America Generation’s subsidiary, Mirant Delta. On December 2, 2004, a settlement was reached that allows the California Department of Toxic Substances Control a general unsecured claim of approximately $50,000 against Mirant Delta in the bankruptcy proceedings.

New York Opacity. On October 20, 2004, the New York State Department of Environmental Affairs Region 3 Staff filed a complaint against Mirant Bowline, Mirant Lovett and Mirant New York with the New York Department of Environmental Conservation. The complaint alleges that the generating facilities owned by Mirant Bowline and Mirant Lovett violated Article 19 of New York’s Environmental Conservation Law and regulations promulgated pursuant to that law by violating opacity standards set for smoke emissions on more than one hundred occasions between the second quarter of 2002 and the first quarter of 2004. The complaint seeks a cease and desist order and fines of $1.96 million against the Mirant defendants.

Potomac River Notice of Violation. On September 10, 2003, the Virginia Department of Environmental Quality issued a Notice of Violation (“NOV”) to Mirant Potomac alleging that it violated its Virginia Stationary Source Permit to Operate by emitting nitrogen oxide (“NOx”) in excess of the “cap” established by the permit for the 2003 summer ozone season. Mirant Potomac responded to the NOV, asserting that the cap is unenforceable, that it can comply through the purchase of emissions credits and raising other equitable defenses. Virginia’s civil enforcement statute provides for injunctive relief and penalties. On January 22, 2004, the EPA issued a NOV to Mirant Potomac alleging the same violation of its Virginia Stationary Source Permit to Operate as set out in the NOV issued by the Virginia Department of Environmental Quality.

On September 27, 2004, Mirant Potomac, Mirant Mid-Atlantic, the Virginia Department of Environmental Quality, the Maryland Department of the Environment, the DOJ and the EPA entered into, and filed for approval with the United States District Court for the Eastern District of Virginia, a consent decree that, if approved, will resolve Mirant Potomac’s potential liability for matters addressed in the NOVs previously issued by the Virginia Department of Environmental Quality and the EPA. The consent decree requires Mirant Potomac and Mirant Mid-Atlantic to install pollution control equipment at Mirant Potomac’s Potomac River plant and at the Morgantown plant leased by Mirant Mid-Atlantic in Maryland; to comply with declining system-wide ozone season NOx emissions caps from 2004 through 2010; to comply with system-wide annual NOx emissions caps starting in 2004; to meet seasonal system average emissions rate targets in 2008; and to pay civil penalties and perform supplemental environmental projects in and around the Potomac River plant expected to achieve additional environmental benefits. Except for the installation of the controls planned for the Potomac River units and the installation of selective catalytic reduction (“SCR”) or equivalent technology at Mirant Mid-Atlantic’s Morgantown Units 1 and 2 in 2007 and 2008, the consent decree does not obligate the Mirant entities to install specifically designated technology, but rather simply to reduce emissions sufficiently to meet the various NOx caps. Moreover, as to the required installations of SCRs at Morgantown, Mirant Mid-Atlantic may choose not to install the technology by the applicable deadlines and leave the units off either permanently or until such time as the SCRs are installed. The aggregate amount of the civil penalties to be paid and costs to be incurred by Mirant Potomac for the supplemental environmental projects is $1.5 million. The consent decree is subject to the approval of the district court and the Bankruptcy Court.

New York Lovett CAMF. The New York State Department of Environmental Affairs issued a notice of violation for the improper closure techniques used on the closure of the coal ash management facility at

Mirant Lovett. This issue is being resolved with the State of New York and may require repair work to be undertaken on the cover.

New York Dissolved Oxygen. Mirant New York is working with the New York State Department of Environment Affairs to settle a consent order that would require us to install equipment to enable us to comply with dissolved oxygen level requirements at the New York Hydro facilities.

Other Governmental Proceedings

Department of Justice Inquiries. In 2002, we were contacted by the DOJ regarding our disclosure of accounting issues, energy trading matters and allegations contained in an amended complaint filed in securities litigation pending against us that we improperly destroyed certain electronic records related to its activities in California. We have been asked to provide copies of the same documents requested by the SEC in their investigation described below in “Securities and Exchange Commission Investigation,” and we have been, and intend to continue, cooperating fully. The DOJ has advised us that it does not intend to take further action with respect to the allegations of improper destruction of electronic records.

In November 2002, we received a subpoena from the DOJ, acting through the United States Attorney’s office for the Northern District of California, requesting information about our activities and those of its subsidiaries for the period since January 1, 1998. The subpoena requested information related to the California energy markets and other topics, including the reporting of inaccurate information to the trade press that publish natural gas or electricity spot price data. The subpoena was issued as part of a grand jury investigation. We have continued to receive additional requests for information from the United States Attorney’s office, and we intend to continue to cooperate fully with the United States Attorney’s office in this investigation.

Securities and Exchange Commission Investigation. In August 2002, we received a notice from the Division of Enforcement of the Securities and Exchange Commission (“SEC”) that it was conducting an investigation of us. The Division of Enforcement has asked for information and documents relating to various topics such as accounting issues (including accounting issues we announced on July 30, 2002 and August 14, 2002), energy trading matters (including round trip trades), our accounting for transactions involving special purpose entities, and information related to shareholder litigation. In late June 2003, the Division of Enforcement advised us that its investigation of Mirant had become a formal investigation in February 2003. We intend to continue to cooperate fully with the SEC.

Department of Labor Inquiries. On August 21, 2003, we received a notice from the Department of Labor (the “DOL”) that it was commencing an investigation pursuant to which it was undertaking to review various documents and records relating to our 401(k) Plans. The DOL also has interviewed our personnel regarding those plans. We will continue to cooperate fully with the DOL.

CFTC Inquiry. In 2002, the Commodity Futures Trading Commission (“CFTC”) asked Mirant Americas Energy Marketing for information about certain buy and sell transactions occurring during the period from January 1, 1999 through June 17, 2002. Mirant Americas Energy Marketing provided information regarding such trades to the CFTC, none of which it considers to be wash trades. In March 2003, Mirant Americas Energy Marketing received a subpoena from the CFTC requesting a variety of documents and information related to Mirant Americas Energy Marketing’s trading of electricity and natural gas and its reporting of transactional information to energy industry publications that prepare price indices for electricity and natural gas in the period from January 1, 1999 through the date of the subpoena. In December 2004, Mirant and Mirant Americas Energy Marketing entered into a settlement with the CFTC that resolves the CFTC’s inquiry into whether Mirant Americas Energy Marketing misrepresented natural gas trading information in 2000 and 2001. Pursuant to the settlement, Mirant and Mirant Americas Energy Marketing consented to the entry of an order by the CTFC in which it makes findings, which are neither admitted or denied by Mirant and Mirant Americas Energy Marketing, that (1) from January 2000

through December 2001, certain Mirant Americas Energy Marketing natural gas traders (i) knowingly reported inaccurate price, volume, and/or counterparty information regarding natural gas cash transactions to publishers of natural gas indices; and (ii) inaccurately reported to index publishers transactions observed in the market as Mirant Americas Energy Marketing transactions and (2) from January to October 2000, certain Mirant Americas Energy Marketing west region traders knowingly delivered the false reports in an attempt to manipulate the price of natural gas. Under the settlement, the CFTC received a subordinated allowed, unsecured claim against Mirant Americas Energy Marketing of $12.5 million in the Chapter 11 proceedings.

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

None.

PART II

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

Common Stock

Our common stock is presently being quoted, and has been quoted since July 16, 2003, on the Pink Sheets Electronic Quotation Service (“Pink Sheets”) maintained by Pink Sheets LLC for the National Quotation Bureau, Inc. Certain restrictions in trading are imposed under a Bankruptcy Court order that requires certain direct and indirect holders of claims, preferred securities and common stock to provide at least ten days advance notice of their intent to buy or sell claims against the Mirant Debtors or shares in Mirant Corporation. The ticker symbol MIRKQ has been assigned to our common stock for over-the-counter quotations. As of February 25, 2005, we had 143,308 holders of record. Prior to July 15, 2003, our common stock was listed under, and traded on, the New York Stock Exchange (“NYSE”). As a result of our filing on July 14, 2003 of a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code, on July 15, 2003, our common stock was suspended from trading by the NYSE and, thereafter, delisted by the NYSE. The following table sets forth (1) the high and low sales prices for our common stock as reported on the NYSE for the first and second quarters of 2003, and (2) the quarterly high and low bid quotations for our common stock as reported on the Pink Sheets for the third and fourth quarter of 2003 and all quarters of 2004. These quotations reflect inter-dealer prices, without retail markup, markdown or commissions, and may not necessarily represent actual transactions.

	Market	High		Low
2003
First Quarter	NYSE	$	2.90	$	1.13
Second Quarter	NYSE	$	3.90	$	1.48
Third Quarter	Pink Sheets	$	0.75	$	0.19
Fourth Quarter	Pink Sheets	$	0.63	$	0.26
2004
First Quarter	Pink Sheets	$	0.75	$	0.40
Second Quarter	Pink Sheets	$	0.40	$	0.26
Third Quarter	Pink Sheets	$	0.48	$	0.30
Fourth Quarter	Pink Sheets	$	0.41	$	0.31

Dividends

We will retain any future earnings to fund our operations and meet our cash and liquidity needs. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future.

Under the proposed Plan, our existing common stock would be cancelled upon our emergence from bankruptcy and our current equity holders would then receive any surplus value after creditors are paid in full and junior interests in the trust formed under the proposed Plan plus the right to a pro rata share of warrants issued by the new company (“New Mirant”) if they vote to accept the proposed Plan (warrants would give each holder the right to purchase New Mirant shares at a set price within a certain period of time). The amount equity holders will receive, if anything, will be determined by the Bankruptcy Court in a valuation hearing to commence in mid-April 2005. Accordingly, we urge that appropriate caution be exercised with respect to existing and future investments in our securities.

The Mirant Trust I trust preferred stock is presently being quoted on the Pink Sheets under the ticker symbol MIRPQ. These trust preferred securities are obligations of the Mirant Trust I and, as such, are not direct obligations of Mirant Corporation. As a result, they are not addressed specifically as part of the proposed Plan. Mirant Trust I holds $356 million in aggregate principal amount of junior unsecured

convertible debentures of Mirant Corporation, the principal and interest on which are pledged to the payment of the trust preferred securities. Mirant Trust I has agreed that these debentures are subordinated to certain “senior indebtedness” of Mirant Corporation, including indebtedness under the respective credit facilities and debt securities of Mirant Corporation. If all senior indebtedness is paid in full, the holders of the subordinated debentures would receive payments up to their aggregate principal amount, if available.

Item 6. Selected Financial Data

The following discussion should be read in conjunction with our consolidated financial statements and the notes thereto, which are included elsewhere in this Form 10-K. The following table presents our selected consolidated financial information, which is derived from our consolidated financial statements. The financial information for the periods prior to our separation from Southern Company on April 2, 2001 does not necessarily reflect what our financial position and results of operations would have been had we operated as a separate, stand-alone entity during those periods.

The following selected financial information should also be read considering that until August 10, 2000, the date of our acquisition of Vastar Resources Inc.’s 40% interest in Mirant Americas Energy Marketing, we accounted for this joint venture under the equity method of accounting. Effective August 10, 2000, Mirant Americas Energy Marketing became a wholly-owned consolidated subsidiary of Mirant.

	Years Ended December 31,
	2004			2003			2002			2001			2000
	(In millions except per share data)
Statement of Operations Data:
Operating revenues	$	4,572		$	5,162		$	4,703		$	7,208		$	3,951
(Loss) income from continuing operations	(410		)	(3,632		)	(2,340		)	465			300
(Loss) income from discontinued operations	(66		)	(174		)	(98		)	(56		)	30
Cumulative effect of changes in accounting principles	—			(29		)	—			—			—
Net (loss) income	(476		)	(3,835		)	(2,438		)	409			330
(Loss) earnings per share:
From continuing operations	$	(1.01	)	$	(8.97	)	$	(5.82	)	$	1.36		$	1.03
From discontinued operations	(0.16		)	(0.43		)	(0.24		)	(0.16		)	0.11
From cumulative effect of changes in accounting principles	—			(0.07		)	—			—			—
Net (loss) income	$	(1.17	)	$	(9.47	)	$	(6.06	)	$	1.20		$	1.14

	As of December 31,
	2004			2003			2002		2001		2000
Balance Sheet Data:
Total assets	$	11,424		$	12,333		$	19,423	$	22,043	$	24,136
Total long-term debt	1,375			1,538			8,822		8,435		5,596
Liabilities subject to compromise	9,211			9,077			—		—		—
Subsidiary obligated mandatorily redeemable preferred securities	—			—			—		—		950
Company obligated mandatorily redeemable securities of a subsidiary holding solely parent company debentures	—			—			345		345		345
Stockholders’ (deficit) equity	(1,318		)	(823		)	2,955		5,258		4,164

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

Executive Summary

Overview

We operate as a debtor-in-possession under the jurisdiction of the Bankruptcy Court in accordance with Chapter 11 of the Bankruptcy Code. As a result, our financial statements include the results of Bankruptcy Court actions, probable claims against our estate and professional and administrative costs related to the bankruptcy process.

In 2004, we allocated a substantial amount of resources to bankruptcy restructuring, which includes resolving claims disputes and contingencies, determining enterprise value and capital structure and negotiating a plan of reorganization with the Statutory Committees. In addition to financial restructuring activities, we are preparing to operate after our emergence from Chapter 11 protection. We currently plan to emerge from Chapter 11 in mid-2005. On January 19, 2005, we filed our proposed Plan with the Bankruptcy Court.

In general, it is our current view that the U.S. electricity markets have excess generation capacity. Additionally, generation capacity is expected to exceed combined demand levels and reserve generation targets through 2008 to 2010 for most major markets. This market situation has the potential to result in continued narrow fuel to electricity conversion spreads. In this environment, customers typically transact over shorter durations and rely more heavily on spot markets to meet their energy needs, thus making it more difficult for us to sell our power for longer-term durations and at prices that provide a reasonable return, most notably on our gas fired units.

For our U.S.-based generation business, changing commodity prices can result in volatile financial results as these forward power contracts and other derivative instruments do not currently receive cash flow hedge accounting treatment in our financial statements. Instead, these contracts are reflected in our financial statements at fair value, resulting in volatility in our gross margin. Our unrealized gains and losses for each period reflect changes in fair value of commodity contracts not yet settled and the reversal of unrealized gains and losses recognized in previous periods that settled in the current reporting period. We plan to implement cash flow hedge accounting during 2005, which will reduce volatility from these transactions in the income statement.

Our power generation businesses and our integrated utilities in the Philippines and Caribbean continue to provide consistent, stable gross margin and operating cash flows. In general, we expect increased demand levels in the countries in which these businesses operate.

For the years ended December 31, 2004, 2003 and 2002, our gross margin included the following (in millions):

	Years Ended December 31,
	2004			2003			2002
Realized gross margin(1)	$	1,460		$	1,678		$	1,663
TPA amortization	344			426			423
Unrealized gains (losses) on PPAs	168			171			35
Net unrealized losses on asset management, optimization and legacy portfolios(1)	(20		)	(297		)	100
Net unrealized gross margin	148			(126		)	135
Total gross margin	$	1,952		$	1,978		$	2,221

(1) Gross margin for the year ended December 31, 2003 reflects $188 million of unrealized losses offset by $188 million of realized gross margin related to energy contracts terminated by counterparties as a result of our Chapter 11 filings. As a result of the terminations, the unrealized gains on these contracts became realized in the third quarter of 2003.

Financial Performance

We reported an operating loss of $18 million for the year ended December 31, 2004 compared to an operating loss of $2,864 in 2003. The $2,846 million change in operating loss is detailed as follows (in millions):

	Favorable/ (Unfavorable)
Gross margin(1)		$	(26	)
Operations and maintenance(2)		81
Depreciation and amortization		32
Goodwill impairment losses(3)		1,485
Long-lived asset impairment losses(4)		1,339
Other impairment losses and restructuring charges		34
(Loss) gain on sales of assets, net(5)		(99		)
Change in operating loss		$	2,846

(1) Gross margin decreased $26 million in 2004 compared to 2003 primarily due to lower transition power agreement amortization and unrealized losses stemming from an increase in electricity prices partially offset by new rates in Jamaica in 2004 and higher realized margins from increased prices in 2004. The lower transition power agreement amortization is due to the revisions to the contracts as part of a late 2003 settlement and expiration of one of the contracts in 2004.

(2) Operations and maintenance expense decreased by $81 million primarily due to cost cutting efforts, lower bad debt expenses, favorable property tax settlements and write back of a receivable stemming from bankruptcy court actions of one of our customers.

(3) Goodwill impairment losses decreased by $1,485 million in 2004 compared to 2003. In 2003 we wrote off all goodwill related to our North America business of $2,067 million due to lower cash flow prospects of the business. In 2004, we wrote off the remaining goodwill amounts related to our Asia business of $582 million. See “Critical Accounting Policies and Estimates” and Note 8 to our consolidated financial statements contained elsewhere in this report.

(4) Long-lived asset impairment losses decreased by $1,339 million in 2004 compared to 2003. This change is due to the $1,339 million impairment charge in 2003 related to lower cash flow prospects for the North America business. This asset impairment also caused depreciation and amortization expense to decrease in 2004 compared to 2003.

(5) In 2004 we completed the sale of our remaining Canadian natural gas transportation contracts and certain natural gas marketing agreements. As part of the sale agreements, we paid approximately $12 million to a third party to assume approximately $28 million of net liabilities. We recognized a gain of approximately $16 million in connection with the sale of these agreements. In 2004 we recorded a loss on sale of assets of approximately $65 million related to the planned sale of three natural gas combustion turbines that is reflected in the loss (gain) on sales of assets, net in the consolidated statements of operations. In 2003, we had a gain on sale of assets of $46 million primarily related to the sale of gas storage contracts in our Canadian trading operations.

Bankruptcy Considerations

Through the bankruptcy process, we intend to restructure the Company and establish a capital structure that is consistent with the effects of overcapacity and resulting lower margins and reduced cash flow in the competitive power generation business. While in bankruptcy, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities, contract

terminations and rejections, and claims assessments will significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance post-bankruptcy.

In addition, upon emergence from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements as a result of revisions to our operating plans set forth in the proposed Plan and, if required, the impact of revaluing our assets and liabilities by applying fresh start accounting in accordance with Statement of Position 90-7, “Financial Reporting by Entities in Reorganization under the Bankruptcy Code.”

As part of the bankruptcy process, claims are filed with the Bankruptcy Court related to amounts that claimants believe the Mirant Debtors owe them. These claims, except for claims by certain governmental agencies, were required to be filed with the Court by December 16, 2003 (March 12, 2004 for claims against the Chapter 11 estates of Mirant Americas Energy Capital and Mirant Americas Energy Capital Assets). In the absence of a specific Bankruptcy Court order providing otherwise, all governmental agencies were required to file claims with the Bankruptcy Court by January 12, 2004 (May 17, 2004 for claims against the Chapter 11 estates of Mirant Americas Energy Capital and Mirant Americas Energy Capital Assets). See “Critical Accounting Policies and Estimates” for additional information.

On January 19, 2005, we filed a proposed Plan and Disclosure Statement in the Bankruptcy Court. For further discussion, see Item 1 contained elsewhere in this report.

Business Review and Market Environment

North America

Given our current view of the market, certain of our U.S. generating assets will need to overcome several hurdles to remain operational. The following is a summary of our key strategic initiatives.

In the Northeast region, certain power plants that are adversely impacted by overcapacity in the region and significant environmental capital expenditure requirements may be permanently shutdown or mothballed if current conditions persist or we are unsuccessful in reaching an agreement on a regulatory solution. Another significant issue in the Northeast region is our New York property tax disputes at Lovett and Bowline power plants. See Note 15 to our consolidated financial statements for additional information. At our current tax rates, these New York power plants are forecast to have negative operating cash flows. Without substantial tax relief, we will likely sell, permanently shutdown or abandon these plants. In addition, our New York power plants face a challenging operating environment due to poor supply/demand fundamentals.

In the Mid-Atlantic region, our historical financial results include significant non-cash revenue from the amortization of the then-fair values of the TPA liabilities assumed as part of our acquisition of generation assets from PEPCO. This non-cash revenue comprised approximately 29%, 35% and 29% of the gross margin of our North America segment for the years ended December 31, 2004, 2003 and 2002, respectively. One of the TPAs expired in June 2004 and the remaining TPA expired in January 2005. Since the expiration of the TPA, Mirant Americas Energy Marketing has been economically hedging the output of the Mid- Atlantic portfolio, extending into 2006, in the bilateral market and by entering into structured transactions.

In the West region, litigation related to our RMR contract in California represents a significant contingency that could result in sale or other disposition of some or all of our RMR units. On January 19, 2004, we entered into a settlement agreement related to these contracts that is discussed under “California Settlement” in Note 15. The settlement is subject to the approval of the FERC and the Bankruptcy Court.

In the Mid-Continent region, we are working to either extend our current contracts or enter into new contracts after their expiration dates between May 2004 and May 2014 at our generating facilities in Florida and Georgia. We are also working to open new channels to realize value from our plants in Michigan and Indiana through contracts with other utilities.

We currently expect to permanently or temporarily shutdown generating plants with a total capacity of 1,592 MW over the next five years. Additionally, we do not expect to independently complete our four suspended construction projects that consist of 2,188 MW of generating capacity and will either pursue partnerships to complete these projects or to, sell or abandon them. During 2004, we mothballed the Wrightsville generating facility. In February 2005, we entered in an agreement to sell the Wrightsville facility to Arkansas Electric Cooperative Corporation, subject to Bankruptcy Court approval and certain other regulatory and third-party consents and approvals. We expect the sale of the Wrightsville facility to close in 2005.

In response to the current market conditions, we instituted two cost reduction programs, the Corporate Overhead Initiative (“COI”) and the Operations Performance Initiative (“OPI”) that were completed in 2004. These reductions are included in the forecasts contained in the proposed Plan. COI, an initiative undertaken by the Company to find efficiencies and cut costs where reasonable to do so, is intended to result in forecasted Company-wide savings of $35 million in 2005 and $52 million in 2006 and beyond for both the Corporate and North America segments. OPI is an initiative undertaken by the Company to reduce costs and enhance gross margins in the United States and Jamaica. For North America, the forecasts incorporate expected operational improvements of approximately $176 million per year through 2011. For Jamaica, the forecasts assume savings of approximately $2 million in 2005 and approximately $4 million per year from 2006 through 2009.

International

Our international operations include integrated utilities and generating companies with long-term contracts in cooperation with local governments, which provide more stable earnings and cash flow than our North America business. Our core initiatives for our international businesses include the following:

· continue to perform on our NPC contracts in the Philippines;

· manage regulatory, political and customer relationships;

· reduce the system electricity losses at JPS as part of our continuous improvement efforts;

· add additional generation capacity; and

· expand our energy supply business in the Philippines from available, but uncontracted, generation capacity.

Results of Operations

The following discussion of our performance is organized by reportable operating segment, which is consistent with the way we manage our business. Beginning January 1, 2004, we changed our allocation methodology related to our corporate overhead expenses. As a result, substantially all of our corporate operating expenses are allocated to our North America and International segments. The new methodology allocates costs using several methods but is primarily based on gross margin, property, plant and equipment balances and labor costs. Our allocation methodology may be subject to further change during the Chapter 11 process.

North America

Our North America segment consists primarily of electricity generation (approximately 14,000 MW of generating capacity) and energy trading and marketing activities managed as a combined business. The following table summarizes the operations of our North America segment for the years ended December 31, 2004, 2003, and 2002 (in millions):

	Years Ended December 31,
	2004		2003			Increase/ (Decrease)				2003			2002			Increase/ (Decrease)
Operating Revenues:
Generation	$	3,486	$	4,138			$	(652	)	$	4,138		$	3,352			$	786
Net trading revenues	36		(1		)		37			(1		)	341				(342		)
Total operating revenues	3,522		4,137				(615		)	4,137			3,693				444
Cost of fuel, electricity and other products	2,326		2,904				(578		)	2,904			2,254				650
Gross margin	1,196		1,233				(37		)	1,233			1,439				(206		)
Operating Expenses:
Operations and maintenance	730		701				29			701			770				(69		)
Depreciation and amortization	165		200				(35		)	200			149				51
Goodwill impairment losses	—		2,067				(2,067		)	2,067			—				2,067
Long-lived asset impairment losses	—		1,338				(1,338		)	1,338			509				829
Other impairment losses and restructuring charges	9		19				(10		)	19			270				(251		)
Loss (gain)on sales of assets, net	50		(38		)		88			(38		)	(5		)		(33		)
Total operating expenses	954		4,287				(3,333		)	4,287			1,693				2,594
Operating (loss) income	$	242	$	(3,054	)		$	3,296		$	(3,054	)	$	(254	)		$	(2,800	)

The following table summarizes gross margin by region for our North America segment for the years ended December 31, 2004, 2003 and 2002 (in millions):

	Years Ended December 31,
	2004			2003			Increase/ (Decrease)				2003			2002			Increase/ (Decrease)
Mirant Americas Generation:
Northeast	$	242		$	143			$	99		$	143		$	163			$	(20	)
Mid-Atlantic	424			352				72			352			469				(117		)
West	164			183				(19		)	183			334				(151		)
Other North America generation	170			179				(9		)	179			151				28
TPA amortization	344			426				(82		)	426			423				3
Other, including TPA and PPA losses	(148		)	(50		)		(98		)	(50		)	(101		)		51
Total	$	1,196		$	1,233			$	(37	)	$	1,233		$	1,439			$	(206	)

The following table summarizes capacity factor (average percentage of full capacity used over a year) by region for our North America segment for the years ended December 31, 2004 and 2003:

	Years Ended December 31,
	2004			2003			Increase/ (Decrease)
Mirant Americas Generation
Northeast		33	%		31	%		2	%
Mid-Atlantic		44	%		45	%		(1	)%
West		19	%		9	%		10	%
Other North America generation		13	%		14	%		(1	)%
Total North America		28	%		23	%		5	%

The following table summarizes power generation volumes by region for our North America segment for the years ended December 31, 2004 and 2003 (in gigawatt hours):

	Years Ended December 31,
	2004	2003	Increase/ (Decrease)
Mirant Americas Generation
Northeast	8,797	8,492		305
Mid-Atlantic	16,461	16,884		(423	)
West	4,880	4,062		818
Other North America generation	5,093	5,637		(544	)
Total	35,231	35,075		156

2004 versus 2003

Gross Margin. Gross margin decreased by $37 million primarily due to the following:

· Northeast operations gross margin increased $99 million primarily due to the following:

· An increase of $36 million related to net unrealized gains on derivative instruments of approximately $24 million in 2004 compared to $12 million in net unrealized losses in 2003;

· An increase of $27 million due to certain events that occurred in the first half of 2003, such as certain forced outages and transmission line problems that did not recur in 2004;

· An increase of $22 million in our realized economic hedging margin due to the impact of 2003 short positions on power in a market where prices for power were rising; and

· An increase of $6 million due to the sale of surplus emission allowances.

· Mid-Atlantic operations gross margin increased $72 million primarily due to the termination in April 2003 of an intercompany capacity and energy agreement with our Mirant Americas Energy Marketing subsidiary. As a result of the intercompany agreement, approximately $94 million of Mid-Atlantic gross margin for the year ended December 31, 2003 is included in other gross margin. This agreement ended May 1, 2003. Excluding the impact of this agreement, Mid-Atlantic operations gross margin would have been $22 million lower in 2004 than in 2003, primarily due to the following:

· An increase of approximately $46 million driven by higher market prices for power;

· An increase of $46 million related to an increase in prices for capacity and ancillary services;

· A decrease of approximately $68 million related to net unrealized losses on derivative contracts for future periods. Of these contracts, $58 million related to power and $10 million related to

oil and gas, and were entered into to economically hedge a portion of the energy price risk related to future Mid-Atlantic operations. The decrease in value of these energy derivative contracts is due to an increase in forward power prices;

· A decrease of $20 million related to a higher emissions expense due mainly to higher prices for SO2 emissions allowances;

· A decrease of $14 million related to a reduction in realized gains on economic fuel hedges; and

· A decrease of $11 million related to the termination of contracts in 2004.

· West operations reflect lower gross margin for our generation units in California and Texas. In California, gross margin decreased by approximately $3 million primarily due to a decrease in gains on realized economic hedges of $22 million as a result of reduced economic hedging activity offset by $18 million of savings on gas reservation charges following a contract rejection. In Texas, gross margin decreased by $16 million primarily due to lower energy prices and a new tolling agreement that began in August 2004 with a third party that is at lower prices than what these units received under a prior agreement with Mirant Americas Energy Marketing.

· Non-cash revenue related to the amortization of the TPAs decreased by $82 million primarily due to the expiration of one of the two TPAs in June 2004 and the impact of a late contract change in 2003. The second TPA expired in January 2005.

· Other gross margin decreased by $98 million primarily resulting from $94 million of gross margin in 2003 received from the market for power at higher prices than the fixed prices paid under an intercompany capacity and energy agreement with Mirant Mid-Atlantic. As a result, approximately $94 million of Mid-Atlantic gross margin for the year ended December 31, 2003 is included in other gross margin. This agreement ended May 1, 2003. Other gross margin also includes our realized losses under the TPAs and the realized and unrealized gains and losses under the power purchase agreements with PEPCO.

Operating Expenses. Operating expenses decreased by $3,333 million due to the following factors:

· A decrease of $2,067 million for goodwill impairment charges is related to the impairment of goodwill in 2003 associated with our North America operations. For further discussion, see “Critical Accounting Policies and Estimates” and Note 8 to our consolidated financial statements contained elsewhere in this report;

· A decrease of $1,338 million for long-lived asset impairment losses is due to an impairment recorded in 2003 for our turbines, power islands and other project costs. For further discussion, see “Critical Accounting Policies and Estimates” and Note 7 to our consolidated financial statements contained elsewhere in this report;

· A decrease of $10 million in other impairment losses and restructuring charges is primarily due to additional cost reductions in 2003 related to costs to cancel equipment orders and service agreements along with workforce reduction and other employee termination-related charges;

· An increase of $29 million in operations and maintenance expense is primarily due to the following:

· An increase of $87 million in corporate costs allocated to the North America segment in the 2004 period. Corporate expenses allocated were $176 million for the year ended December 31, 2004 compared to $89 million for the same period in 2003. In 2004, we began allocating all costs to business units while in 2003 a fixed charge methodology was used and a significant amount of corporate costs were retained at Corporate;

· An increase of approximately $13 million related to the Commodity Futures Trading Commission settlement in December 2004. See Note 15 to our consolidated financial statements contained elsewhere in this report;

· An increase of $7 million related to the additional rent expense for our Morgantown and Dickerson baseload units as a result of the Bankruptcy Court’s granting the motion compelling Mirant Mid-Atlantic to pay incremental rent. See Note 16 to our consolidated financial statements contained elsewhere in this report for further discussion;

· A decrease of $18 million in operations and maintenance related to a reduction in the allowance related to receivables from Enron of $10 million and $8 million lower property taxes due to settlements related to certain California and New York generation assets;

· A decrease of $32 million related to an energy marketing customer bad debt expense reflected in 2003. In 2003, we recorded a $32 million allowance on a single customer that was not able to pay its receivable balance. We are pursuing various legal remedies for collection, but substantial doubt exists as to recovery; and

· A remaining decrease of $28 million, of which approximately $23 million is primarily related to reduced scope and scale of our energy marketing operations. This reduction is primarily attributable to labor costs due to workforce reductions that occurred in the last quarter of 2003;

· A decrease of $35 million in depreciation and amortization expense was primarily due to lower depreciation expense related to our property, plant and equipment after our $1,338 million impairment of long-lived assets in the fourth quarter of 2003; and

· An increase of $88 million in loss on sales of assets, net primarily relates to a loss of approximately $65 million on the planned sale of three natural gas combustion turbines, offset by a gain of $16 million related to the sale of the remaining Canadian natural gas transportation and certain natural gas marketing contracts. In 2003 the gain on sales of assets of $38 million primarily related to the sale of gas storage contracts in our Canadian trading operations.

2003 versus 2002

Gross Margin. Gross margin decreased by $206 million primarily due to the following:

· Our generation volumes decreased approximately 8% from 38.3 million MWh in 2002 to 35.1 million MWh in 2003. The decrease in generated MWh in 2003 is due primarily to an increase in available capacity in the market relative to demand. As a result of overcapacity of power and increased prices for fuel, spark spreads were narrower in 2003 compared to 2002. These factors negatively impacted our gross margin from generation activities in 2003.

· Northeast operations gross margin decreased $20 million primarily due to an unsuccessful economic hedging strategy related to a short position for power as power prices increased in 2003.

 Mid-Atlantic operations gross margin decreased $117 million primarily due to the following:

· A decrease of $79 million in revenues due to the May 1, 2003 termination of an intercompany agreement with Mirant Americas Energy Marketing. During 2002, these operations received fixed prices for power paid under the intercompany agreement and revenues were $179 million higher than what would have been received from the market. From January 1, 2003 to May 1, 2003 the revenue received under the agreement was $94 million less than what would have been received from the market. For the remainder of 2003, Mid-Atlantic received market prices for power;

· A decrease of $41 million related primarily to higher fuel prices of approximately $30 million and emission allowances of $11 million; and

· An increase of $6 million related to $38 million of realized margin on economic fuel hedges offset by $32 million in net unrealized losses on contracts for future periods.

· Gross margin in our West operations decreased $151 million primarily related to reduced profitability from our California operations due primarily to the expiration of our power sales agreement with DWR in December 2002. In 2003, we converted the units that were contracted under the DWR agreement to RMR Contract Condition 2 of approximately 1,700 MW out of 2,000 MW. Revenues under the DWR agreement were based on the market prices at the time we entered into the agreement of approximately $150/MWh. Under the RMR Contract Condition 2 contracts, revenues are based on a fixed rate of return and the units’ operating costs of operating the unit.

· Gross margin from other North America generation assets increased $28 million primarily resulting from new generation of approximately 1,000 MW put in service during 2003 that earned approximately $36 million in margin and incurred net unrealized losses of $32 million reflected in 2002 offset by decreased generation of existing generation facilities of approximately $44 million.

· Non-cash revenue related to the amortization of the TPAs increased $3 million and is a significant portion of the North America segment operating revenue, gross margin and operating income. One of these contracts expired in June 2004 and the other expired in January 2005.

· Other gross margin increased $51 million primarily due to the following:

· A decrease of $342 million in net trading revenues due to lower trading volumes and the fact that there were fewer counterparties participating in the market or willing to do business with us. Through mid-2003, we reduced our trading activity to limit potential collateral exposure. Subsequent to filing for bankruptcy, we have concentrated on protecting total portfolio value, resizing our business and adjusting our optimization trading activities to comply with our amended Risk Management Policy which limits the commodities we can trade and significantly reduced our VaR limits;

· An increase of $273 million resulting from the intercompany capacity and energy agreement with Mirant Mid-Atlantic. In 2003, $94 million of Mid-Atlantic gross margin was received from the market for power at higher prices than the fixed prices paid compared to $179 million of gross margin paid to the market for power prices lower than the fixed prices paid. This agreement ended May 1, 2003;

· An increase of $136 million in unrealized gains under the power purchase agreements with PEPCO due to an increase in power prices in the PJM market; and

· Other gross margin also includes our realized losses under the TPAs and the realized and unrealized gains and losses under the power purchase agreements with PEPCO.

Operating Expenses: Operating expenses increased by $2,594 million and the following factors were responsible for the change:

· An increase of $2,067 million for goodwill impairment charges is related to the impairment of goodwill associated with our North America operations;

· An increase of $829 million for long-lived asset impairment losses is due to an impairment of approximately $1,338 million recorded in 2003 compared to $509 in 2002 for the impairment of our turbines, power islands and other project costs;

· A decrease of $251 million in other impairment losses and restructuring charges is primarily due to $270 million recorded in 2002 compared to $19 million in 2003 related to costs to cancel equipment orders, service agreements, severance costs and other employee termination-related charges;

· A decrease of $69 million in operations and maintenance expense is due primarily to cost reduction initiatives as part of our effort to downsize our organization. This decrease is partially offset by increased operations and maintenance expense as a result of our net generation capacity additions in Indiana, Michigan, Florida, Oregon and Nevada in 2003. Operations and maintenance expense includes such costs as plant operations and maintenance, administrative expenses, such as consulting, accounting and legal fees, and property taxes;

· An increase of $51 million in depreciation and amortization expense was primarily a result of additional depreciation from generation capacity additions in 2003 and the recognition of a full year of depreciation in 2003 for those new units that were completed during 2002; and

· An increase of $33 million in gain on sale of assets, net is primarily related to the sale of gas storage in our Canadian trading operations in 2003.

International

Our International segment consists of our ownership interest in power generating operations in the Philippines, Curacao and Trinidad and Tobago and our ownership interest in integrated utilities in Jamaica and the Bahamas. The following table summarizes the operations of our International businesses for the years ended December 31, 2004, 2003 and 2002 (in millions):

	Years Ended December 31,
	2004			2003		Increase/ (Decrease)				2003		2002			Increase/ (Decrease)
Operating Revenues:
Generation	$	477		$	502		$	(25	)	$	502	$	525			$	(23	)
Integrated utilities and distribution	573			523			50			523		485				38
Total operating revenues	1,050			1,025			25			1,025		1,010				15
Cost of fuel, electricity and other products	294			280			14			280		228				52
Gross margin	756			745			11			745		782				(37		)
Operating Expenses:
Operations and maintenance	295			257			38			257		322				(65		)
Depreciation and amortization	122			116			6			116		116				—
Goodwill impairment losses	582			—			582			—		697				(697		)
Long-lived asset impairment losses	—			1			(1		)	1		101				(100		)
Other impairment losses and restructuring charges	1			13			(12		)	13		65				(52		)
Loss (gain) on sales of assets, net	2			1			1			1		(36		)		37
Total operating expenses	1,002			388			614			388		1,265				(877		)
Operating (loss) income	$	(246	)	$	357		$	(603	)	$	357	$	(483	)		$	840

The following table summarizes capacity factor (average percentage of full capacity used over a year) by operations for our International segment for the years ended December 31, 2004 and 2003:

	Years Ended December 31,
	2004			2003			Increase/ (Decrease)
International
Philippines		44	%		43	%		1	%
Caribbean		50	%		49	%		1	%

The following table summarizes power generation volumes by operations for our International segment for the years ended December 31, 2004 and 2003 (in gigawatt hours):

	Years Ended December 31,
	2004	2003	Increase/ (Decrease)
International:
Philippines	7,021	6,973		48
Caribbean	8,250	8,021		229

2004 versus 2003

Gross Margin. Our gross margin increased $11 million primarily due to the following:

· An increase of $50 million in integrated utilities and distribution primarily due to higher energy sales and fuel-related revenues, and regulatory approved rate increases in non-fuel tariffs at our Jamaica integrated utility in 2004;

· A decrease of $25 million in generation revenue primarily due to a reduction of $16 million related to assets that were no longer owned, operated or consolidated in 2004 that were included in 2003 results and lower nominated capacity from Pagbilao as a result of the implementation of the General Framework Agreement (“GFA”) of $3 million; and

· A decrease of $14 million primarily driven by higher commodity fuel prices in 2004 for our Caribbean integrated utilities compared to 2003 offset by a decrease of $9 million in fuel costs related to assets that were no longer owned, operated or consolidated by us in 2004 that were included in 2003 results.

Operating Expenses: Our operating expenses increased by $614 million primarily due to the following factors:

· An increase of $582 million in goodwill impairment represents the impairment of the remaining goodwill related to our Asia operations. See Note 8 to our consolidated financial statements contained elsewhere in this report for further discussion.

· Operations and maintenance expense increased by $38 million primarily as a result of the following:

· An increase of $25 million in corporate costs allocated to the International segment in the 2004 period. Corporate expenses allocated were $37 million for the year ended December 31, 2004 compared to $12 million for the same period in 2003. In 2004, we began allocating all costs to business units while in 2003 a fixed charge methodology was used and a significant amount of corporate costs were retained at Corporate;

· An increase of $9 million related to the estimated hurricane expense at our Caribbean operations;

· An increase of $5 million in operating and maintenance expenses primarily related to our Caribbean operating expenses associated with new vehicle leases, increased bad debt expense and fees associated with the Jamaica rate case filing;

· An increase of $9 million related to an expired and unfulfilled contract obligation provision in 2003; and

· A decrease of $6 million related to assets in Asia that were no longer owned, operated, or consolidated by us in 2004 that were included in the 2003 results;

· A decrease of $12 million in other impairment losses and restructuring charges were related to the severance of employees and other employee termination-related charges.

2003 versus 2002

Gross Margin. Our gross margin decreased by $37 million primarily due to a $10 million decrease resulting from the discontinuance of supplying energy to a major energy supply customer in November 2002 and a $8 million decrease in operating revenue as a result of lower capacity fees under our long-term energy conversion agreement with NPC from our Pagbilao plant in the Philippines. Additionally, our gross margin from our Caribbean operations decreased by approximately $10 million primarily as a result of higher fuel oil costs and increased use of gas turbines in our Jamaica operations.

Operating Expenses: Our operating expenses decreased by $877 million and the following factors were responsible for the change:

· A decrease of $697 million in goodwill impairment in 2002 that was related to our Asia operations;

· A decrease of $100 million in long-lived asset impairment that is related to turbines, power islands and other project costs recorded in 2002;

· A decrease of $52 million in other impairment losses and restructuring charges that is primarily due to restructuring charges of $16 million related to our severance of employees and other employee termination related expenses and $49 million related to costs to cancel equipment orders and service agreements recorded in 2002;

· A decrease of $65 million in operations and maintenance expense that is primarily due to lower compensation expense as a result of our cost cutting efforts and restructuring our business in 2003; and

· A decrease of $37 million in gain on sale of assets, net that is primarily due to a $30 million gain on the sale of our investments in Australia and $6 million of gains on the sale of our investments in Korea and the United Kingdom in 2002.

Corporate

The following table summarizes our corporate expenses for the years ended December 31, 2004, 2003 and 2002 (in millions):

	Years Ended December 31,
	2004			2003			Increase/ (Decrease)				2003			2002		Increase/ (Decrease)
Operating Expenses:
Operations and maintenance	$	(21	)	$	127			$	(148	)	$	127		$	117		$	10
Depreciation and amortization	21			24				(3		)	24			17			7
Other impairment losses and restructuring charges	13			25				(12		)	25			28			(3		)
Gain on sales of assets, net	1			(9		)		10			(9		)	—			(9		)
Operating loss	$	14		$	167			$	(153	)	$	167		$	162		$	5

2004 versus 2003

The corporate operating expenses for the year ended December 31, 2004 represent the amount of costs incurred in excess of billings to subsidiaries during this period. This is a result of two factors. First, we use budgeted costs to determine cost allocations to the operating segments and a one-month lag in allocations to the segment. This creates a timing difference that will be resolved through adjustments to the cost allocation amount in the following period. Second, all cost allocations are reflected in operations and maintenance expense, regardless of the statement of operations classification of the expense incurred by the corporate segment. As a result, depreciation and amortization and other expense items are reflected as reductions of operations and maintenance expense when allocated. This contributes to the negative operations and maintenance expense for the corporate segment but has no impact on the consolidated statements of operations. Before allocations to operating segments, our corporate expenses in total are $44 million lower through December 31, 2004 compared to 2003. This 16% decrease is primarily due to a headcount reduction of approximately 10% as a result of a workforce reduction program in October 2003.

In 2003, certain corporate costs were not allocated to a reporting segment. Beginning January 1, 2004, we changed our allocation methodology related to corporate overhead expenses to better reflect our operating structure. As a result, substantially all of our operating expenses are now allocated to our North America and International segments. The new methodology allocates costs using several methods but is primarily based on gross margin, property, plant and equipment balances, and labor costs.

2003 versus 2002

Operations and maintenance expense increased by $10 million primarily due to increased legal, consulting and accounting fees. Expenses incurred in 2003 included $15 million related to pre-bankruptcy refinancing efforts and $10 million associated with the settlement of certain non-tax qualified pension obligations by purchasing individual annuity contracts in the first quarter of 2003. The increases were somewhat offset by lower compensation expense as a result of our cost cutting and restructuring efforts in 2003.

Other impairment losses and restructuring charges decreased as a result of the severance of 133 employees and other employee termination-related expenses in 2002.

Other Significant Consolidated Statements of Operations Movements

The following table summarizes our consolidated other income and expenses for the years ended December 31, 2004, 2003 and 2002 (in millions):

	Years Ended December 31,
	2004			2003			Increase/ (Decrease)				2003			2002			Increase/ (Decrease)
Other (Expense) Income, net:
Interest expense	$	(130	)	$	(379	)		$	249		$	(379	)	$	(495	)		$	116
Interest rate hedging losses	—			(110		)		110			(110		)	—				(110		)
Gain on sales of investments, net	—			67				(67		)	67			329				(262		)
Equity in income of affiliates	26			33				(7		)	33			168				(135		)
Impairment losses on minority owned affiliates	—			—				—			—			(467		)		467
Interest income	11			24				(13		)	24			38				(14		)
Other, net	68			48				20			48			10				38
Total other (expense) income, net	$	(25	)	$	(317	)		$	292		$	(317	)	$	(417	)		$	100
Reorganization items, net	$	259		$	290			$	(31	)	$	290		$	—			$	290
Provision for income tax	87			126				(39		)	126			949				(823		)
Minority interest	21			35				(14		)	35			75				(40		)
Loss from discontinued operations, net	(66		)	(174		)		108			(174		)	(98		)		(76		)
Cumulative effect of changes in accounting principles, net	—			(29		)		29			(29		)	—				(29		)

2004 versus 2003

Interest expense. Interest expense decreased by $249 million due to the Chapter 11 filings. The accrual of interest expense associated with the debt of the Mirant Debtors, with the exception of West Georgia, was suspended. Therefore, subsequent to the Petition Date, no interest expense related to those obligations was recorded. Contractual interest on liabilities subject to compromise in excess of reported interest was approximately $535 million and $239 for the years ended December 31, 2004 and 2003, respectively.

Interest rate-hedging losses. Interest rate hedging losses of $110 million in 2003 represents the reclassification of interest rate hedging losses from other comprehensive income to interest expense. The reclassification resulted primarily from the suspension of interest payments on the debt associated with the interest rate swaps, pursuant to the Chapter 11 filings.

Other, net. The consolidated statements of operations for the year ended December 31, 2004 reflect a gain of $37 million related to the extinguishment of $83 million of 2.5% convertible debentures due 2021 that were included in liabilities subject to compromise. During 2003, we recorded income of $11 million related to the sale of certain energy marketing contracts.

Reorganization items, net. Reorganization items, net represents expense or income amounts that were recorded in the financial statements as a result of the bankruptcy proceedings.

· For the year ended December 31, 2004, this amount includes:

· $171 million related to estimated damage claims on rejected and amended contracts;

· $110 million in professional and administrative fees;

· $15 million of interest income; and

· $7 million gain related to the emergence of the Mirant Canadian Subsidiaries from creditor protection.

· For the year ended December 31, 2003, this amount includes:

· $241 million related to estimated damage claims on rejected and amended contracts;

· $48 million in professional and administrative fees; and

· $1 million of interest income, net.

Provision for Income Taxes. The consolidated statements of operations for the year ended December 31, 2004 reflect an income tax provision of $87 million. We provide a valuation allowance, where appropriate, for federal, state and foreign income tax purposes. See “Critical Accounting Policies” contained elsewhere in this report for further discussion.

Discontinued Operations. The $66 million loss from discontinued operations for the year ended December 31, 2004 includes Coyote Springs and Wrightsville that were disposed of or are expected to be disposed of in 2005. The $174 million loss from discontinued operations for the year ended December 31, 2003 reflects the generating facilities that were disposed of in 2003. See Note 4 to our consolidated financial statements contained elsewhere in this report for further discussion.

Cumulative Effect of Changes in Accounting Principles. As a result of the consensus on EITF Issue 02-03, all non-derivative energy trading contracts as of January 1, 2003 that existed on October 25, 2002 have been adjusted to historical cost resulting in a cumulative effect adjustment of $26 million, after tax, which was recorded in the first quarter of 2003. Certain of these contracts were reclassified from price risk management liabilities to transition power agreements and other obligations on our consolidated balance sheets. We also adopted SFAS No. 143 effective January 1, 2003 and recognized an after-tax charge of $3 million associated with its implementation.

2003 versus 2002

Interest expense. Interest expense decreased by $116 million due to the Chapter 11 filings. The accrual of interest expense associated with the debt of the Mirant Debtors, with the exception of West Georgia, was suspended. Therefore, subsequent to the Petition Date, no interest expense related to those obligations was recorded. Contractual interest on liabilities subject to compromise in excess of reported interest was approximately $239 million for the year ended December 31, 2003.

Interest rate hedging losses. Interest rate hedging losses of $110 million in 2003 represent the reclassification of realized interest rate hedging losses from Other Comprehensive Income (“OCI”) to interest expense. The reclassification resulted primarily from the suspension of interest payments on the debt associated with the interest rate hedges, pursuant to the Chapter 11 filings.

Gain on sales of investments, net. The gain on sales of investments of $67 million for 2003 resulted from the October 2003 sale of substantially all of our investment in Birchwood. The gain on sales of investments of $329 million for 2002 resulted primarily from the sale of our interest in Bewag in February 2002 and our interest in Shajiao C power project in December 2002. These divestitures are discussed further in Note 10 to our consolidated financial statements contained elsewhere in this report.

Reorganization items, net. Reorganization items, net represents expense or income amounts that were recorded in the financial statements as a result of the bankruptcy proceedings.

For the year ended December 31, 2003, this amount includes:

· $241 million related to estimated damage claims on rejected and amended contracts;

· $48 million in professional and administrative fees; and

· $1 million of interest income, net.

Provision for Income Taxes. The consolidated statements of operations for the year ended December 31, 2003 reflect an income tax provision of $126 million. We currently record a tax provision for foreign income taxes as appropriate but record no tax benefit for losses for federal and state income tax

purposes. In 2003 and 2002, we recorded valuation allowances of $943 million and $1,088 million, respectively, against our net deferred tax assets.

Discontinued Operations. The financial statements for prior periods have been restated to report the revenues and expenses of the components of the Company that were disposed of separately as discontinued operations.

· Loss from discontinued operations in 2003 and 2002 includes the following components of the Company that were disposed of in 2003: Mirant Europe B.V., the Neenah generating facility in Wisconsin, the Tanguisson power plant in Guam and investments held by Mirant Americas Energy Capital and Mirant Canada Energy Capital. Amounts relating to the sale of Coyote Springs 2 and the pending sale of Wrightsville have been reclassified to be reflected in this category.

· Loss from discontinued operations for the year ended December 31, 2002 also includes the operations of Mirant Americas Production Company in Louisiana, MAP Fuels Limited in Queensland, Australia and the State Line generating facility in Indiana which were disposed of in 2002.

Cumulative Effect of Changes in Accounting Principles. As described in Note 2 to our consolidated financial statements contained elsewhere in this report, we reflected the adoption of EITF Issue 02-03 effective January 1, 2003 as a cumulative effect of a change in accounting principle. The net impact was an after-tax charge of $26 million. We also adopted SFAS No. 143 effective January 1, 2003 and recognized an after-tax charge of $3 million associated with its implementation.

Financial Condition

Liquidity and Capital Resources

The matters described in this section relate to future events or expectations and may be significantly affected by the Chapter 11 filings. The Chapter 11 filings have, or may result in, various restrictions on our activities, limitations on financing, the need to obtain Bankruptcy Court approval for various matters and uncertainty as to relationships with vendors, suppliers, customers and others with whom we may conduct or seek to conduct business.

During the pendency of the Chapter 11 proceedings, we and certain of our subsidiaries, including Mirant Americas Generation and Mirant Mid-Atlantic, are participating in an intercompany cash management program approved by the Bankruptcy Court pursuant to which cash balances at Mirant and the participating subsidiaries are transferred to central concentration accounts and, if necessary, lent to Mirant or any participating subsidiary to fund working capital and other needs, subject to the intercompany borrowing limits approved by the Bankruptcy Court. Under the intercompany cash management program, the Bankruptcy Court imposed borrowing limits for intercompany loans among the respective subsidiary sub-groups. In December 2004, the Bankruptcy Court amended the intercompany cash management program to exclude from the intercompany borrowing limits amounts borrowed by Mirant Americas Energy Marketing from the non-Mirant Americas Energy Marketing sub-groups to fund cash collateral posted and cash prepayments made to third parties on account of transactions entered into by Mirant Americas Energy Marketing for the benefit of the members of the non-Mirant Americas Energy Marketing sub-groups. All intercompany transfers by such Mirant entities are recorded as intercompany loans on a junior superpriority administrative basis and are secured by junior liens on the assets of the relevant borrowing group. Upon entering into the debtor-in-possession credit facility described below, the cash balances of the participating Mirant Debtors became subject to security interests in favor of the debtor-in-possession lenders and, upon certain conditions, such cash balances are swept into concentration accounts controlled by the debtor-in-possession lenders.

On November 5, 2003, certain of the Mirant Debtors (the “DIP Borrowers”) entered into a two-year debtor-in-possession credit facility (the “DIP Facility”) providing for borrowings or the issuance of letters of credit in an amount not to exceed the lesser of $500 million or the then-existing “borrowing base.” The borrowing base is the aggregate value assigned to specified power generation assets of the DIP Borrowers that serve as collateral for the DIP Facility. However, upon the occurrence of certain triggering events, including the sale of borrowing base assets or an event that has a material adverse effect on the business, operations or value of a power generation facility, the borrowing base may be revalued or reserves against the borrowing base may be imposed, thus lowering the borrowing base amount. The borrowing base as of December 31, 2004 was $724 million. The borrowing base decreased $48 million in January 2005 following the sale of Coyote Springs and will decrease another $37 million following the proposed sale of Wrightsville. The orders entered by the Bankruptcy Court approving the DIP Facility permit up to $300 million of borrowings, which amount may be increased to $500 million upon written approval of each of the Statutory Committees or further order of the Bankruptcy Court. The DIP Facility also contains an option, exercisable by Mirant or Mirant Americas Generation, to remove Mirant Americas Generation and its subsidiaries as borrowers and obligors under the DIP Facility and reduce the DIP Facility commitment to a maximum of $200 million of borrowings. Borrowings under the DIP Facility are secured by substantially all of the assets of the DIP Borrowers.

Pursuant to the DIP Facility, the DIP Borrowers are subject to a number of affirmative and restrictive covenants, reporting requirements, and, subject to usage, financial covenants. The Company was in compliance with the DIP Facility covenants, or had received affirmative waivers of compliance where compliance was not attained, as of December 31, 2004.

JPS has approximately $131 million of indebtedness maturing in 2006, which amounts are expected to be repayed through a combination of cash flows from its business and the proceeds of additional indebtedness. Mirant Trinidad has approximately $73 million of indebtedness maturing in January 2006, which amounts are expected to be repaid through the proceeds of additional indebtedness. It is anticipated that any refinancing of the indebtedness of Mirant Trinidad will be subject to an extension of the long-term power purchase agreement between PowerGen, in which Mirant Trinidad owns 39%, and Trinidad and Tobago Electricity Commission that extends beyond the term of any new indebtedness.

Total Cash, Cash Equivalents and DIP Facility Availability

The table below sets forth total cash, cash equivalents and availability under the DIP Facility and other credit facilities of Mirant Corporation and its subsidiaries as of December 31, 2004 and 2003, respectively (in millions):

	December 31, 2004			December 31, 2003
Cash and Cash Equivalents:
Debtors:
Mirant Corporation		$	276		$	467
Mirant Americas Generation(1)		167			115
Mirant Mid-Atlantic(1)		247			209
Mirant Americas Energy Marketing		207			161
Other subsidiaries		56			124
Total debtors’ cash and cash equivalents		953			1,076
Non-debtors		532			511
Total cash and cash equivalents		1,485			1,587
Less: Cash required for operating, working capital or other purposes or restricted by subsidiaries’ debt agreements(2)		274			351
Total available cash and cash equivalents		1,211			1,236
Available under DIP Facility		263			279
Total cash, cash equivalents and credit facilities availability		$	1,474		$	1,515

(1) Since filing for protection under Chapter 11, none of the Mirant Debtors have paid dividends nor made capital contributions. As discussed above, Mirant and certain of its subsidiaries, including Mirant Americas Generation and Mirant Mid-Atlantic, are participating in an intercompany cash management program approved by the Bankruptcy Court.

(2) Amounts designated as “Cash required for operating, working capital or other purposes or restricted by subsidiaries’ debt agreements” are estimated amounts. In addition, as of December 31, 2003, such amounts include $92 million held by the Mirant Canadian Subsidiaries that were subject to protection under the CCAA in Canada at that time.

Maintaining sufficient liquidity in our business is crucial in order to mitigate the risk of future financial distress to the Company.

Accordingly, we plan on a prospective basis for the expected liquidity requirements of our business considering the factors listed below.

· Expected collateral posted in support of our business

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

· Effects of market price volatility on fuel pre-payment requirements

· Seasonal and intra-month working capital requirements

· Other unforeseen events

These expected liquidity requirements will affect, among other things, our proposed Plan and any exit financing necessary to emerge from bankruptcy that we may pursue. Under the proposed Plan, it is a condition to consummation of the proposed Plan that we secure a $750 million revolving credit facility.

We expect to incur capital expenditures of approximately $285 million in 2005. Based on expected requirements, we estimate capital expenditures to be approximately $1.6 billion over the next five years. This forecast does not assume any construction of new generating units in the United States during the forecast period. Instead, the current capital expenditure program, which is expected to be funded by operating cash flow, focuses on efficiency, safety, reliability, environmental compliance and contract obligations. In the Philippines, the forecast assumes that the Philippine subsidiaries will make capital expenditures for the purpose of building and upgrading substations and transmission lines in order to support the energy supply business. These capital expenditures are expected to be funded primarily by operating cash flow. Additional capital expenditures are expected for the Philippines primarily for major maintenance and environmental projects at Pagbilao and Sual. In the Caribbean operations, new construction of generating facilities will be necessary to meet the growing energy demands and are expected to be funded by operating cash flow and project financings.

As discussed in “Item 1. Business,” we are subject to extensive environmental regulations. Based on expected requirements and technological advances, we estimate environmental expenditures to be approximately $437 million over the next five years.

We anticipate that our total cash and cash equivalents, together with our debtor-in-possession financing and our exit financing upon emergence from bankruptcy, will be sufficient to fund our operations during the bankruptcy proceedings and beyond.

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

We are in the process of evaluating the Mirant Debtors’ executory contracts in order to determine which contracts will be assumed, assumed and assigned, or rejected. See “Item 1. Business—Overview—Proceedings under Chapter 11 of the Bankruptcy Code.” The table presented below does not include contracts that we have successfully rejected through the bankruptcy process.

Our debt obligations, off-balance sheet arrangements and contractual obligations as of December 31, 2004 are as follows (in millions):

	Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations by Year
	Total		2005		2006		2007		2008		2009		More than 5 years
Long-term debt not included in liabilities subject to compromise	$	1,375	$	206	$	387	$	143	$	98	$	238		$	303
Operating leases	2,781		147		145		144		150		166			2,029
Purchase commitments:
Long-term service agreements	610		26		32		36		46		44			426
Fuel and transportation commitments	741		335		252		111		4		4			35
Power purchase agreements	1,044		211		52		52		52		52			625
Key employee retention payments	5		5		—		—		—		—			—
Other purchase commitments	100		100		—		—		—		—			—
Total excluding pre-petition debt	6,656		1,030		868		486		350		504			3,418
Liabilities subject to compromise	9,211
Total debt obligations, off-balance sheet arrangements and contractual obligations	$	15,867

Long-term debt not included in liabilities subject to compromise includes the current portion of long-term debt and long-term debt on the consolidated balance sheets, which are discussed in Note 12 to our consolidated financial statements contained elsewhere in this report.

Operating leases are off-balance sheet arrangements and are discussed in Note 16 to our consolidated financial statements contained elsewhere in this report. These amounts primarily relate to our minimum lease payments associated with our lease of the Morgantown and Dickerson baseload units.

Long-term service agreements are discussed in Note 16 to our consolidated financial statements contained elsewhere in this report. These amounts represent our total estimated commitments under our long-term service agreements associated with turbines installed or in storage.

Fuel and transportation commitments are discussed in Note 16 to our consolidated financial statements contained elsewhere in this report. These amounts relate primarily to long-term coal agreements and other fuel purchase and transportation agreements. The table above does not include certain contracts which are accounted for as derivatives. The fair value of these contracts is included in price risk management assets or price risk management liabilities on our consolidated balance sheets.

PPAs are discussed in Note 17 to our consolidated financial statements contained elsewhere in this report. These amounts represent the estimated commitments under the PPAs that Mirant assumed in the asset purchase and sale agreement for the PEPCO generating assets. The estimated commitment is based on the total remaining MWh commitment at contractual prices. These contracts are accounted for as derivatives. The fair value of these agreements as of December 31, 2004 is included in liabilities subject to compromise on our consolidated balance sheets. As discussed in Note 3 to our consolidated financial statements contained elsewhere in this report. The Mirant Debtors’ motion to reject the Back-to-Back Agreement related to the PPAs was denied by the federal district court in Texas, as discussed in Note 15 contained elsewhere in this report. In December 2004, we notified PEPCO and the Bankruptcy Court that we are suspending all future payments under the Back-to-Back Agreement absent further order of the Bankruptcy Court. For 2004, the suspended payment amount was $16 million.

On August 11, 2004, the Bankruptcy Court approved the second portion of the Company’s Key Employee Retention Program (“KERP”) which provides for retention payments for approximately 90 employees, both executive and non-executive. Expected payments under this program total approximately $6 million; $1 million of which was previously paid and $5 million of which will be paid in 2005. These amounts are recognized as operations and maintenance expense as earned. Executive payments are contingent upon achievement of certain milestones and include filing a plan of reorganization with the Court, approval of the plan, and confirmation and consummation of the plan.

Other purchase commitments represent the open purchase orders less invoices received related to open purchase orders for general procurement products and services purchased in the ordinary course of business. These include construction, maintenance and labor activities at our generation facilities. The estimated walk away cost related to our construction activities is approximately $7 million as of December 31, 2004.

Liabilities subject to compromise represent liabilities incurred prior to the Petition Date. As discussed in Note 3 to our consolidated financial statements contained elsewhere in this report, the amounts of liabilities subject to compromise represent our estimate of known or potential pre-petition claims that we expect will be resolved in the bankruptcy process. Adjustments to liabilities subject to compromise may result from negotiations with the respective creditors, actions of the Bankruptcy Court, rejection of executory contracts, and the determination as to the value of any such claim or the value of the respective obligor. Included in liabilities subject to compromise is a $189 million contractual obligation stemming from an indemnification agreement related to an asset sale transaction.

Cash Flows

Operating Activities. Cash provided by operating activities increased $90 million in 2004 compared to 2003. The change is detailed as follows (in millions):

	Years Ended December 31,						Increase
	2004			2003			(Decrease)
Cash provided by operating activities excluding working capital and other assets and liabilities	$	277		$	89			$	188
Cash provided (used) for working capital and other assets and liabilities	(206		)	(108		)		(98		)
Net cash provided by (used in) operating activities	$	71		$	(19	)		$	90

Net cash provided by operating activities excluding the effects of working capital was $277 million in 2004 compared to $89 million in 2003. This increase in cash is primarily due to the reduction in cash used to pay interest on Mirant Debtor debts of $255 million related to the bankruptcy filing in July 2003 partially offset by higher cash expenses related to the cost of bankruptcy of $51 million.

In 2004, working capital changes, which are reflected as changes in operating assets and liabilities, required $206 million in cash compared to $108 million of cash required by changes in working capital in 2003. This was primarily due to the following:

· Favorable change in collateral used to support commercial operations in 2004 compared to 2003. Net collateral uses were $121 million in 2004 compared to $242 million in 2003. The $121 million favorable change is due to the decrease in asset related fuel purchases in 2004 and favorable market movements in power and economic fuel hedging in 2004 compared to 2003, and

· Other working capital requirements of $85 million in 2004 compared to other working capital sources of $134 million in 2003. Other working capital requirements for 2004 relate primarily to inventories that have increased due to rising commodity prices, primarily SO2 allowances used in our Mid-Atlantic power plants. Other working capital sources for 2003 relate primarily to receivables outstanding as of December 31, 2003 on energy contracts terminated early by counterparties as a result of our Chapter 11 filings.

Investing Activities. Net cash used in investing activities was $146 million in 2004 compared to $88 million of cash used in 2003. This was primarily due to the following:

· In 2004, we had capital expenditures of $159 million compared to capital expenditures of $493 million in 2003, which included construction projects in Indiana, Nevada and Jamaica and $124 million related to the cancellation of turbine contracts in Europe.

· In 2004, we received $42 million in proceeds from the disposal of three natural gas turbines related to a suspended construction project. In 2003, we received $398 million in proceeds from the sale of assets and minority-owned investments including the sale of substantially all our investment in Birchwood, our Neenah generating facility, Mirant Americas Energy Capital investments, certain Canadian operations and the Tanguisson power plant in Guam. See Note 9 to our consolidated financial statements for more information.

· In 2004, our Philippine business paid $21 million to acquire an additional interest in the Sual project after a minority shareholder exercised its put option. In 2003, we paid $60 million to acquire additional interest in the Pagbilao project after minority shareholders exercised their put options.

· We also paid $12 million to a third party to exit our Canadian natural gas transportation agreements and certain natural gas marketing contracts in 2004.

· Also in 2003 we were repaid $98 million and issued $29 million of notes receivable primarily related to our energy capital business. We had sold the remaining investments in our energy capital business in May and August of 2003.

Financing Activities. Net cash used in financing activities was $27 million in 2004 compared to cash used in financing activities of $18 million in 2003. This was primarily due to the following:

· Proceeds from issuance of debt were $376 million in 2004 compared to $355 million in 2003. Of the $376 million, $318 million represented letters of credit being drawn upon by counterparties and banks in 2004. The drawing of Mirant Debtor letters of credit creates a liability subject to compromise. The remaining amount of the increase is offset by the increase in the debt service reserve described below. The remaining debt proceeds of $58 million in 2004 were related to our Caribbean operations.

· Cash provided by financing activities in 2004 reflects repayments of long-term debt of $218 million primarily related to our Philippine operations of $159 million and to our Caribbean operations of $56 million.

· In 2004, cash deposited in the debt service reserves increased $154 million compared to a decrease of $9 million in 2003. The increase in the cash deposited in debt service reserves is primarily due to $161 million of letters of credit drawn upon in 2004 in our Philippine operations.

· In 2004, we paid $17 million of dividends to minority interest holders, and our Jamaica operations repaid $14 million of short-term debt.

· In 2003, we repaid long-term debt of $300 million, short-term debt of $36 million, purchased $51 million of TIERS certificates and received $5 million in other financing activities.

Critical Accounting Policies and Estimates

The accounting policies described below are considered critical to obtaining an understanding of our consolidated financial statements because their application requires significant estimates and judgments by management in preparing our consolidated financial statements. Management’s estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. We believe that the following critical accounting policies and the underlying estimates and judgments involve a higher degree of complexity than others do. We discussed the selection of and application of these accounting policies with the Audit Committee of the Board of Directors and our independent auditors.

Potential Applicability of Fresh Start Accounting

We may be required, as part of our emergence from bankruptcy protection, to adopt fresh start accounting in a future period. If fresh start accounting is applicable, our assets and liabilities will be recorded at fair value as of the fresh start reporting date. The fair value of our assets and liabilities may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. In addition, if fresh start accounting is required, the financial results of the Company after the application of fresh start accounting will be different than historical trends.

See Note 3 to our consolidated financial statements for further information on our accounting while in bankruptcy.

Accounting for Energy Trading and Marketing Activities

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

Our North America businesses use derivatives and other energy contracts to economically hedge our electricity generation assets and to engage in optimization trading activities. We use a variety of derivative contracts, such as futures, swaps and option contracts, in the management of our business. Such derivative contracts have varying terms and durations, or tenors, which range from a few days to a number of years, depending on the instrument.

Most of these activities are reflected in our financial statements at fair value, with changes in fair value recognized currently in earnings. The fair value of these contracts is included in price risk management assets and liabilities in our consolidated balance sheets. A limited number of transactions do not meet the definition of a derivative or are considered normal purchases or normal sales and, therefore, qualify for the use of accrual accounting.

The fair value amounts contained within our consolidated financial statements are estimates based largely on the mid-point of quoted market prices. The mid-point may vary significantly from the bid or ask price for some delivery points. If no active market exists, we estimate the fair value of certain derivative contracts using quantitative pricing models. Our modeling techniques include assumptions for market prices, correlation and volatility, such as using the prices of one delivery point to calculate the price of the contract’s delivery point. The degree of complexity of our pricing models increases for longer duration contracts, contracts with multiple pricing features and off-hub delivery points.

The fair value of price risk management assets and liabilities in our consolidated balance sheets are also impacted by our assumptions regarding interest rate and counterparty credit risk. The nominal value of the contracts is discounted using a forward interest rate curve based on the London InterBank Offered Rate (“LIBOR”). In addition, the fair value of our derivative contracts is reduced to reflect the estimated risk of default of counterparties on their contractual obligations to us.

The amounts recorded as revenue change as estimates are revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control. Because we use derivatives that do not qualify for cash flow or fair value hedge accounting under SFAS 133, our financial statements—including gross margin, operating income, balance sheet ratios and cash flow—are, at times, volatile and subject to fluctuations in value primarily due to changes in energy prices.

Bankruptcy Claims Assessment

See Note 3 to our consolidated financial statements for further information on liabilities subject to compromise and our bankruptcy proceedings.

Our consolidated financial statements include, as liabilities subject to compromise, our estimated pre-petition liabilities and settlements approved by the Bankruptcy Court prior to December 31, 2004. In addition, we also reflect as liabilities subject to compromise the probable claim amounts relating to liabilities for rejected contracts, litigation, accounts payable and accrued liabilities, debt and other liabilities (the “Probable Claims Estimates”). These Probable Claims Estimates require management to estimate the likely claim amount that will be allowed by the Bankruptcy Court prior to the Bankruptcy Court’s ruling on the individual claims. These estimates are based on assumptions of future commodity prices, reviews of claimants’ supporting material and assessments by management and outside experts. We expect that our estimates, although based on the best available information, will change as the claims are resolved in the Bankruptcy Court.

The following table summarizes the claims filed in our Chapter 11 case as of December 31, 2004:

	Total Number of Claims		Total Claims Exposure
			(in millions)
Total claims filed		8,246		$	264,176
Less:
Redundant claims		169		2,250
Claims with basis for objection		6,213		252,649
Total claims		1,864		9,277
Additional scheduled liabilities				35
Total claims exposure				$	9,312

The amount of the claims, net of redundancies and amounts for which we have identified a basis for objection, totals approximately $9 billion, as summarized above. This amount plus approximately $2 billion of estimated liabilities for which claims have not been filed represents the total estimate of current claims exposure against the Mirant Debtors as of December 31, 2004. Of the $11 billion, we have recorded approximately $9 billion as liabilities subject to compromise on our consolidated balance sheet as of December 31, 2004. The most significant components of the $2 billion difference between the net claims exposure and the amount recorded as liabilities subject to compromise relate to litigation and rejected contract claims.

Our estimates may be materially different than the amounts ultimately allowed in the Chapter 11 proceedings. The following is a summary of the procedures we performed to calculate the probable claim amount for each type of claim.

Contract Rejections: We recorded an estimated damage claim amount for those contracts that we have successfully rejected through the Bankruptcy Court process. We calculated the estimated claim amount as the fair value of the rejected contract based on what we believe a willing third party would require us to pay to step into the contract. For certain contracts, these estimates involve long-range commodity price assumptions that are difficult to predict. We estimated the fair value of these contracts using the same procedures used to value our price risk management assets and liabilities in the normal course of business.

Litigation: We assessed our legal exposures through discussions with applicable legal counsel and analysis of case law and legal precedents. We recorded our best estimate of a loss, or the low end of our range if no estimate was better than another estimate within a range of estimates, when the loss was considered probable. For matters that are not probable and/or estimable, we have recorded no liability.

Accounts Payable-Trade: For all invoiced claims for services performed but not reflected in our pre-petition accounts payable on our consolidated balance sheet, we recorded a liability subject to compromise equal to the claim amount. For claims related to services that we cannot verify were performed or claims related to alleged damages resulting from our bankruptcy proceedings, we have not recorded any liability.

Debt: We compared estimated damage claim amounts for our debt and accrued interest obligations to our records and accrued additional administrative and interest expenses for properly supported claims.

Other: Other claims include claims filed across multiple categories such as taxes and employee claims. We recorded our best estimate of the probable allowed claim amount for these claims.

Income Taxes

See Note 13 to our consolidated financial statements for further information on income taxes.

At December 31, 2004, we had a valuation allowance of approximately $2.4 billion primarily related to our U.S. net deferred tax assets. In assessing the recoverability of our deferred tax assets, we consider whether it is likely that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences will be deductible.

As of December 31, 2004, we have approximately $2.8 billion of U.S. federal net operating loss (“NOL”) carryforwards for financial reporting purposes. Similarly, there are approximately $3.9 billion of state net operating loss carryforwards. The ultimate utilization of our NOLs will depend on several factors, such as the amount of our debt that is cancelled through the bankruptcy proceedings and the financial plan contained in the proposed Plan. If a portion of our debt is cancelled in bankruptcy, the amount of the cancelled debt will reduce tax attributes such as our NOLs and tax basis on fixed assets which, depending on our proposed Plan and certain tax elections, could partially or fully utilize the available NOLs. We intend to include an indication in a later amendment to our Disclosure Statement regarding whether NOLs will be available post-bankruptcy and the projected timeframe for utilizing the available NOLs.

We have negotiated a settlement agreement with the Internal Revenue Service (“IRS”) for certain tax liabilities arising from their audit of our federal income tax returns for tax years when we were a subsidiary of Southern Company. This agreement results in an assessment of $39 million including interest. We have provided adequate tax provisions in prior years for the recognition of this liability.

We continue to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. A tax liability has been recorded for certain tax filing positions where our inability to sustain the tax return position is probable and estimable. Such liabilities are based on judgment and it can take many years between the time when a liability is recorded and when the related filing position is no longer subject to question. Management periodically reviews these matters and adjusts the liabilities recorded as appropriate.

Long-Lived Assets

See Note 7 to our consolidated financial statements for further information on long-lived assets.

We evaluate our long-lived assets (property, plant and equipment) and definite-lived intangibles for impairment whenever indicators of impairment exist or when we commit to sell the asset. The accounting standards require that if the sum of the undiscounted expected future cash flows from a long-lived asset or definite-lived intangible is less than the carrying value of that asset, an asset impairment charge must be recognized. The amount of an impairment charge is calculated as the excess of the asset’s carrying value over its fair value, which generally represents the discounted expected future cash flows from that asset or in the case of assets we expect to sell, at fair value less costs to sell.

Our evaluations for impairment require us to apply judgment in estimating future energy prices, environmental and other maintenance expenditures and other cash flows. Our estimates of the fair value of the assets require estimating useful lives and selecting a discount rate that reflects the risk inherent in future cash flows.

If actual results are not consistent with our assumptions used in estimating future cash flows and asset fair values, we may be exposed to additional losses that could be material to our results of operations.

Goodwill and Indefinite-lived Intangible Assets

See Note 8 to our consolidated financial statements for further information on goodwill and indefinite-lived intangible assets.

We evaluate our goodwill and indefinite-lived intangible assets for impairment at least annually and periodically if indicators of impairment are present. An impairment occurs when the fair value of a reporting unit is less than its carrying value including goodwill (Step I). For this test our reporting units are North America, Asia and Caribbean. The amount of the impairment charge, if an impairment exists, is calculated as the difference between the fair value of the reporting unit goodwill and its carrying value (Step II). We perform our annual assessment of goodwill at October 31 and whenever contrary evidence exists as to the recoverability of goodwill.

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

The results of our 2003 analysis indicated that goodwill was impaired related to our North America reporting unit. Accordingly, in the second quarter of 2003, we recorded an impairment charge of approximately $2.1 billion, representing the entire balance of goodwill attributable to our North America reporting unit.

We performed our annual test for goodwill impairment effective October 31, 2004 for our Asia and Caribbean reporting units. The test was based upon the business plan completed in the third quarter of 2004. The combined subjectivity and sensitivity of our assumptions and estimates used in our goodwill impairment analysis could result in a reasonable person reaching a different conclusion regarding those critical assumptions and estimates.

In our Caribbean reporting unit, the fair value of the reporting unit exceeded the carrying value including goodwill at October 31, 2004 by $137 million. The cost of capital rate significantly impacts the fair value of our projected future cash flows in the Caribbean. We used a cost of capital of 11% in determining the present value of our projected future cash flows. The sensitivity of the fair value of our projected future cash flows is such that a 100 basis point change in the cost of capital rate would change the discounted value of our projected future cash flows by approximately $35 million, which still would not indicate an impairment.

In our Asia reporting unit, the Step I analysis determined that the fair value of the reporting unit was less than the carrying value including goodwill at October 31, 2004 by approximately $600 million. The critical assumptions used in our Asia analysis are as follows:

· A 10-year financial plan consistent with the underlying forecast for Asia used in the proposed Plan. For years beyond the financial plan through the BOT agreement dates, we used supplemental projections for gross margin and EBITDA. The 10-year financial plan and the supplemental cash flow information used through the BOT agreements are based on the contractual terms within those agreements.

· Depreciation and amortization expenses were calculated based on the fair value of the underlying assets and a 28-year depreciable life or 15-year intangible amortization life.

· The forecasted cash flows assumed no U.S. taxes and an effective cash tax rate of approximately 42% including Philippine taxes as well as withholding taxes.

· The cash flows from Asia were discounted at 12% weighted average cost of capital. The sensitivity of the fair value of our projected future cash flows is such that a 100 basis point change in the cost of capital rate would change the discounted value of our projected future cash flows by approximately $110 million.

· The 10-year forecasted balance sheet was used for periods through 2014. Certain ratio relationships were used to extend the forecasted balance sheet through the life of the BOT agreements.

· None of the intercompany balances of the Asia reporting unit were assumed to have value or detriment to a third party acquirer. The total net intercompany liability of the Asia reporting unit was approximately $370 million.

The results of our 2004 analysis indicated that goodwill was impaired related to our Asia reporting unit. Accordingly, in the fourth quarter of 2004, we recorded an impairment charge of approximately $582 million, representing the remaining balance of goodwill attributable to our Asia reporting unit.

Pension and Other Post-Retirement Benefits

See Note 14 to our consolidated financial statements for further information on employee benefit plan obligations.

We have various defined benefit plans. We use several statistical methods and other factors to calculate the expenses and liabilities related to these plans. These factors include our assumptions about the discount rate, expected return on plan assets and rate of future compensation increases. In addition, assumptions related to mortality rates and other factors are made by our actuarial consultants to estimate our projected benefit obligation. Estimates used to calculate expenses and liabilities related to these plans may differ significantly from actual results.

Litigation

See “Item 3. Legal Proceedings” and Note 15 to our consolidated financial statements for further information related to our legal proceedings.

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

Factors that Could Affect Future Performance

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

We sell capacity, energy and ancillary services from many of our North America generating facilities into competitive power markets or on a short-term fixed price basis through power sales agreements. The market for wholesale electric energy and energy services is largely based on prevailing market forces, subject to regulatory caps, and, therefore, we are not guaranteed any return on our capital investments through mandated rates. Except where we have entered into longer term fixed price agreements for the output of our power plants, our revenues and results of operations are likely to depend upon prevailing market prices, which are influenced by factors that are beyond our control, including:

· prevailing market prices for fuel oil, coal, natural gas and emissions;

· the extent of additional supplies of electric energy and energy services from our current competitors or new market entrants, including the development of new generating facilities that may be able to produce electricity less expensively than our generating facilities;

· the extended operation of nuclear generating plants and other older power plants beyond their presently expected dates of decommissioning;

· prevailing regulations by the FERC that affect our markets and regulations governing the independent system operators that oversee these markets, including any price limitations and other mechanisms to address some of the volatility or illiquidity in these markets or the physical stability of the system;

· the failure of market rules to develop mechanisms that provide for capacity compensation in markets where the mechanisms do not currently exist;

· actions by regulators, ISOs and other bodies that could prevent capacity and energy prices from rising to the level sufficient for full recovery of long run marginal costs of new entrants when supply/demand equilibrium is reached;

· weather conditions; and

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

In addition, unlike most other commodities, power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, the wholesale power markets are subject to significant price fluctuations over relatively short periods of time and can be unpredictable.

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

The operation of our generating facilities involves various operating risks, including:

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

· interruptions in fuel supply;

· disruptions in the delivery of electricity;

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

· violations of our permit requirements or revocation of permits;

· shortages of equipment or spare parts;

· labor disputes;

· operator errors;

· curtailment of operations due to transmission constraints;

· restrictions on emissions;

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

· catastrophic events such as fires, explosions, floods, earthquakes or other similar occurrences.

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

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

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

Furthermore, we seek to manage market risks and exposure to fluctuating power and fuel prices by entering into forward and other contracts that economically hedge the amount of exposure for our net transactions. As such, the effectiveness of our hedging strategy may be dependent on the amount of collateral available to enter into these hedging contracts, and liquidity requirements may be greater than we anticipate or are able to meet.

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

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

Mirant Americas Energy Marketing engages in price risk management activities related to the sales of electricity and purchases of fuel and our generation businesses receive the income and incur the losses from these activities. Mirant Americas Energy Marketing may use forward contracts and derivative financial instruments, such as futures contracts and options, to manage market risks and exposure to fluctuating electricity, coal, natural gas and oil prices. We cannot provide assurance that these strategies will be successful in managing our price risks, or that they will not result in net losses to us as a result of future volatility in electricity and fuel markets.

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

Additionally, we expect to have an open position in the market, within our established guidelines, resulting from the management of our portfolio. To the extent open positions exist, fluctuating commodity prices can impact financial results and financial position, either favorably or unfavorably. Furthermore, the risk management procedures we have in place may not always be followed or may not always work as planned. As a result of these and other factors, we cannot predict with precision the impact that risk management decisions may have on our businesses, operating results or financial position. Although management devotes a considerable amount of attention to these issues, their outcome is uncertain.

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

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

Our facilities in the Philippines are exposed to significant risks, as a result of their reliance on their contracts with NPC, which purchases almost all of the power generated by those facilities. These risks include political instability, changes in governmental leadership, regulation of the electricity business and the credit quality of the Philippine government. If NPC were to fail to perform its obligations under its energy conversion agreements with us, the resulting loss of cash flow and revenue would have a material adverse affect on our financial condition and results of operations.

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

We are exposed to the risk of fuel and fuel transportation cost increases and volatility and interruption in fuel supply because our facilities generally do not have long-term natural gas, coal and oil fuel supply agreements.

Most of our domestic power generation facilities purchase their fuel requirements under short-term contracts or on the spot market. Although we attempt to purchase fuel based on our known fuel requirements, we still face the risks of supply interruptions and fuel price volatility as fuel deliveries may not exactly match energy sales due in part to our need to prepurchase inventories for reliability and dispatch requirements. The price we can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel costs. This may have a material adverse effect on our financial performance. The volatility of fuel prices could adversely affect our financial results and operations.

Our credit ratings impact our ability to access the capital markets for new borrowings on acceptable terms and our collateral requirements with counterparties. If we are not able to achieve our anticipated rating levels after emergence from Chapter 11 and maintain those levels, our financial condition may be materially adversely affected.

If we are not able to achieve our anticipated credit ratings after emergence from Chapter 11 or if our ratings are lowered significantly from these levels, our business could be materially adversely impacted. For example, significant downgrades could increase negative sentiment and reactions from our customers, regulators, investors, suppliers, lenders or other credit rating agencies, increase pressure on our liquidity and reduce our ability to raise capital on acceptable terms. These reactions could impair our ability to achieve our business plan.

We are exposed to credit risk from third parties under contracts and in market transactions.

Our operations are exposed to the risk that counterparties that owe money as a result of market transactions will not perform their obligations. A facility’s financial results may be materially adversely affected if any one customer fails to fulfill its contractual obligations and we are unable to find other

customers to produce the same level of profitability. As a result of the failure of a major customer to meet its contractual obligations, we may be unable to repay obligations under our debt agreements.

Our operations and activities are subject to extensive environmental regulation and permitting requirements and could be adversely affected by future changes in environmental laws and requirements.

Our business is subject to extensive environmental regulation by federal, state and local authorities, which requires continuous compliance with conditions established by our operating permits. To comply with these legal requirements, we must spend significant sums on environmental monitoring, pollution control equipment and emission allowances. We may also be exposed to compliance risks from plants we have acquired. Although we have budgeted for significant expenditures to comply with these requirements, actual expenditures may be greater than budgeted amounts. If we were to fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. With the trend toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the number and types of assets operated by us subject to environmental regulation, we expect our environmental expenditures to be substantial in the future. Our business, operations and financial condition could be adversely affected by this trend.

In general, environmental laws, particularly with respect to air emissions, are becoming more stringent, which may require us to install expensive plant upgrades or restrict our operations to meet more stringent standards. We cannot always predict the level of capital expenditures that will be required due to changing environmental and safety laws and regulations, deteriorating facility conditions and unexpected events (such as natural disasters or terrorist attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on our financial performance and condition.

We may not be able to obtain from time to time desired environmental regulatory approvals. Such approvals could be delayed or subject to onerous conditions. If there is a delay in obtaining any environmental regulatory approvals or if onerous conditions are imposed, the operation of our generating facilities or the sale of electricity to third parties could be prevented or become subject to additional costs. We generally are responsible for all on-site environmental liabilities. Unless our contracts with customers expressly permit us to pass through increased costs attributable to new statutes, rules and regulations, we may not be able to recover capital costs of complying with new environmental regulations, which may adversely affect our profitability.

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

Currently, our facilities are Exempt Wholesale Generators (EWGs) that sell electricity primarily into the wholesale market. Generally, we are subject to regulation by the FERC regarding the terms and conditions of wholesale service and rates, as well as by state agencies regarding physical aspects of the generating facilities. The majority of our generation is sold at market prices under the market based rate authority granted by the FERC. If certain conditions are not met, the FERC has the authority to withhold or rescind market based rate authority and require sales to be made based on cost of service rates. Such cases are typically settled rather than litigated to completion, adding additional uncertainty to the process. A loss of our market based rate authority could have a materially negative impact on our generation business.

Even where market based rate authority has been granted, the FERC frequently imposes various forms of price and operating restrictions where it determines that market power exists and that the public interest requires such market power to be mitigated. These restrictions are frequently administered via bidding and scheduling rules administered by Independent System Operators (ISOs) and Regional

Transmission Operators (RTOs). In the fall of 2004, PJM completed its integration of AEP and DP&L into the PJM RTO, and AEP and DP&L were deemed to be capable of providing capacity to all areas of PJM. This has severely depressed forward pricing for capacity.

Certain of our assets are located in the Electric Reliability Council of Texas (ERCOT). Such assets are not generally subject to regulation by the FERC, but are subject to similar types of regulation by agencies of the state of Texas. In addition to direct regulation by the FERC and ERCOT, most of our assets are subject to rules and terms of participation imposed and administered by various RTOs and ISOs. While these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business.

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

Currently, the state of California is asserting jurisdiction over EWGs to impose operating and maintenance standards. Included in these standards are certain provisions that would restrict our ability to control economic decisions with regard to the use, ownership transfer and retirement of our assets in California. The state’s ability to legally impose such restrictions is uncertain. However, if the regulations are imposed in their current form, and such imposition withstands any legal challenge that might be undertaken, then our business, financial condition and results of operation may be materially adversely affected.

We cannot predict whether the federal or state legislatures will adopt legislation relating to the restructuring of the energy industry. There are proposals in many jurisdictions to both advance and to roll back the movement toward competitive markets for supply of electricity, at both the wholesale and retail level. In particular, the 109^th United States Congress is expected to consider legislation that could contain provisions that could impair competition in existing or evolving power markets in which we operate, including restrictions on the authority of the FERC under the Federal Power Act. In addition, any legislation resulting in an environment dominated by large, vertically integrated utilities and a concentration of ownership of such utilities, could impact our ability to compete successfully, and our business and results of operations could suffer. We cannot provide assurance that the introductions of new laws, or other future regulatory developments, will not have a material adverse impact on our business, operations or financial condition.

Changes in technology may significantly impact our generation business by making our power plants less competitive.

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

Terrorist attacks, future war or risk of war may adversely impact our results of operations, our ability to raise capital or our future growth.

As power generators, we face above-average risk of an act of terrorism, either a direct act against one of our generating facilities or an inability to operate as a result of systemic damage resulting from an act

against the transmission and distribution infrastructure that we use to transport our power. If such an attack were to occur, our business, financial condition and results of operations could be materially adversely impacted. In addition, such an attack could impact our ability to service our indebtedness, our ability to raise capital and our future growth opportunities.

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

Our operations are subject to many hazards associated with the power generation industry, which may expose us to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in our operations. These hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate, but we cannot assure that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition.

Certain participants in the wholesale power markets are able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation assets without relying exclusively on market clearing prices to recover their investments, which may give them a competitive advantage to us.

Certain participants in the wholesale power markets, including many regulated utilities, enjoy a lower cost of capital than most merchant generators and often are able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation assets without relying exclusively on market clearing prices to recover their investments. This could impact our ability to compete effectively and could have an adverse impact on the revenues generated by our facilities.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risks associated with commodity prices, foreign currency exchange rates and interest rates and to credit risks. Prior to the Petition Date, the Mirant Debtors were also exposed to market risks associated with interest rates on debt that is now classified as liabilities subject to compromise.

Commodity Price Risk

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

The financial performance of our power generating business is influenced by the difference between the cost of converting source fuel, such as natural gas or coal, into electricity, and the revenue we receive from the sale of that electricity. The difference between the cost of a specific fuel used to generate one megawatt hour of electricity and the market value of the electricity generated is commonly referred to as the “spark spread.” Absent the impacts of our asset management activities, the operating margins that we realize are equal to the difference between the spark spread and the cost of operating the plants that produce the electricity sold.

Spark spreads are dependent on a variety of factors that influence the cost of fuel and the sales price of the electricity generated over the longer-term, including spark spreads of additional plant generating capacity in the regions in which we operate, plant outages, weather and general economic conditions. As a result of these influences, the cost of fuel and electricity prices do not always change by the same magnitude or direction, which results in spark spreads widening or narrowing over time.

Through our asset management activities, we enter into a variety of exchange-traded and OTC energy and energy-related derivative contracts, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage our exposure to commodity price risk and changes in spark spreads. These derivatives have varying terms and durations, or tenors, which range from a few days to a number of years, depending on the instrument. Our optimization trading activities also utilize similar contracts in markets where we have a physical presence to attempt to generate incremental gross margin. In addition, our legacy portfolio consists of a variety of energy and energy-related derivative and non-derivative contracts that have been determined to be no longer consistent with our asset management or optimization trading strategies.

Derivative energy contracts required to be reflected at fair value are presented as price risk management assets and liabilities in the accompanying consolidated balance sheets. The net changes in their market values are recognized in income in the period of change. The fair value of the power purchase agreements which we account for as derivatives and which we have attempted to reject are included in liabilities subject to compromise on the accompanying consolidated balance sheets as of December 31, 2004 and 2003.

The determination of fair value considers various factors, including closing exchange or OTC market price quotations, time value, credit quality, liquidity and volatility factors underlying options and contracts.

The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at December 31, 2004 was 1 year. The net notional amount, or net short position, of the price risk management assets and liabilities at December 31, 2004 was approximately 17 million equivalent MWh.

The following table provides a summary of the factors impacting the change in net fair value of the price risk management asset and (liability) accounts in 2004 (in millions).

	Optimization				Asset Management				Legacy				Total
Net fair value of portfolio at December 31, 2003		$	30			$	16			$	(54	)	$	(8	)
(Losses) gains recognized in the period, net		(4		)		(115		)		16			(103		)
Contracts settled during the period, net		(27		)		48				61			82
Other changes in fair value, net		2				—				—			2
Net fair value of portfolio at December 31, 2004		$	1			$	(51	)		$	23		$	(27	)

The fair values of our price risk management assets and liabilities, net of credit reserves, as of December 31, 2004 are included in the following table (in millions).

	Net Price Risk Management Assets/(Liabilities)
	Assets							Liabilities								Net Value at December 31,
	Current				Noncurrent			Current				Noncurrent				2004
Electricity		$	106			$	85		$	(198	)		$	(41	)		$	(48	)
Natural Gas		59				26			(65		)		(20		)		—
Crude Oil		46				1			(23		)		(1		)		23
Other		(2		)		—			—				—				(2		)
Total		$	209			$	112		$	(286	)		$	(62	)		$	(27	)

The following table represents the net price risk management assets and liabilities by tenor as of December 31, 2004 (in millions):

2005	$	(75	)
2006	14
2007	9
2008	8
2009	9
Thereafter	8
Net assets (liabilities)	$	(27	)

In the Philippines, our business is largely conducted through fixed-price, long-term contracts denominated in U.S. dollars, under which the purchaser is responsible for supplying the fuel, thereby mitigating our exposures to both fluctuating commodity prices and foreign currencies in these businesses.

In the Caribbean, our generating facilities either operate as rate regulated integrated utilities, or under long-term power sales agreements which contain energy cost adjustment clauses. These arrangements help mitigate our exposure to fluctuating commodity prices and foreign currencies in these businesses.

Value at Risk

Effective November 5, 2003, we amended our Risk Management Policy to prohibit the trading of certain products (e.g., natural gas liquids and pulp and paper) and to change or clarify limits related to our asset management and optimization trading. As part of this amendment, we established a new value-at-risk (“VaR”) limit with respect to our optimization trading activities of $7.5 million. There is now no VaR limit with respect to our asset management activities, as these activities are only allowable if they reduce the commodity price exposure of our generation assets. We manage the market risks associated with our asset management activities in conjunction with the physical generation assets that they are designed to economically hedge. As a result, in 2004 our asset management portfolio is no longer included in our VaR calculation for purposes of compliance with our Risk Management Policy.

We manage the price risk associated with asset management activities through a variety of methods. To ensure that economic hedge positions are risk reducing in nature, we measure the impact of each asset management transaction executed relative to the overall asset position, including previously executed economic hedge transactions, that it is designed to economically hedge. See “Critical Accounting Policies Estimates” for accounting treatment for asset management and optimization trading activities.

The average VaR for our optimization activities, using various assumed holding periods and a 95% confidence interval, was $2 million for the year ended December 31, 2004 and the VaR as of December 31, 2004 was $2 million. If we assumed VaR levels using a one-day holding period for all positions in our optimization portfolio, based on a 95% confidence interval, our average portfolio VaR for the year ended December 31, 2004 was $1 million and the VaR at December 31, 2004 was $1 million. During the year ended December 31, 2004, the actual daily loss on a fair value basis exceeded the corresponding one-day VaR calculation 8 times, which falls within our 95% confidence interval.

Collection Risk

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

Credit Risk

Credit risk represents the loss that we would incur if a counterparty failed to perform under its contractual obligations. We have established controls and procedures in our Risk Management Policy to determine and monitor the creditworthiness of customers and counterparties. Our credit policies are established and monitored by the Risk Oversight Committee. We measure credit risk as the loss we would record if our customers failed to perform pursuant to the terms of their contractual obligations less the value of collateral held by us, if any, to cover such losses. We manage our portfolio positions such that the average credit quality of the portfolio must fall inside an authorized range. We use published ratings of customers, as well as our internal analysis, to guide us in the process of setting credit levels, risk limits and contractual arrangements including master netting agreements. Where external ratings are not available, we rely on our internal assessments of customers.

Foreign Currency Risk

From time to time, we have used currency swaps and currency forwards to hedge our net investments in certain foreign subsidiaries. Gains or losses on these derivatives are designated as hedges of net investments and are offset against the foreign currency translation gains or losses recorded in OCI relating to these investments. Occasionally, we use currency forwards to offset the effect of exchange rate fluctuations on forecasted transactions denominated in a foreign currency. We do not have any foreign exchange contracts outstanding at December 31, 2004 that are designated as hedges of our investments in foreign countries or otherwise.

Item 8. Financial Statements and Supplementary Data

The information required hereunder is included in this report as set forth in the “Index to Financial Statements” on page F-1.

MIRANT CORPORATION AND SUBSIDIARIES
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Years Ended December 31,
	2004				2003				2002
	(in millions, except per share data)
Operating Revenues:
Generation		$	3,963			$	4,640			$	3,877
Integrated utilities and distribution		573				523				485
Net trading revenue		36				(1		)		341
Total operating revenues		4,572				5,162				4,703
Cost of fuel, electricity and other products		2,620				3,184				2,482
Gross Margin		1,952				1,978				2,221
Operating Expenses:
Operations and maintenance		1,004				1,085				1,209
Depreciation and amortization		308				340				282
Goodwill impairment losses		582				2,067				697
Long-lived asset impairment losses		—				1,339				610
Other impairment losses and restructuring charges		23				57				363
Loss (gain) on sales of assets, net		53				(46		)		(41		)
Total operating expenses		1,970				4,842				3,120
Operating Loss		(18		)		(2,864		)		(899		)
Other (Expense) Income, net:
Interest expense		(130		)		(379		)		(495		)
Interest rate hedging losses		—				(110		)		—
Gain on sales of investments, net		—				67				329
Equity in income of affiliates		26				33				168
Impairment losses on minority owned affiliates		—				—				(467		)
Interest income		11				24				38
Other, net		68				48				10
Total other expense, net		(25		)		(317		)		(417		)
Loss From Continuing Operations Before Reorganization Items, Income Taxes and Minority Interest		(43		)		(3,181		)		(1,316		)
Reorganization Items, net		259				290				—
Provision for Income Taxes		87				126				949
Minority interest		21				35				75
Loss From Continuing Operations		(410		)		(3,632		)		(2,340		)
Loss from Discontinued Operations, net of tax benefit of $1 and $55 in 2003 and 2002, respectively		(66		)		(174		)		(98		)
Loss Before Cumulative Effect of Changes in Accounting Principles		(476		)		(3,806		)		(2,438		)
Cumulative Effect of Changes in Accounting Principles, net of taxes of $1 in 2003		—				(29		)		—
Net Loss		$	(476	)		$	(3,835	)		$	(2,438	)
Loss Per Share:
Basic and diluted:
From continuing operations		$	(1.01	)		$	(8.97	)		$	(5.82	)
From discontinued operations		(0.16		)		(0.43		)		(0.24		)
From cumulative effect of changes in accounting
principles		—				(0.07		)		—
Net loss		$	(1.17	)		$	(9.47	)		$	(6.06	)

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

F-2

MIRANT CORPORATION AND SUBSIDIARIES
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

											Accumulated
				Additional							Other
	Common			Paid-In			Accumulated				Comprehensive				Treasury
	Stock			Capital			Deficit				Loss				Stock
	(in millions)
Balance, December 31, 2001		$	4		$	4,884		$	594			$	(222	)		$	(2	)
Net loss		—			—			(2,438		)		—				—
Other comprehensive income		—			—			—				120				—
Issuance of common stock		—			15			—				—				—
Balance, December 31, 2002		4			4,899			(1,844		)		(102		)		(2		)
Net loss		—			—			(3,835		)		—				—
Other comprehensive income		—			—			—				38				—
Issuance of common stock		—			19			—				—				—
Balance, December 31, 2003		4			4,918			(5,679		)		(64		)		(2		)
Net loss		—			—			(476		)		—				—
Other comprehensive loss		—			—			—				(19		)		—
Balance, December 31, 2004		$	4		$	4,918		$	(6,155	)		$	(83	)		$	(2	)

MIRANT CORPORATION AND SUBSIDIARIES
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

	For the Years Ended
	December 31,
	2004			2003			2002
	(in millions)
Net Loss	$	(476	)	$	(3,835	)	$	(2,438	)
Other comprehensive (loss) income, net of tax
Net change in fair value of derivative hedging instruments	—			(4		)	(16		)
Reclassification of TIERS investment unrealized gains to earnings	(7		)	—			—
Reclassification of derivative net gains to earnings	—			73			41
Cumulative translation adjustment	(17		)	(41		)	109
Share of other comprehensive income of affiliates	—			7			(12		)
Minimum pension liability adjustment	—			—			(2		)
Unrealized gain (loss) on TIERS investments	5			3			—
Other comprehensive (loss) income, net of tax	(19		)	38			120
Total Comprehensive Loss	$	(495	)	$	(3,797	)	$	(2,318	)

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

F-4

MIRANT CORPORATION AND SUBSIDIARIES
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2004			2003			2002
	(in millions)
Cash Flows from Operating Activities:
Net loss	$	(476	)	$	(3,835	)	$	(2,438	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Amortization of transition power agreements and other obligations (non-cash revenue)	(349		)	(449		)	(430		)
Depreciation and amortization	320			359			339
Impairment losses and restructuring charges	639			3,640			2,222
Loss (Gain) on sales of assets and investments	53			(92		)	(362		)
Interest rate hedging losses	—			110			—
Equity in income of affiliates, net of dividends	(7		)	(12		)	(133		)
Non-cash charges for reorganization items	168			260			—
Minority interest	21			(70		)	56
Cumulative effect of changes in accounting principles	—			29			—
Price risk management activities, net	(148		)	126			(135		)
Deferred income taxes	50			46			974
Other, net	6			(23		)	148
Changes in operating assets and liabilities:
Receivables, net	160			809			558
Other current assets	(164		)	49			23
Other assets	23			(84		)	(18		)
Accounts payable and accrued liabilities	(194		)	(787		)	(281		)
Taxes accrued	(22		)	(10		)	119
Other liabilities	(9		)	(85		)	(64		)
Total adjustments	547			3,816			3,016
Net cash provided by (used in) operating activities	71			(19		)	578
Cash Flows from Investing Activities:
Capital expenditures	(159		)	(493		)	(1,512		)
Cash paid for acquisitions	(21		)	(61		)	(111		)
Issuance of notes receivable	—			(29		)	(378		)
Repayments on notes receivable	1			98			209
Proceeds from the sale of assets and minority owned investments	45			398			2,677
Cash paid related to disposition	(12		)	—			—
Other	—			(1		)	(11		)
Net cash (used in) provided by investing activities	(146		)	(88		)	874
Cash Flows from Financing Activities:
(Payments on) proceeds from short-term debt, net	(14		)	(36		)	6
Proceeds from issuance of long-term debt	376			355			2,598
Repayment of long-term debt	(218		)	(300		)	(3,100		)
Repayment of commodity prepay transaction	—			—			(25		)
Purchase of TIERS Certificates	—			(51		)	—
Payment of debt related derivatives	—			—			(60		)
Proceeds from issuance of common stock	—			2			17
Change in debt service reserve fund	(154		)	9			7
Other	(17		)	3			9
Net cash used in financing activities	(27		)	(18		)	(548		)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			6			9
Net (Decrease) Increase in Cash and Cash Equivalents	(102		)	(119		)	913
Cash and Cash Equivalents, beginning of year	1,587			1,706			793
Cash and Cash Equivalents, end of year	$	1,485		$	1,587		$	1,706
Supplemental Cash Flow Disclosures:
Cash paid for interest, net of amounts capitalized	$	117		$	372		$	398
Cash paid (refunds received) for income taxes	$	42		$	(7	)	$	(254	)
Cash paid for reorganization items	$	107		$	56		$	—
Business Acquisitions:
Fair value of assets acquired	$	21		$	61		$	114
Less cash paid	21			61			111
Liabilities assumed	$	—		$	—		$	3

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

F-5

MIRANT CORPORATION AND SUBSIDIARIES
(Debtor-in-Possession)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002

1. Description of Business and Organization

Mirant Corporation (formerly Southern Energy, Inc.) and its subsidiaries (collectively, “Mirant” or the “Company”) is an international energy company incorporated in Delaware on April 20, 1993. Prior to April 2, 2001, Mirant was a subsidiary of Southern Company (“Southern”). The Company’s revenues are primarily generated through the production of electricity in the United States, the Philippines and the Caribbean. As of December 31, 2004, Mirant owned or leased approximately 18,000 MW of electric generating capacity.

Mirant manages its business through two principal operating segments: North America and International. The Company’s North America segment consists of the ownership and operation of power generation facilities and energy trading and marketing operations. The International segment includes power generation businesses in the Philippines, Curacao and Trinidad, and integrated utilities in the Bahamas and Jamaica. In the Philippines, currently approximately 90% of the revenues come from fixed capacity charges under long-term contracts that are paid without regard to the dispatch level of the plant. The Company’s operations in the Caribbean include fully integrated electric utilities, which generate power sold to residential, commercial and industrial customers.

2. Accounting and Reporting Policies

Basis of Presentation

The accompanying consolidated financial statements of Mirant and its wholly-owned subsidiaries have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

The accompanying financial statements include the accounts of Mirant and its wholly-owned, and controlled majority-owned subsidiaries, as well as variable interest entities in which Mirant has an interest and is the primary beneficiary, and have been prepared from records maintained by Mirant and its subsidiaries in their respective countries of operation. All significant intercompany accounts and transactions have been eliminated in consolidation. Investments in minority-owned companies in which Mirant exercises significant influence over operating and financial policies are accounted for using the equity method of accounting. Majority or jointly owned affiliates, which Mirant does not control, as well as interests in variable interest entities in which Mirant is not the primary beneficiary, are also accounted for using the equity method of accounting.

Certain prior period amounts have been reclassified to conform to the current year financial statement presentation. All amounts are presented in U.S. dollars unless otherwise noted.

Use of Estimates

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

F-6

estimating liabilities resulting from the bankruptcy, including the effects of bankruptcy claims and rejected contracts; estimating future cash flows and fair values in recording impairments of long-lived assets, goodwill and indefinite-lived intangible assets; estimating the expected return on plan assets, rate of compensation increases and other actuarial assumptions used in estimating pension and other postretirement benefit plan liabilities; and estimating losses to be recorded for contingent liabilities.

New Accounting Standards

In December 2003, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (“ARB”) No. 51 (“FIN 46R”). FIN 46R addresses the consolidation by business enterprises of variable interest entities (“VIEs”), as defined in FIN 46R. FIN 46R expands existing accounting guidance regarding when a company should consolidate in its financial statements the assets, liabilities and activities of another entity. The consolidation requirements applied immediately to Special Purpose Entities (“SPEs”) in 2003 and to all other VIEs no later than the end of the first reporting period ending after March 15, 2004. At December 31, 2003, the Company deconsolidated Mirant Trust I, an SPE, and began accounting for its interest in Mirant Trust I using the equity method of accounting pursuant to FIN 46R.

As of March 31, 2004, the Company applied the consolidation requirements of FIN 46R to all interests it has in non-SPE VIEs. The effect of the Company’s adoption of FIN 46R with respect to these VIEs was not material to the Company’s consolidated results of operations, cash flows or financial position.

The Company has held a minority equity interest in a non-consolidated VIE since July 2000. The non-consolidated VIE primarily holds an interest in a generation facility and has total assets of approximately $105 million at December 31, 2004. The Company believes that its maximum exposure to loss associated with its interest in the non-consolidated VIE is the Company’s carrying value of its investment in the VIE at December 31, 2004 of approximately $55 million.

New Accounting Standard Not Yet Adopted

In December 2004, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 123R, “Share-Based Payment: an amendment of FASB Statements No. 123 and 95” (“SFAS 123R”), which requires companies to recognize in the income statement the grant-date fair value of stock options and other equity-based compensation issued to employees. The provisions of the interpretation are effective for financial statements issued for periods that begin after June 15, 2005. The Company will use the modified prospective transition method. Under the modified prospective method, awards that are granted, modified or settled after the date of adoption will be measured and accounted for in accordance with SFAS 123R. Compensation cost for awards granted prior to, but not vested as of, the date SFAS 123R is adopted would be based on the grant date, fair value and attributes originally used to value those awards. Due to the Company’s debtor-in-possession status, the Company cannot predict the effect this standard will have on 2005 financial statements.

Revenue Recognition

Mirant recognizes generation revenue from the sale of energy and integrated utilities and distribution revenue from the sale and distribution of energy when earned and collection is probable. The Company recognizes revenue when electric power is delivered to a customer pursuant to contractual commitments that specify volume, price and delivery requirements. When a long-term electric power agreement conveys the right to use the generating capacity of Mirant’s plant to the buyer of the electric power, that agreement is evaluated to determine if it is a lease of the generating facility rather than a sale of electric power.

F-7

Derivative financial instruments are recorded in the accompanying consolidated balance sheets at fair value as either assets or liabilities, and changes in fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized currently in earnings. If the derivative is designated as a cash flow hedge, the changes in the fair value of the derivative are recorded in other comprehensive income (“OCI”) and the realized gains and losses related to these derivatives are recognized in earnings in the same period as the settlement of the underlying hedged transaction. Any ineffectiveness relating to cash flow hedges is recognized currently in earnings. The assets and liabilities related to derivative instruments that do not qualify for hedge accounting treatment are included in price risk management assets and liabilities. For the years ended December 31, 2004 and 2003, the Company did not have any derivative instruments that it had designated as cash flow hedges for accounting purposes. Mirant’s derivative financial instruments are categorized by the Company as one of three types, based on the business objective the instrument is expected to achieve: asset management, legacy and optimization. All asset management, legacy and optimization activities are recorded at fair value, except for a limited number of transactions that qualify for the normal purchases or normal sales exclusion from “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No.133”) and therefore qualify for use of accrual accounting.

As the Company’s commodity derivative financial instruments have not been designated as hedges for accounting purposes, changes in such instruments’ fair values are recognized currently in earnings. Unless the contract is held for trading purposes, changes in fair value of electricity derivative financial instruments are reflected in generation revenue and changes in fair value of fuel derivative contracts are reflected in cost of fuel and other products in the accompanying consolidated statements of operations. Changes in the fair value and settlements of contracts held for trading purposes are recorded as net trading revenues in the accompanying consolidated statement of operations.

Concentration of Revenues

During 2004 and 2003, revenue earned from a single customer did not exceed 10% of the Company’s total revenues. In 2003, Mirant earned a significant portion of its operating revenue from the Pennsylvania-New Jersey-Maryland Interconnection, LLC (“PJM”) energy market, which is where Mirant’s Mid-Atlantic assets are primarily located.

Cash and Cash Equivalents

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

Restricted Cash

Restricted cash is included in current and other noncurrent assets in the accompanying consolidated balance sheets and amounted to $485 million and $199 million at December 31, 2004 and 2003, respectively. Restricted cash includes deposits with brokers to support the Company’s commodity positions and deposits for debt service reserve requirements under Mirant’s project financing in the Philippines.

Inventory

Inventory consists primarily of natural gas, oil, coal, purchased emission certificates, and materials and supplies. Inventory, including commodity trading inventory, is generally stated at the lower of cost or market value at December 31, 2004 and 2003.

F-8

Property, Plant and Equipment

Property, plant and equipment are recorded at cost, which includes materials, labor, and associated payroll-related and overhead costs and the cost of financing construction. The cost of routine maintenance and repairs, such as inspections and corrosion removal, and the replacement of minor items of property are charged to expense as incurred. Certain expenditures incurred during a major maintenance outage of a generating plant are capitalized, including the replacement of major component parts and labor and overheads incurred to install the parts. Depreciation of the recorded cost of depreciable property, plant and equipment is determined using primarily composite rates. Upon the retirement or sale of property, plant and equipment the cost of such assets and the related accumulated depreciation are removed from the consolidated balance sheet. No gain or loss is recognized for ordinary retirements in the normal course of business since the composite depreciation rates used by Mirant take into account the effect of interim retirements.

Capitalization of Interest Cost

Mirant capitalizes interest on projects during the advanced stages of development and during the construction period. The Company determines which debt instruments represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for determining the capitalization rate. Upon commencement of commercial operations of the plant or project, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant or the life of the cooperation period of the various energy conversion agreements. For the years ended December 31, 2004, 2003 and 2002, the Company incurred the following interest costs (in millions):

	2004			2003			2002
Total interest costs	$	131		$	407		$	590
Capitalized and included in construction work in progress	(1		)	(28		)	(95		)
Interest expense	$	130		$	379		$	495

Leasehold Interests

Certain of Mirant’s Philippine power generation facilities are developed under “build, operate and transfer agreements” with government controlled agencies of the respective local country government. Under these agreements, Mirant builds power generation facilities, operates them for a period of years (a “cooperation period”) and transfers ownership to the government at the end of the cooperation period. During construction, the cost of these facilities is recorded as construction work in progress. Upon completion of a facility, its entire cost is reclassified to leasehold interests where the balance is amortized over the remaining term of the agreement.

Goodwill and Intangible Assets

Goodwill represents the excess of costs over fair value of assets of businesses acquired. Goodwill and intangible assets acquired in a purchase business combination that are determined to have an indefinite useful life are not amortized, but instead tested for impairment at least annually. Intangible assets with definite useful lives are amortized on a straight-line basis over their respective useful lives ranging up to 40 years to their estimated residual values. An impairment occurs when the fair value of a reporting unit is less than its carrying value including goodwill. The amount of the impairment charge, if an impairment exists, is calculated as the difference between the implied fair value of the reporting unit goodwill and its carrying value. The Company performs an annual assessment of goodwill at October 31 and whenever contrary evidence exists as to the recoverability of goodwill. The fair value of the reporting unit is

F-9

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

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

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

Objective positive evidence is necessary to support a conclusion that a valuation allowance is not needed for all or a portion of deferred tax assets when significant negative evidence exists. Cumulative losses in recent years are the most compelling form of negative evidence considered by management in this determination. In 2004, 2003 and 2002, the Company recognized increases in its valuation allowance of $162 million, $943 million and $1,088 million, respectively, related to its net deferred tax assets.

Impairment of Long-Lived Assets

Mirant evaluates long-lived assets, such as property, plant, and equipment, and purchased intangible assets subject to amortization, for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated discounted future cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of are separately presented in the accompanying consolidated balance sheets and are reported at the lower of the carrying amount or fair value less costs to sell, and are not depreciated. The assets and liabilities of a disposal group classified as held for sale are presented separately in the appropriate asset and liability sections of the accompanying consolidated balance sheets.

Mirant evaluates its goodwill and indefinite-lived intangible assets for impairment at least annually and periodically if indicators of impairment are present.

Cumulative Effect of Changes in Accounting Principles

In October 2002, the Emerging Issues Task Force (“EITF”) reached a consensus on EITF Issue 02-03, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” to rescind EITF Issue 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” Accordingly, energy-related contracts that are not accounted for pursuant to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No. 133”), such as transportation contracts, storage contracts and tolling agreements, are required to be accounted for as executory contracts using the accrual method of accounting and not fair value. Energy-related contracts

F-10

that meet the definition of a derivative pursuant to SFAS No. 133 continue to be carried at fair value. In addition, the EITF observed that accounting for energy-related inventory at fair value by analogy to the consensus on EITF Issue 98-10 is not appropriate and that such inventory is not to be recognized at fair value. As a result of the consensus on EITF Issue 02-03, all non-derivative energy trading contracts on the consolidated balance sheet as of January 1, 2003 that existed on October 25, 2002 and energy-related inventories that were recorded at fair value have been adjusted to historical cost resulting in a cumulative effect adjustment of $26 million, net of taxes, which was recorded in the first quarter of 2003.

The Company adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) effective January 1, 2003, relating to costs associated with legal obligations to retire tangible, long-lived assets. Asset retirement obligations are recorded at fair value in the period in which they are incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its fair value and the capitalized costs are depreciated over the useful life of the related asset. In the first quarter of 2003, the Company recorded a charge as a cumulative effect of a change in accounting principle of approximately $3 million, net of tax, related to the adoption of this accounting standard.

On November 5, 2003, the FASB made certain revisions to the implementation guidance contained in Derivatives Implementation Group (“DIG”) Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity.” DIG Issue C15 describes the criteria that permit power purchase or sale agreements to qualify for the normal purchases and normal sales exception. The revisions were effective on the first day of the first fiscal quarter beginning after November 10, 2003. The modifications to DIG Issue C15 did not have a material impact on the Company’s consolidated results of operations, cash flows or financial position.

Interest Rate Financial Instruments

Historically, Mirant’s policy was to manage interest expense using a combination of fixed- and variable-rate debt. The Company also entered into interest rate swaps to hedge its exposure to changes in interest rates. For qualifying hedges, changes in the fair value of the swaps were deferred in OCI, net of tax, and were reclassified from OCI to interest expense as an adjustment of interest expense over the term of the debt. Gains and losses resulting from the termination of qualifying hedges prior to their stated maturities were recognized as interest expense ratably over the remaining term of the hedged debt instrument. For non-qualifying hedges, changes in fair values of the swaps were recognized currently in earnings. As a result of the Company’s bankruptcy filing, it recognized the remaining interest expense related to the previously terminated qualifying interest rate hedges in the third quarter of 2003. The Company does not have any interest rate swaps outstanding at December 31, 2004.

Foreign Currency Translation

For international operations in which the Company considers the functional currency to be the local currency, the foreign currency is translated into U.S. dollars using exchange rates in effect at period end for assets and liabilities and average exchange rates during each reporting period for results of operations. Adjustments resulting from translation of financial statements of foreign operations are reported in accumulated other comprehensive loss. For international operations in which the Company considers the functional currency to be the U.S. dollar, transactions denominated in currencies other than the U.S. dollar are translated into U.S. dollars. Gains or (losses) on such transactions are recognized in earnings and amounted to $12 million, $8 million and $2 million in 2004, 2003 and 2002, respectively.

F-11

Earnings (Loss) Per Share

Basic earnings (loss) per share is calculated by dividing net income (loss) applicable to common stockholders by the weighted average number of common shares outstanding. Diluted earnings (loss) per share is computed using the weighted average number of shares of common stock and dilutive potential common shares, including common shares from stock options using the treasury stock method and assumed conversion of convertible debt securities using the if-converted method.

3. Bankruptcy Related Disclosures

Proceeding Summary

On July 14, 2003 and July 15, 2003 (collectively, the “Petition Date”), Mirant and 74 of its wholly-owned subsidiaries in the U.S. (collectively, the “Original Debtors”) filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Northern District of Texas, Fort Worth Division (“Bankruptcy Court”). On August 18, 2003, October 3, 2003 and November 18, 2003, four additional wholly-owned subsidiaries and four affiliates of Mirant commenced Chapter 11 cases under the Bankruptcy Code (together with the Original Debtors, the “Mirant Debtors”). The Chapter 11 cases of the Mirant Debtors are being jointly administered for procedural purposes only under case caption In re Mirant Corporation et al., Case No. 03-46590 (DML).

Additionally, on the Petition Date, certain of Mirant’s Canadian subsidiaries, Mirant Canada Energy Marketing, Ltd. and Mirant Canada Marketing Investments, Inc. (together, the “Mirant Canadian Subsidiaries”), filed an application for creditor protection under the Companies Creditors’ Arrangement Act in Canada (“CCAA”), which, like Chapter 11, allows for reorganization under the protection of the court system. The Mirant Canadian Subsidiaries emerged from creditor protection on May 21, 2004. The accounting for their emergence is reflected in this report and did not have a material impact on the Company’s operating results.

Mirant’s businesses in the Philippines and the Caribbean were not included in the Chapter 11 filings.

The Mirant Debtors are operating their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code, the Federal Rules of Bankruptcy Procedure and applicable court orders, as well as other applicable laws and rules. In general, as debtors-in-possession, each of the Mirant Debtors is authorized under the Bankruptcy Code to continue to operate as an ongoing business, but may not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court.

The Office of the United States Trustee has established a committee of unsecured creditors for Mirant Corporation and a committee of unsecured creditors for Mirant Americas Generation (collectively, the “Creditor Committees”). The Office of the United States Trustee has also established a committee of equity securities holders of Mirant Corporation (the “Equity Committee” and, collectively with the Creditor Committees, the “Statutory Committees”). Pursuant to an order of the Bankruptcy Court, the Office of the United States Trustee appointed an examiner (the “Examiner”) in these cases to analyze certain potential causes of action and act as a mediator with respect to certain disputes that may arise among the Mirant Debtors, the Statutory Committees and other parties in interest.

Subject to certain exceptions in the Bankruptcy Code, the Chapter 11 filings automatically stayed the initiation or continuation of most actions against the Mirant Debtors, including most actions to collect pre-petition indebtedness or to exercise control over the property of the bankruptcy estates. As a result, absent an order of the Bankruptcy Court, creditors of the Mirant Debtors are precluded from collecting pre-petition debts and substantially all pre-petition liabilities are subject to compromise under a plan or plans of reorganization currently being developed by the Mirant Debtors in the bankruptcy proceedings. One

F-12

exception to this stay of litigation is for an action or proceeding by a governmental agency to enforce its police or regulatory power.

Under the Bankruptcy Code, the Mirant Debtors also have the right to assume, assume and assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and certain other conditions. The Mirant Debtors are continuing to evaluate their executory contracts in order to determine which contracts will be assumed, assigned or rejected.

The proposed Plan implements and includes the following key elements:

· the Mirant Americas Generation Debtors are substantively consolidated for all purposes under the proposed Plan;

F-13

· the prospective working capital requirements of Mirant Americas Generation will be met with the proceeds of a new first lien facility in the amount of at least $750 million;

· substantially all of the assets of Mirant will be transferred to a new company (“New Mirant”) to be formed pursuant to the proposed Plan, which will serve as the corporate parent of our business enterprise on and after the effective date of the proposed Plan and which shall have no successor liability for any unassumed obligations of Mirant Corporation, including any obligations to Potomac Electric Power Company (“PEPCO”) under the back-to-back agreement discussed in Note 15. Litigation and Other Contingencies; similarly, the trading business shall be transferred to Mirant Energy Trading, LLC, which shall have no successor liability for any unassumed obligations of Mirant Americas Energy Marketing, LP, including any obligations to PEPCO under the back-to-back agreement discussed in Note 15. Litigation and Other Contingencies ; and

At present, the proposed Plan has not been approved by any of the Statutory Committees. As such, the Mirant Debtors anticipate that negotiations (which, whether or not successful, could lead to material changes to certain components of the proposed Plan) will continue between the Mirant Debtors and each of the Statutory Committees until the hearing to approve the adequacy of the Disclosure Statement. At present, the Bankruptcy Court has set the following schedule with respect to the Disclosure Statement: the First Amended Disclosure Statement is to be filed by March 25, 2005; objections to the draft Disclosure Statement is to be filed by April 1, 2005; the Second Amended Disclosure Statement to be filed by April 15, 2005; and the Disclosure Statement adequacy hearing in the Bankruptcy Court is set for April 20, 2005.

Accounting for Reorganization

The accompanying consolidated financial statements of Mirant have been prepared in accordance with Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” and on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. However, as a result of the bankruptcy filings, such realization of assets and satisfaction of liabilities are subject to a significant number of uncertainties. Mirant’s consolidated financial statements do not reflect adjustments that might be required if Mirant (or each of the Mirant Debtors) is unable to continue as a going concern.

Condensed combined financial statements of the Mirant Debtors and Non-Debtors are set forth below. Mirant Debtors include all entities that filed for protection from creditors in 2003. “Non-Debtors” include the Company’s businesses in the Caribbean and Philippines that are generally not affected by the bankruptcy filings, as well as certain non wholly-owned subsidiaries and the Mirant Canadian Subsidiaries which emerged from CCAA creditor protection in May 2004.

F-14

Condensed Combined Statement of Operations Data
For the Year Ended December 31, 2004
(in millions)

	Debtors			Non-Debtors				Consolidation/ Elimination Entries				Consolidated
Operating revenues	$	3,530			$	1,061			$	(19	)		$	4,572
Cost of fuel, electricity and other products	2,333				304				(17		)		2,620
Operating expenses	962				1,010				(2		)		1,970
Operating (loss) income	235				(253		)		—				(18		)
Other (expense) income net	(161		)		(52		)		188				(25		)
Reorganization items, net	250				6				3				259
Provision (benefit) for income taxes	282				(195		)		—				87
Minority interest	—				21				—				21
(Loss) income from continuing operations	(458		)		(137		)		185				(410		)
Loss from discontinued operations, net of tax	(18		)		(48		)		—				(66		)
Net (loss) income	$	(476	)		$	(185	)		$	185			$	(476	)

Condensed Combined Statement of Operations Data
For the Year Ended December 31, 2003
(in millions)

	Debtors			Non-Debtors				Consolidation/ Elimination Entries				Consolidated
Operating revenues	$	4,162			$	1,024			$	(24	)		$	5,162
Cost of fuel, electricity and other products	2,923				280				(19		)		3,184
Operating expenses	4,456				392				(6		)		4,842
Operating (loss) income	(3,217		)		352				1				(2,864		)
Other (expense) income net	(225		)		14				(106		)		(317		)
Reorganization items, net	290				—				—				290
Provision for income taxes	(110		)		236				—				126
Minority interest	12				23				—				35
(Loss) income from continuing operations	(3,634		)		107				(105		)		(3,632		)
Loss from discontinued operations, net of tax	(172		)		(2		)		—				(174		)
Cumulative effect of changes in accounting principles, net of taxes	(29		)		—				—				(29		)
Net (loss) income	$	(3,835	)		$	105			$	(105	)		$	(3,835	)

F-15

Condensed Combined Balance Sheet Data
December 31, 2004
(in millions)

	Debtors			Non-Debtors			Consolidation/ Elimination Entries				Consolidated
Current assets	$	2,854			$	1,233		$	(234	)		$	3,853
Intercompany receivables	684				618			(1,302		)		—
Property, plant and equipment, net	4,055				2,190			—				6,245
Intangible assets, net	262				14			—				276
Investments	2,101				231			(2,084		)		248
Other	281				521			—				802
Total assets	$	10,237			$	4,807		$	(3,620	)		$	11,424
Liabilities not subject to compromise:
Current liabilities	977				436			(1		)		1,412
Intercompany payables	526				685			(1,211		)		—
Other noncurrent liabilities	333				454			(1		)		786
Long-term debt	185				984			—				1,169
Liabilities subject to compromise	9,534				—			(323		)		9,211
Minority interest	—				164			—				164
Stockholders’ (deficit) equity	(1,318		)		2,084			(2,084		)		(1,318		)
Total liabilities and stockholders’ equity	$	10,237			$	4,807		$	(3,620	)		$	11,424

Condensed Combined Balance Sheet Data
December 31, 2003
(in millions)

	Debtors			Non-Debtors			Consolidation/ Elimination Entries				Consolidated
Current assets	$	3,051			$	1,292		$	(243	)		$	4,100
Intercompany receivables	848				644			(1,492		)		—
Property, plant and equipment, net	4,212				2,263			—				6,475
Intangible assets, net	282				598			—				880
Investments	2,400				211			(2,344		)		267
Other	282				328			1				611
Total assets	$	11,075			$	5,336		$	(4,078	)		$	12,333
Liabilities not subject to compromise:
Current liabilities	1,270				514			(5		)		1,779
Intercompany payables	561				847			(1,408		)		—
Other noncurrent liabilities	478				367			4				849
Long-term debt	189				1,095			(2		)		1,282
Liabilities subject to compromise	9,400				—			(323		)		9,077
Minority interest	—				169			—				169
Stockholders’ (deficit) equity	(823		)		2,344			(2,344		)		(823		)
Total liabilities and stockholders’ equity	$	11,075			$	5,336		$	(4,078	)		$	12,333

F-16

Condensed Combined Statement of Cash Flow Data
For the Year Ended December 31, 2004
(in millions)

	Debtors			Non-Debtors				Consolidation/ Elimination Entries				Consolidated
Net cash provided by (used in):
Operating activities	$	(391	)		$	435			$	27			$	71
Investing activities	(121		)		(11		)		(14		)		(146		)
Financing activities	392				(406		)		(13		)		(27		)
Effect of exchange rate changes on cash and cash equivalents	(3		)		3				—				—
Net (decrease) increase in cash and cash equivalents	(123		)		21				—				(102		)
Cash and cash equivalents, beginning of year	1,075				512				—				1,587
Cash and cash equivalents, end of year	$	952			$	533			$	—			$	1,485
Cash paid for reorganization items	$	104			$	3			$	—			$	107

Condensed Combined Statement of Cash Flow Data
For the Year Ended December 31, 2003
(in millions)

	Debtors			Non-Debtors				Consolidation/ Elimination Entries				Consolidated
Net cash provided by (used in):
Operating activities	$	(340	)		$	256			$	65			$	(19	)
Investing activities	(91		)		51				(48		)		(88		)
Financing activities	287				(288		)		(17		)		(18		)
Effect of exchange rate changes on cash and cash equivalents	3				3				—				6
Net (decrease) increase in cash and cash equivalents	(141		)		22				—				(119		)
Cash and cash equivalents, beginning of year	1,216				490				—				1,706
Cash and cash equivalents, end of year	$	1,075			$	512			$	—			$	1,587
Cash paid for reorganization items	$	56			$	—			$	—			$	56

Interest Expense

The Mirant Debtors have discontinued recording interest on liabilities subject to compromise. Contractual interest on liabilities subject to compromise in excess of reported interest was approximately $535 million and $239 million for the years ended December 31, 2004 and 2003, respectively. Contractual interest on liabilities subject to compromise in excess of reported interest for the period from the Petition Date through December 31, 2004 is approximately $774 million. This amount includes approximately $225 million of interest related to Mirant Americas Generation long dated bonds to be reinstated under the proposed Plan filed by the Company on January 19, 2005.

F-17

Reorganization Items

Reorganization items, net represents expense or income amounts that were recorded in the financial statements as a result of the bankruptcy proceedings. For the years ended December 31, 2004 and 2003, the following were the significant items within this category (in millions):

	Years Ended December 31,
	2004			2003
Estimated claims and losses on rejected and amended contracts	$	171		$	241
Professional fees and administrative expense	110			48
Interest income, net	(15		)	1
Other gains, net	(7		)	—
Total	$	259		$	290

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

Professional fees and administrative expense relate to legal, accounting and other professional costs directly associated with the reorganization process. Approximately $39 million and $15 million of the professional fees and administrative expense for the years ended December 31, 2004 and 2003, respectively, relate to advisors of the Statutory Committees.

Other gains, net for the year ended December 31, 2004 includes a gain on settlements of accounts payable of $7 million upon emergence of the Mirant Canadian Subsidiaries from creditor protection.

Liabilities Subject to Compromise

Liabilities subject to compromise include certain liabilities incurred prior to the Petition Date. The amounts of the various categories of liabilities that are subject to compromise are set forth below. These amounts represent the Company’s estimates of known or potential claims against Mirant Debtors that are likely to be resolved in connection with the bankruptcy filings. Such claims remain subject to future adjustments. Adjustments may result from negotiations, actions of the Bankruptcy Court, rejections of executory contracts and unexpired leases, and determinations as to the value of any collateral securing claims, proofs of claim or other events. The fair value of a Mirant Debtor’s assets may be lower than its liabilities. This fact could result in liabilities being settled at less than 100% of their face value and the Company’s equity being cancelled.

Liabilities not subject to compromise include: (1) liabilities of Non-Debtor entities; (2) liabilities incurred after the Petition Date; (3) liabilities incurred prior to the Petition Date that the Mirant Debtors expect to pay in full, even though certain of these amounts may not be paid until a plan of reorganization is approved; (4) liabilities related to pre-petition contracts that have not been rejected; and (5) liabilities incurred prior to the Petition Date that have been approved for payment by the Bankruptcy Court and that the Mirant Debtors expect to pay (in advance of a plan of reorganization) in the ordinary course of business, including certain employee-related items (e.g., salaries, vacation and medical benefits). The proposed Plan contemplates complete funding of Mirant Americas Generation debt currently classified as liabilities subject to compromise. The debt will continue to be classified as such until the Bankruptcy Court approves the proposed Plan.

The classification of liabilities not subject to compromise versus liabilities subject to compromise is based on currently available information and analysis. As the bankruptcy cases proceed and additional information and analysis is completed or, as the Bankruptcy Court rules on relevant matters, the

F-18

classification of amounts between these two categories may change. The amount of any such changes could be significant.

The amounts subject to compromise at December 31, 2004 and 2003, consisted of the following items (in millions):

Items, absent the bankruptcy filings, that would have been considered current at:

	Years ended December 31,
	2004		2003
Accounts payable and accrued liabilities	$	1,022	$	1,102
Current portion of long-term debt	3,112		2,500
Price risk management liabilities	80		133

Items, absent the bankruptcy filings, that would have been considered noncurrent at:

Long-term debt	3,974		4,361
Price risk management liabilities	460		575
Note payable to Mirant Trust I	356		356
Indemnification agreement and other noncurrent liabilities	207		50
Total	$	9,211	$	9,077

The price risk management liabilities included in liabilities subject to compromise relate to power purchase agreements. The $168 million decrease in these liabilities from December 31, 2003 to December 31, 2004 relates to purchases made under the power purchase agreements during the year ended December 31, 2004 and to changes in the fair value of the remaining obligation as of December 31, 2004 due to changes in forward power prices. Price risk management liabilities represent the fair value of the PEPCO Back-to-Back Agreement. See Note 15 for additional information related to the PEPCO Back-to-Back Agreement.

Accounts payable and accrued liabilities above are net of approximately $35 million of pre-petition accounts receivable due from counterparties with which the Mirant Debtors have a netting agreement.

Included in the indemnification agreement and other non-current liabilities is $189 million for an estimated obligation that relates to potential tax obligations stemming from the sale of a business in 2002. As part of the sale agreement, Mirant guaranteed that two wholly-owned subsidiaries would indemnify the purchaser, if the purchaser became liable for additional taxes on the acquisition. No triggering event has occurred, but the Company believes it is probable that additional tax will be due on the sale, and consequently the guarantee between Mirant and the subsidiaries will be called upon to reimburse the purchaser for additional taxes due on the transaction. No payments are due on the indemnification agreement if additional taxes are never assessed on the transaction. The estimated maximum exposure approximates the amount recorded as of December 31, 2004. During the fourth quarter of 2004, this liability was transferred to liabilities subject to compromise because the guarantee is expected to be rejected or otherwise avoided through the bankruptcy process. In prior year periods, this liability was included in other non-current liabilities on the balance sheet.

During the first quarter of 2003, Mirant paid $51 million to purchase $83 million in aggregate principal amount of TIERS Fixed Rate Certificates (the “TIERS Certificates”). The TIERS Certificates were issued by a third party trust (the “Trust”) and were secured by $750 million aggregate principal amount of Mirant’s 2.5% convertible senior debentures due 2021 (the “Mirant Debentures”). On June 15, 2004, the Trust was terminated in accordance with the terms of the Trust agreement and the Mirant Debentures were distributed to holders of the TIERS Certificates. The Company received $83 million of

F-19

the Mirant Debentures upon liquidation of the Trust. The acquisition of the Mirant Debentures was accounted for as an extinguishment of $83 million of debt. Mirant recognized a $37 million gain on the extinguishment of debt during the year ended December 31, 2004, which is reflected in other income (expense), net in the consolidated statements of operations.

On January 28, 2004, the Bankruptcy Court approved the amended lease agreement for Mirant’s Atlanta Headquarters to reduce its space commitments to approximately 216,000 square feet and reduce the term of the lease to three years. This new agreement is accounted for as an operating lease. Under the previous lease agreement, the remaining obligations totaled $57 million as of December 31, 2003. The Company recorded the estimated damage claim and the gain on the lease amendment in reorganization items, net in the consolidated statement of income. In the year ended December 31, 2004, the net reorganization expense recognized related to the lease amendment was approximately $5 million.

On August 29, 2003, the Mirant Debtors filed a motion with the Bankruptcy Court to reject the tolling agreement with Perryville Energy Partners, LLC (“Perryville”), under which Mirant Americas Energy Marketing, LP paid a fixed capacity payment and supplied the natural gas needed to fuel the Perryville generation facility in exchange for the right to own and market the facility’s output. The rejection was approved by the Bankruptcy Court on September 15, 2003. Perryville filed claims in excess of $1 billion against the Mirant Debtors as a result of the rejection. Mirant Americas Energy Marketing, L.P. has filed an objection to the Perryville claims and the Mirant Debtors are investigating the nature, scope and defenses to such claims. The Company has recorded an estimated damage claim related to the rejection of the tolling agreement of approximately $80 million as of December 31, 2004. Approximately $43 million of the $80 million recorded represents the Company’s estimate of the out-of-market value of the tolling agreement (after netting of $99 million of debt owed by Perryville to Mirant Americas, Inc.). The balance of the $80 million liability reflects the uncertainties associated with the ongoing litigation of the Perryville claims and the potential for an adverse outcome of the litigation. The amount recorded is included in accounts payable and accrued liabilities within liabilities subject to compromise.

On January 28, 2004, Perryville and its parent company Perryville Energy Holdings, LLC filed voluntary petitions for protection under Chapter 11 in Alexandria, Louisiana (the “Perryville Cases”). The Mirant Debtors filed claims in the Perryville Cases based on the unpaid subordinated loan.

On July 14, 2004, Perryville filed a motion for relief from the automatic stay to compel arbitration of Perryville’s claim in Mirant Americas Energy Marketing’s Chapter 11 case. On September 29, 2004, the Bankruptcy Court denied Perryville’s motion. Perryville appealed the decision to deny arbitration to the United States District Court for the Northern District of Texas. Based on their expert analysis and report, the Mirant Debtors estimate the total damages at $151 million (subject to offset by $99 million due and owing by Perryville on the subordinated loan). Perryville’s expert report estimates damages in the range of $395 million to $407 million with no offset for the unpaid subordinated loan.

4. Assets Held for Sale

The Company has reclassified amounts for prior periods in the financial statements to report separately, as discontinued operations, the revenues and expenses of components of the Company that have been disposed of or are expected to be disposed of in the next year. A description of the assets held for sale is discussed below the tables.

F-20

A summary of the operating results for these discontinued operations for the years ended December 31, 2004, 2003 and 2002 follows (in millions):

	December 31,
	2004			2003			2002
Operating revenue	—			$	13		$	107
Cost of fuel, electricity and other products	—			6			6
Operating expenses, including other (expense) income, net	(54		)*	(270		)**	(251		)
Loss before income taxes, reorganization items and minority interest	(54		)	(263		)	(150		)
Reorganization items, net	12			5			—
Income tax expense (benefit)	—			(1		)	(55		)
Minority interest	—			(93		)	3
Net loss	$	(66	)	$	(174	)	$	(98	)

* For the year ended December 31, 2004, an impairment charge of approximately $48 million was recorded related to Coyote Springs 2.

** For the year ended December 31, 2003, an impairment charge of approximately $228 million was recorded related to the Wrightsville facility.

Current assets and liabilities held for sale include discontinued operations and other assets that the Company expects to dispose of in the next year. The table below presents the components of the balance sheet accounts classified as current assets and liabilities held for sale as of December 31, 2004 and 2003 (in millions):

	2004		2003
Current Assets:
Current assets	$	7	$	11
Property, plant and equipment	145		292
Other assets	9		9
Total current assets held for sale	$	161	$	312
Current Liabilities:
Current liabilities	$	1	$	—
Liabilities subject to compromise	6		7
Total current liabilities related to assets held for sale	$	7	$	7

F-21

The following tables present the effects of the reclassifications in the previously presented consolidated statements of operations for the years ended December 31, 2003 and 2002, and balance sheet as of December 31, 2003 (in millions).

	Year Ended December 31, 2003
	As Previously Presented				Reclassifications				As Presented
Operating revenues		$	5,171			$	(9	)		$	5,162
Cost of fuel, electricity and other products		3,190				(6		)		3,184
Gross Margin		1,981				(3		)		1,978
Operating expenses		5,087				(245		)		4,842
Operating income		(3,106		)		242				(2,864		)
Other expense, net		(317		)		—				(317		)
(Loss) income before reorganization items, income taxes and minority interest		(3,423		)		242				(3,181		)
Reorganization items, net		295				(5		)		290
Income tax expense		126				—				126
Minority interest		(58		)		93				35
(Loss) income from continuing operations		(3,786		)		154				(3,632		)
Loss from discontinued operations, net of tax		(20		)		(154		)		(174		)
Cumulative effect of changes in accounting principles, net of taxes		(29		)		—				(29		)
Net loss		$	(3,835	)		$	—			$	(3,835	)

	Year Ended December 31, 2002
	As Previously Presented				Reclassifications				As Presented
Operating revenues		$	4,705			$	(2	)		$	4,703
Cost of fuel, electricity and other products		2,488				(6		)		2,482
Gross Margin		2,217				4				2,221
Operating expenses		3,128				(8		)		3,120
Operating (loss) income		(911		)		12				(899		)
Other expense, net		(417		)		—				(417		)
(Loss) income before reorganization items, income taxes and minority interest		(1,328		)		12				(1,316		)
Reorganization items, net		—				—				—
Income tax expense		948				1				949
Minority interest		78				(3		)		75
(Loss) income from continuing operations		(2,354		)		14				(2,340		)
Loss from discontinued operations, net of tax		(84		)		(14		)		(98		)
Cumulative effect of changes in accounting principles, net of tax		—				—				—
Net loss		$	(2,438	)		$	—			$	(2,438	)

F-22

	As of December 31, 2003
	As Previously Presented				Reclassifications				As Presented
Cash and cash equivalents		$	1,589			$	(2	)		$	1,587
Funds on deposit, current		150				—				150
Receivables, net		1,329				(3		)		1,326
Price risk management assets, current		104				—				104
Inventories		288				(2		)		286
Assets held for sale		—				312				312
Other current assets		339				(4		)		335
Property, plant and equipment, net		6,767				(292		)		6,475
Goodwill		587				—				587
Other intangible assets, net		293				—				293
Investments		267				—				267
Price risk management assets, noncurrent		135				—				135
Funds on deposit, noncurrent		49				—				49
Other noncurrent assets		436				(9		)		427
Total assets		$	12,333			$	—			$	12,333
Current liabilities		$	1,552			$	—			$	1,552
Other current liabilities		220				7				227
Total noncurrent liabilities		2,131				—				2,131
Liabilities subject to compromise		9,084				(7		)		9,077
Minority interest		169				—				169
Stockholders’ deficit		(823		)		—				(823		)
Total liabilities and stockholders’ deficit		$	12,333			$	—			$	12,333

Description of Components in Assets Held for Sale

2004

Coyote Springs 2: In October 2004, Mirant Oregon LLC (“Mirant Oregon”), a wholly-owned subsidiary of Mirant, entered into an agreement to sell its 50% undivided interest in Coyote Springs 2 to Avista Energy, subject to Bankruptcy Court and regulatory approval. The Bankruptcy and regulatory approvals occurred in the fourth quarter of 2004. In the second quarter of 2004, the Company recognized an impairment charge of $48 million related to the Coyote Springs 2 project. This amount is included in loss from discontinued operations for the year ended December 31, 2004 in the consolidated statements of operations. The Company completed the sale for $63 million in January 2005 after conducting an auction in which Mirant Oregon solicited higher bids.

Wrightsville: During the third quarter of 2004, the Company negotiated a non-binding term sheet to sell its generating facility in Wrightsville, Arkansas. This facility is currently mothballed (temporarily shutdown). The Company expects proceeds from this sale to approximate book value as of December 31, 2004. In February 2005, certain indirect subsidiaries of the Company entered into an agreement to sell the Wrightsville generating facility to Arkansas Electric Cooperative Corporation, and, subject to Bankruptcy Court and other approvals, expects to complete the sale in 2005.

2003

Neenah: In January 2003, Mirant completed the sale of its Neenah generating facility for approximately $109 million resulting in a pre-tax gain of approximately $4 million. The operating results for this business prior to its disposal are included in loss from discontinued operations in the accompanying consolidated statements of operations.

F-23

Tanguisson: In April 2003, Mirant completed the sale of its Tanguisson power plant in Guam for approximately $16 million, which approximated the book value of the assets sold. The operating results for this business prior to its disposal are included in loss from discontinued operations in the accompanying consolidated statements of operations.

Mirant Americas Energy Capital: In May and August 2003, Mirant Americas Energy Capital completed the sale of its two remaining investments for approximately $41 million and $3 million, respectively, which approximated book value. The operating results for this business prior to its disposal are included in loss from discontinued operations in the accompanying consolidated statements of operations.

2002

State Line: In June 2002, Mirant completed the sale of its State Line generating facility for approximately $180 million plus an adjustment for working capital. The asset was sold at approximately book value. The operating results for this business prior to its disposal are included in loss from discontinued operations in the accompanying consolidated statements of operations.

Mirant Americas Production Company: In August 2001, Mirant acquired a 75% working interest in 18 natural gas and oil producing fields as well as 206,000 acres of mineral rights in southern Louisiana from Castex and a number of its affiliates for approximately $162 million. Castex, a privately held Houston-based oil and gas producer, retained an interest in the properties and continued to operate them. In September 2002, Mirant recorded a write down of $48 million to reduce the carrying value of its investment to its estimated fair value less costs to sell. In December 2002, Mirant completed the sale of its investment for $143 million, and recorded an additional loss of $7 million. The operating results for this business prior to its disposal are included in loss from discontinued operations in the accompanying consolidated statements of operations.

5. Accounts Receivable and Notes Receivable

Receivables consisted of the following at December 31, 2004 and 2003 (in millions).

	2004		2003
Customer accounts	$	1,049	$	1,330
Notes receivable	99		102
Collateral receivable	217		239
Other	48		66
Less: allowance for uncollectibles	395		411
Total receivables	1,018		1,326
Less: long-term receivables included in other long-term assets	32		—
Total current receivables	$	986	$	1,326

6. Financial Instruments

Commodity Financial Instruments

The Company manages the risks around fuel supply and power to be generated from its physical asset positions (“asset management”), and attempts to achieve incremental returns by entering into additional energy contracts where it has specific market expertise or physical asset positions (“optimization trading”). In the fourth quarter of 2003, the Company segregated a portion of its existing derivative contracts that were not considered strategic to ongoing operations into a separately managed portfolio (“legacy portfolio”).

Mirant enters into a variety of derivative financial and physical instruments to manage its exposure to the prices of the fuel it acquires for generating electricity, as well the electricity produced that it sells.

F-24

These include contractual agreements, such as forward purchase and sale agreements, and futures, swaps and option contracts. Futures are traded on national exchanges and swaps are typically traded in over-the-counter financial markets. Option contracts are traded on both a national exchange and in over-the-counter financial markets. These contractual agreements have varying terms and durations, or tenors, which range from a few days to a number of years, depending on the instrument.

As part of its optimization trading activities, the Company is exposed to certain market risks in an effort to generate gains from changes in market prices by entering into derivative instruments, including exchange-traded and over-the-counter contracts, as well as other contractual arrangements. The earnings and cash flows from the Company’s optimization trading business can be volatile and subject to swings as commodity prices change. Gas and electricity, the primary commodities the Company trades, are among the most volatile commodities in terms of price in the market.

Derivative instruments are recorded at their estimated fair value in the Company’s accompanying consolidated balance sheets as price risk management assets and liabilities except for a limited number of transactions that qualify for the normal purchase or normal sale exception election that allows accrual accounting treatment. Certain transactions are entered into under master netting agreements that provide the Company with a legal right of offset in the event of default by the counterparty and are, therefore, reported net in the Company’s accompanying consolidated balance sheets. Unless the contracts are held for trading purposes, changes in the fair value and settlements of electricity derivative financial instruments are reflected in generation revenue and changes in the fair value and settlements of fuel derivative contracts are reflected in cost of fuel and other products in the accompanying consolidated statements of operations. For contracts held for trading purposes, changes in the fair value and settlements of these instruments are recorded as net trading revenues in the accompanying consolidated statements of operations. As of December 31, 2004, the Company does not have any derivative instruments for which hedge accounting criteria are met.

The fair values of Mirant’s price risk management assets and liabilities, net of credit reserves, as of December 31, 2004 are included in the following table (in millions).

	Assets							Liabilities
	Current				Noncurrent			Current				Noncurrent
Electricity		$	106			$	85		$	(198	)		$	(41	)
Natural Gas		59				26			(65		)		(20		)
Crude Oil		46				1			(23		)		(1		)
Other		(2		)		—			—				—
Total		$	209			$	112		$	(286	)		$	(62	)

Fair Values

Financial instruments recorded at market or fair value include cash and interest-bearing cash equivalents, derivative financial instruments and financial instruments used for price risk management purposes. The following methods were used by Mirant to estimate the fair value of all financial instruments that are not subject to compromise and not otherwise carried at fair value on the accompanying consolidated balance sheets:

Notes and Other Receivables. The fair value of Mirant’s notes receivable are estimated using interest rates it would receive currently for similar types of arrangements.

Notes Payable and Other Long- and Short-Term Debt. The fair value of Mirant’s notes payable and long- and short-term debt is estimated using quoted market prices, when available. Market prices for

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international business debt are not readily available as there is no active market for these financial instruments. In most cases, the debt of the Company’s international operations is secured by the assets of those operations. Therefore, the carrying value of the debt is deemed to be a reasonable approximation of fair value.

The carrying or notional amounts and fair values of Mirant’s financial instruments at December 31, 2004 and 2003 were as follows (in millions):

	2004					2003
	Carrying Amount			Fair Value		Carrying Amount			Fair Value
Liabilities Subject to Compromise:
Notes payable and long-and short-term debt		$	7,086	$	*		$	6,861	$	*
Note payable to Mirant Trust I		356		*			356		*
Liabilities Not Subject to Compromise:
Notes payable and long-and short-term debt		1,390		1,390			1,566		1,566
Other:
Notes and other receivables		32		32			—		—

* As a result of the Company’s Chapter 11 filing, the fair value cannot be reasonably determined for the outstanding debt that is included in liabilities subject to compromise on the consolidated balance sheets.

7. Property, Plant and Equipment

Property, plant and equipment consisted of the following at December 31, 2004 and 2003 (in millions):

	2004		2003
Production	$	4,508	$	4,573
Transmission and distribution	307		277
Leasehold interest	2,004		2,003
Oil and gas properties	25		25
Construction work in progress	127		178
Other	336		337
Suspended construction projects(1)	250		241
	7,557		7,634
Less: accumulated depreciation, depletion and amortization and provision for impairment	1,312		1,159
Total property, plant and equipment, net	$	6,245	$	6,475

(1) The Company does not expect to independently complete its four suspended construction projects that consist of 2,188 MW of generating capacity. The Company plans to either pursue partnerships to complete one or more of the projects, sell the projects or abandon the projects.

Depreciation of the recorded cost of depreciable property, plant and equipment is provided on a straight-line basis over the estimated useful lives of the assets as follows:

		Years
Production		5 to 42
Transmission and distribution		5 to 39
Other general plant (office furniture, computer equipment, software, etc.)		5 to 12
Leasehold improvements		12 to 29

The cost of oil and gas properties were amortized using the units of production method over the estimated proved reserves of the properties. Mirant does not depreciate its suspended construction project costs.

Mirant evaluates its long-lived assets (property, plant and equipment) and definite-lived intangibles for impairment whenever events or changes in circumstances indicate that the Company may not be able to recover the carrying amount of the asset. As a result of two credit rating downgrades, public opposition to

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Mirant’s pre-petition restructuring proposals, material unfavorable variances to its prior business plan through the second quarter of 2003 and a lawsuit filed against its pre-petition restructuring proposal by Mirant Americas Generation bondholders, Mirant reassessed its long-lived assets for impairment at June 30, 2003. The results of the analysis indicated no impairments of its property, plant and equipment existed at June 30, 2003. At December 31, 2003, an additional impairment analysis was prepared incorporating Mirant’s then most recent assumptions as to future operations and opportunities in connection with its 2004 10-year business plan. The results of such analysis indicated a substantial decrease in nominal cash flows over Mirant’s 10-year planning horizon and, in certain cases, an impairment of certain long-lived asset balances.

In the second quarter of 2004, the Company began pursuing the sale of its Coyote Springs 2 generation facility. This decision represented a triggering event causing the Company to evaluate the asset for impairment, and to ultimately determine that an impairment charge of $48 million was required. The $48 million impairment charge related to Coyote Springs 2 is included in loss from discontinued operations in the consolidated statements of operations. The Coyote Springs 2 sale was completed in January 2005. Aside from the Coyote Springs impairment, certain project specific assets were determined to be impaired as such assets were no longer utilized nor related to viable projects.

An asset impairment charge must be recognized if the sum of the undiscounted expected future cash flows from a long-lived asset or definite-lived intangible is less than the carrying value of that asset. The amount of any impairment charge is calculated as the excess of the carrying value of the asset over its fair value. Fair value is estimated based on the discounted future cash flows from that asset or determined by other valuation techniques. In the case of assets Mirant expects to sell the impairment charge is based on the estimated fair value less costs to sell. Following is a summary of long-lived asset impairment charges recorded for the years ended December 31, 2004, 2003 and 2002 (in millions):

	2004		2003		2002
Property plant and equipment, in service	$	—	$	743	$	—
Suspended construction projects	—		363		610
Trading rights	—		145		—
Development rights	—		81		—
Emissions allowances	—		6		—
Other intangibles	—		1		—
Total	$	—	$	1,339	$	610

For purposes of testing for impairment losses, Mirant grouped long-lived assets and definite-lived intangibles at the lowest level at which separate cash flows can be identified, which generally was determined to be the individual generating assets or several generating assets operated as a group. The long-lived assets evaluated for impairment consist of the legal entities’ property, plant and equipment, construction work in progress, development rights, trading rights, emissions allowances and other definite-lived intangibles.

8. Goodwill and Other Intangible Assets

Goodwill

Goodwill consisted of the following as of December 31, 2004 and 2003 (in millions):

	2004			2003
Goodwill		$	10	$	783
Less: accumulated amortization		5		196
Total		$	5	$	587

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Following is a summary of the changes in goodwill for the years ended December 31, 2004 and 2003, (in millions):

	North America				International				Total
2004
Goodwill, beginning of year		$	—			$	587		$	587
Impairment losses		—				(582		)	(582		)
Goodwill, end of year		$	—			$	5		$	5
2003
Goodwill, beginning of year		$	2,074			$	609		$	2,683
Impairment losses		(2,067		)		—			(2,067		)
Purchase accounting and tax adjustments		(7		)		(21		)	(28		)
Asset disposal		—				(1		)	(1		)
Goodwill, end of year		$	—			$	587		$	587

As a result of two credit rating downgrades, public opposition to Mirant’s pre-petition restructuring proposals, material unfavorable variances to its prior business plan through the second quarter of 2003 and a lawsuit filed against its pre-petition restructuring proposal by Mirant Americas Generation bondholders, Mirant reassessed its goodwill for impairment at June 30, 2003 related to its North America reporting unit. The results of the analysis indicated that a goodwill impairment existed at June 30, 2003. A detailed impairment analysis indicated that all of the North America goodwill was impaired and accordingly, Mirant recorded an impairment charge of $2.1 billion, which is reflected as an impairment loss in the consolidated statements of operations for the year ended December 31, 2003.

During the year ended December 31, 2003, Mirant disposed of the Tanguisson power plant in Guam and also in 2003, Mirant finalized its purchase accounting adjustments for its West Georgia and TransCanada assets, resulting in reclassifications among deferred taxes, prepaid assets and goodwill.

The Company performed its annual assessment of goodwill in the fourth quarter of 2004. The results of the assessment indicate an impairment of the goodwill related to the Company’s Asia reporting unit. The assets in this region are operated under energy conversion agreements executed under the government’s build-operate-transfer program. The cash flows from these entities are inherently limited since at the end of the term of each energy conversion agreement, the plant is required to be transferred to National Power Corporation (“NPC”), free from any lien or payment of compensation. A detailed impairment analysis indicated that all of the Asia business unit’s goodwill was impaired and accordingly, Mirant recorded an impairment charge of $582 million, which is reflected as an impairment loss in the consolidated statements of operations for the year ended December 31, 2004. This impairment loss was recognized primarily due to changes in tax assumptions, a credit downgrade of the Philippine sovereign debt, and changes in asset and liability allocations.

Intangible Assets

Following is a summary of intangible assets as of December 31, 2004 and 2003 (in millions):

	Weighted		December 31, 2004							December 31, 2003
	Average Amortization Lives		Gross Carrying Amount			Accumulated Amortization				Gross Carrying Amount			Accumulated Amortization
Trading rights		26 years		$	27		$	(1	)		$	62		$	(35	)
Development rights		39 years		119			(12		)		137			(24		)
Emissions allowances		32 years		131			(15		)		131			(12		)
Other intangibles		22 years		25			(3		)		40			(6		)
Total other intangible assets				$	302		$	(31	)		$	370		$	(77	)

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

Development rights represent the right to expand capacity at certain acquired generating facilities. The existing infrastructure, including storage facilities, transmission interconnections, and fuel delivery systems, and contractual rights acquired by Mirant provide the opportunity to expand or repower certain generation facilities. This ability to repower or expand is expected to be at significant cost savings compared to greenfield construction.

Emissions allowances represent credits that entitle the holder of each allowance to emit one ton of sulfur dioxide (“SO2”) or nitrogen oxide (“NOx”). The basic feature of both the SO2 and NOx programs is a system of emission allowances which imposes a cap on total SO2 and NOx emissions from the electric utility industry. These allowances can be used in that year, saved for future years, or sold to other sources.

Substantially all of Mirant’s other intangible assets are subject to amortization and are being amortized on a straight-line basis over their estimated useful lives, ranging up to 33 years.

Amortization expense was approximately $10 million, $21 million and $19 million for the years ended December 31, 2004, 2003 and 2002, respectively. Assuming no future acquisitions, dispositions or impairments of intangible assets, amortization expense is estimated to be $9 million for each of the next five years.

During 2003, Mirant evaluated its definite-lived intangible assets for impairment. As a result of this evaluation, the Company recorded impairment charges related to trading and development rights of approximately $145 million and $81 million, respectively.

The carrying value of the intangible assets above may be further impaired in future periods as a result of changes to the Company’s strategy in implementing its plan or plans of reorganization.

9. Dispositions and Acquisitions of Assets

Dispositions

The following table summarizes information related to completed asset sales for the years ended December 31, 2004, 2003 and 2002 (in millions):

Investment	Location	Gross Proceeds				Gain (Loss)				Reporting Segment	Date of Sale
2004:
Mirant Canada operations	Canada		$	(12	)		$	16		North America	March
Bowline gas turbines	New York		42				(65		)	North America	December
Other			3				(4		)
Total			$	33			$	(53	)
2003:
Mirant Canada operations	Canada		46				35			North America	July
Other			—				11
Total			$	46			$	46
2002:
Kogan Creek	Australia		$	30			$	28		International	May, August
Other			19				13
Total			$	49			$	41

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The gain or loss amounts do not include the effects of impairments of these assets recorded prior to their sale.

Mirant Canada operations: In March 2004, Mirant closed on agreements to dispose of its Canadian natural gas transportation contracts and certain natural gas marketing contracts. As part of the sale agreements, Mirant paid approximately $12 million to have a third party assume these contracts, which released $28 million in liabilities related to such contracts. The resulting $16 million gain is reflected in loss (gain) on sales of assets, net for the year ended December 31, 2004 in the consolidated statements of operations.

Bowline gas turbines: During the third quarter of 2004, the Company committed to dispose of three natural gas turbines related to a suspended construction project. On October 6, 2004, the Company entered into an agreement to sell these turbines, subject to Bankruptcy Court approval. The Bankruptcy Court approved the sale on December 10, 2004. On December 30, 2004, the Company received $42 million related to the sale and expects $4 million in 2005. In the year ended December 31, 2004, the Company recognized a loss related to these turbines of $65 million in loss (gain) on sales of assets, net in the consolidated statements of operations.

Navotas 1: In March 2003, the Build Operate and Transfer (“BOT”) project agreement for Navotas 1 expired, and the plant was transferred to NPC pursuant to the terms of the BOT project agreement. No gain or loss was recorded on the transfer.

Mirant Canada operations: In April and July 2003, Mirant closed on agreements to sell its Canadian natural gas aggregator services contracts, a significant portion of its natural gas transportation contracts and a portion of its storage contracts. As part of the sale agreements, Mirant received approximately $33 million and $13 million in April and July 2003, respectively. Mirant recognized a pre-tax gain of approximately $25 million and $10 million related to these transactions in April and July 2003, respectively, which is reflected in gain on sale of assets in the accompanying consolidated statements of operations.

Kogan Creek: In May 2002, Mirant completed the sale of its 60% ownership interest in the Kogan Creek power project located near Chinchilla in southeast Queensland, Australia, and the associated coal deposits for approximately $30 million. The gain on the sale of Mirant’s investment in Kogan Creek was approximately $28 million.

AQC: In August 2002, Mirant completed the sale of its wholly-owned subsidiary MAP Fuels Limited, which wholly-owned AQC, a coal mining company in Queensland, Australia for approximately $21 million. The subsidiary was sold at a gain of approximately $2 million. The sale included both the Wilkie Creek Coal Mine and the Horse Creek coal deposits. The operating results for this business prior to its disposal are included in income (loss) from discontinued operations in the accompanying consolidated statements of operations.

Acquisitions

Sual and Pagbilao: The Sual project and the Pagbilao project shareholder agreements grant minority shareholders put option rights such that they can require Mirant Asia-Pacific Limited and/or certain of its subsidiaries to purchase the minority shareholders’ interests in the project. The put option for the Sual project, representing the remaining 5.15% ownership interest in the Sual project as of December 31, 2004, can be exercised until December 21, 2005, or thereafter in the event of any change in control, a change in the Sual project’s charter documents or the transfer of sponsor in violation of the sponsor support agreement on the earlier of the date of such changes/events or December 21, 2011. The put option for the Pagbilao project, representing the remaining 4.26% ownership interest in the Pagbilao project as of December 31, 2004, can be exercised the earlier of August 5, 2008 or, in the event of any change in control, a change in the Pagbilao project’s charter documents or the transfer of the sponsor in violation of the

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sponsor completion support agreement. The price for the put options is determined by a formula set forth in the shareholder agreements. The formula price is based on discounted future net cash flow less total liabilities plus current assets as of the date of the put notice.

In March 2003, Mirant paid approximately $30 million to acquire a 4.26% ownership interest in the Pagbilao project and in May 2003, Mirant paid approximately $30 million to acquire an additional 4.26% ownership interest in the Pagbilao project.

In March 2004, Mirant paid approximately $21 million to acquire an additional 2.94% ownership interest in the Sual project.

Sangi and Carmen: In April 2002, Mirant acquired ARB Power Ventures, Inc. and CMS Generation Cebu Limited Company, located in the Philippines, for approximately $21 million. The purchase included the Toledo Power Co., which owns the Sangi and Carmen generating facilities.

10. Investments

Following is a summary of the Company’s consolidated subsidiaries and equity affiliates in which Mirant has less than 100% ownership at December 31, 2004 and the carrying value of its equity method and other investments as of December 31, 2004 and 2003 (in millions):

	Country of	Year of		Economic Ownership Percentage at December 31,			Voting Interest Percentage at December 31,			December 31,
	Operations	Investment		2004			2004			2004			2003
Entities Consolidated:
Mirant Pagbilao Corporation (“Pagbilao”)	Philippines		1997		95.7	%		95.7	%
Mirant Sual Corporation (“Sual”)	Philippines		1997		94.9			94.9
Grand Bahama Power Company (“Grand Bahama Power”)	Bahamas		1993		55.4			57.0
Jamaica Public Service Company (“JPS”)	Jamaica		2001		80.0			80.0
Wrightsville Power Facility, L.L.C. (“Wrightsville”)	United States		2000		51.0			51.0
Entities accounted for under the Equity method:
The Power Generation Company of Trinidad and Tobago (“PowerGen”)	Trinidad		1994		39.0			39.0			$	80		$	82
KEPCO Ilijan Corporation (“Ilijan”)	Philippines		2000		20.0			20.0			56			52
Mirant Global Corporation (“MGC”)	Philippines		2002		50.0			50.0			27			25
Curacao Utilities Company (“CUC”)	Curacao, Netherlands, Antilles		2001		25.5			25.5			27			9
Other:
Investment in Aqualectra convertible preferred equity											40			40
Other											18			59
Total											$	248		$	267

Aqualectra: Mirant owns the $40 million convertible preferred equity interest in Aqualectra, an integrated water and electric company in Curacao, Netherlands Antilles, owned and operated by the government. The Company receives 16.75% preferred dividends on its investment on a quarterly basis. Aqualectra has a call option and Mirant has a put option related to this investment. The options became exercisable on December 19, 2004 and the options can be exercised at any time during the following three

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years from the beginning of this period. Aqualectra has the option (but not the obligation) to purchase from Mirant all, but not less than all, of the shares of preferred stock then held by Mirant on the terms as set forth in the agreement. Mirant has the option (but not the obligation) to require Aqualectra to purchase all, but not less than all, of the shares of preferred stock then held by Mirant on the terms as set forth in the agreement. Mirant also has an option to convert its convertible preferred equity interest in Aqualectra to common shares during the same three-year period beginning upon the date the options become exercisable.

Following is a summary of information related to completed sales of equity and other investments for the years ended December 31, 2004, 2003 and 2002 (in millions).

Investment	Gross Proceeds			Gain (Loss)				Impairment Loss
2004		$	—		$	—			$	—
2003:
Birchwood		70			67				—
Total		$	70		$	67			$	—
2002:
Bewag		$	1,632		$	249			$	—
SIPD		120			(7		)		—
Perryville		—			(1		)		—
WPD		235			(3		)		(325		)
Shajiao C		300			91				—
CEMIG		—			—				(132		)
Norway		—			—				(10		)
Total		$	2,287		$	329			$	(467	)

The gain or loss amounts do not include the effects of impairment losses relating to those investments prior to their sale.

Following is a summary of equity in income of affiliates attributable to investments for the years ended December 31, 2004, 2003 and 2002 (in millions).

	2004			2003			2002
Equity in income of affiliates:
Interests retained		$	26		$	26	$	27
Interests disposed of		—			7		141
		$	26		$	33	$	168

Description of Significant Activity

2004

Sual: The Sual project shareholder agreement grants minority shareholders put option rights such that they can require Mirant Asia-Pacific Limited and/or certain of its subsidiaries to purchase the minority shareholders’ interests in the project. See Note 9 for discussion of activity related to the shareholder agreement.

2003

Mirant Global Corporation: In June 2003, Mirant Global Corporation (“MGC”), a wholly-owned subsidiary of Mirant (Philippines) Corporation (“MPC”), entered into an agreement with the First Metro

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Investment Corporation Group (“the FMIC Group”) to pursue business opportunities in power generation in the Visayas region of the Philippines. The FMIC Group agreed to acquire the entire equity interest in Panay Power Corporation, which owns a 72 MW power generation facility on the island of Panay and the 22.8 MW Sunrise Power Project generation facility located in the island of Luzon. The total acquisition cost of these two projects is approximately $64 million in addition to the assumption of the project debt at Panay Power Corporation of approximately $32 million. Also, a new project debt of approximately $10 million has been raised for the 22.8 MW generation facility. The transaction closed on December 4, 2003. Effective December 4, 2003, the FMIC Group contributed its equity interest in Panay Power Corporation and in the project company that owns the 22.8 MW generation facility of the Sunrise Power Project to an entity, Claredon Tower Holdings, Inc. (“Claredon”). Claredon became a subsidiary of MGC in exchange for a 50% ownership interest in MGC. As a result, the FMIC Group and MPC each have a 50% voting interest in the joint venture. MPC’s investment in MGC at December 31, 2003 aggregated $25 million and is accounted for as an equity investment. The FMIC Group and MPC have agreed not to transfer all or any of their shares in MGC for a period of three years. No gain or loss was recorded as a result of this transaction.

Pagbilao: The Pagbilao project shareholder agreement grants minority shareholders put option rights such that they can require Mirant Asia-Pacific Limited and/or certain of its subsidiaries to purchase the minority shareholders’ interests in the project. See Note 9 for discussion of activity related to the shareholder agreement.

Birchwood: In May 2003, Mirant announced that it had entered an agreement to sell all but one half of one percent of its 50% ownership interest in the Birchwood generating plant located near Fredricksburg, Virginia. On October 9, 2003, the Bankruptcy Court entered an order approving the consummation of the sale. In October 2003, Mirant completed the sale for a price of $70 million and recorded a gain of approximately $67 million related to this transaction.

2002

Bewag: Prior to 2001, Mirant acquired a 26% interest in Bewag, an electric utility serving over 2 million customers in Berlin, Germany. In June 2001, Mirant purchased an additional 18.8% interest in Bewag for approximately $464 million. In February 2002, Mirant sold its interest in Bewag for approximately $1.63 billion and recorded a gain of approximately $249 million.

SIPD: In May 2002, Mirant sold its 9.99% ownership interest in SIPD, located in the Shandong Province, China, for approximately $120 million. The loss on the sale of Mirant’s investment in SIPD was approximately $7 million.

Perryville: In June 2002, Mirant sold its 50% ownership interest in Perryville to Cleco, which owned the remaining 50% interest. As part of the sale, Cleco assumed Mirant’s $13 million future equity commitment to Perryville and paid approximately $55 million in cash to Mirant in repayment of a subordinated loan to Perryville and for other miscellaneous costs. In connection with the sale, Mirant agreed to make a $25 million subordinated loan to Perryville. In 2002, Mirant and Perryville restructured the tolling agreement and Mirant made a $100 million subordinated loan to Perryville. The proceeds were used by Perryville to repay the existing $25 million subordinated loan owed to Mirant and to repay $75 million of senior debt of the project. On August 29, 2003, the Mirant Debtors filed a motion with the Bankruptcy Court to reject the tolling agreement with Perryville. The rejection was approved by the Bankruptcy Court on September 15, 2003. See Note 3 for additional information. Mirant recognized a $1 million loss on the sale of its investment in Perryville in 2002.

WPD: In September 2002, Mirant sold its 49% economic interest in Western Power Distribution Holdings Limited and WPD Investment Holdings (collectively, WPD) for approximately $235 million. WPD included the electric distribution networks for Southwest England and South Wales. In June 2002,

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Mirant recognized an impairment loss of approximately $325 million to reflect the difference between the carrying value of its investment and its estimated fair value. Upon completion of the sale in the third quarter of 2002, Mirant recognized an additional loss of $3 million.

Shajiao C: In December 2002, Mirant sold its indirect 33% interest in Shajiao C power project in Guangdong Province, China for approximately $300 million. Mirant recognized a gain of approximately $91 million on the sale.

CEMIG: In December 2002, Mirant recognized an impairment charge of approximately $132 million reflecting the current fair market value of its investment in CEMIG. The investment was sold in December 2002 at approximately its carrying value.

Norway Project: In the third quarter of 2002, Mirant recognized an impairment loss of approximately $10 million to reflect the difference between the carrying value of its investment in the project and its estimated fair value less costs to sell. In December 2002, Mirant completed the sale of its investment in the development project in Norway. The investment was sold at approximately its carrying value.

11. Restructuring Charges and Other Impairment Losses

Mirant adopted a plan in March 2002 to restructure its operations by exiting certain activities (including its European trading and marketing business), canceling or suspending planned power plant developments, closing business development offices, and severing employees in an effort to better position the Company to operate in the then current business environment. During 2004 and 2003, Mirant recorded additional restructuring charges of $14 million and $46 million, respectively.

Components of the impairment losses and restructuring charges for the years ended December 31, 2004, 2003 and 2002 are as follows (in millions):

	Years ended December 31,
	2004			2003			2002
Impairment losses		$	9		$	11		$	—
Restructuring charges:
Costs to cancel equipment orders and service agreements per contract terms		—			8			302
Severance of employees and other employee termination-related charges		14			38			61
Total restructuring charges		14			46			363
Total impairment losses and restructuring charges		$	23		$	57		$	363

The following is a summary of the liability for accrued restructuring charges for the years ended December 31, 2004 and 2003 (in millions):

	Years ended December 31,
	2004				2003
Balance, beginning of period.		$	19			$	9
Provision		14				53
Reversal		—				(7		)
Cash payments		(27		)		(36		)
Balance, end of period		$	6			$	19

During the year ended December 31, 2004, Mirant terminated approximately 451 employees as part of its restructuring activities and paid $27 million in severance and related restructuring charges.

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Approximately 300 of the employees terminated were part of Mirant’s international operations and the related restructuring charge for these terminations was recognized in December 2003.

During the year ended December 31, 2003, Mirant terminated approximately 550 employees as part of its restructuring activities and paid $36 million in severance and related restructuring charges.

12. Long-Term Debt

Long-term debt not included in liabilities subject to compromise at December 31, 2004 and 2003 was as follows (in millions):

	Interest Rate	2004			2003			Secured/ Unsecured
Long-Term Debt Not Included in Liabilities Subject to Compromise in 2004 and 2003:
Debtor-in-Possession Financing	LIBOR + 3.5% or Prime + 2.5%	$	—		$	—		Secured
West Georgia, due 2009	LIBOR + 2.625%	140			140			Secured
Mirant Sual project loan, due 2006 to 2012	LIBOR + 2.5% to 10.56%	547			640			Secured
Mirant Pagbilao project loan, due 2005 to 2007	LIBOR + 2.15% to 10.25%	166			233			Secured
Jamaica Public Service Company Limited, due 2005 to 2030	7% to 12%	241			224			Secured
Mirant Grand Bahamas Limited, due 2005 to 2006	LIBOR + 1.25%	13			14			Secured
Grand Bahama Power Company, due 2005 to 2014	LIBOR + 1.125%	29			29			Unsecured
Mirant Curacao Investments , Ltd., due 2005 to 2007	10.15%	14			16			Secured
Mirant Trinidad Investments, Inc., due 2006	10.2%	73			73			Secured
Capital leases, due 2015 through 2018	8.19% to 12.51%	146			161			—
Mirant Curacao Investments—deferred acquisition price, due 2005 to 2006	9.00%	6			8			Unsecured
Total		1,375			1,538
Less: current portion of long-term debt		(206		)	(256		)
Total long-term debt not included in liabilities subject to compromise in 2004, excluding current portion		$	1,169		$	1,282

At December 31, 2004, the annual scheduled maturities of long-term debt not subject to compromise during the next five years and thereafter were as follows (in millions):

2005	$	206
2006	387
2007	143
2008	98
2009	238
Thereafter	303
Total	$	1,375

Debtor-in-Possession Financing

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that serve as collateral for the DIP Facility. However, upon the occurrence of certain triggering events, including the sale of borrowing base assets or an event that has a material adverse effect on the business, operations or value of a power generation facility, the borrowing base may be revalued or reserves against the borrowing base may be imposed, thus lowering the borrowing base amount. The borrowing base as of December 31, 2004 was $724 million. The borrowing base decreased $48 million in January 2005 following the sale of Coyote Springs and will decrease another $37 million following the proposed sale of Wrightsville. The orders entered by the Bankruptcy Court approving the DIP Facility permit up to $300 million of borrowings, which amount may be increased to $500 million upon written approval of each of the Statutory Committees or further order of the Bankruptcy Court. The DIP Facility also contains an option, exercisable by Mirant or Mirant Americas Generation, to remove Mirant Americas Generation and its subsidiaries as borrowers and obligors under the DIP Facility and reduce the DIP Facility commitment to a maximum of $200 million of borrowings. Borrowings under the DIP Facility are secured by substantially all of the assets of the DIP Borrowers.

Jamaica Public Service Company Credit Facilities

In February 2004, Jamaica Public Service Company Limited, in which Mirant has an 80% ownership interest, entered into a $30 million, 7-year amortizing credit facility (“2004 RBTT credit facility”) with RBTT Merchant Bank Limited. The proceeds from this facility were used to replace the construction financing of the Bogue construction project completed in 2003. The loans are non-recourse to Mirant Corporation. The loan agreements contain a number of covenants, including (i) restrictions on change of control; (ii) restrictions on the issuance or purchase of borrower’s shares; (iii) limitations on transactions with affiliates; (iv) limitations on the incurrence of new debt; and (v) limitations on dividends. The Company was in compliance with the covenants as of December 31, 2004.

Jamaica Public Service Company Limited is also party to a separate $30 million, 7-year amortizing credit facility with RBTT Merchant Bank Limited entered into in 2003 (“2003 RBTT credit facility”) and a $45 million, 12-year amortizing credit facility with International Finance Corporation (“IFC credit facility”). In connection with the 2004 RBTT, 2003 RBTT and IFC credit facilities, Jamaica Public Service Company Limited was required to obtain and register a title related to property on which the 120MW facility at Bogue is situated to facilitate registration of the lenders’ mortgages. At December 31, 2003, Jamaica Public Service Company Limited had secured title and was actively working with the lender’s local attorneys to register the mortgages, but had not finalized the registration at that time, which represented a breach of the IFC credit facility and a potential breach of the 2004 RBTT and 2003 RBTT credit facilities. As a result, the Company included amounts outstanding under the 2003 RBTT and IFC credit facilities in the current portion of long-term debt on its consolidated balance sheets at December 31, 2003. In June 2004, the registration of the mortgage was finalized and the amounts outstanding under the 2004 RBTT, 2003 RBTT and IFC credit facilities were reclassified to long-term debt. The Company was in compliance with the covenants as of December 31, 2004.

In October 2004, Jamaica Public Service Company Limited entered into an $8 million, 5-year amortizing credit facility (“2004 AIC credit facility”) with AIC Capital Market Brokers Limited. The proceeds from this facility were used to replace working capital and other funds used to repay a previous credit facility. The facility is non-recourse to Mirant Corporation. The facility is secured by a mortgage on the corporate headquarters and related real property of Jamaica Public Service Company Limited. The Company was in compliance with the covenants as of December 31, 2004.

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Grand Bahama Power Company Limited Credit Facilities

In November 2004, Grand Bahama Power Company Limited entered into a $48 million senior unsecured credit facility (“2004 GBPC facility”) with Scotiabank (Bahamas) Limited. The 2004 GBPC facility includes a $28 million 10-year amortizing term facility and a $20 million construction facility. As of December 2004, Grand Bahama Power Company Limited has drawn the entire term facility and $2 million of the construction facility. In addition, a $10 million letter of credit has been issued under the construction facility. The construction facility converts into an amortizing term facility at the conclusion of the construction period (up to sixteen months) and matures together with the $28 million term facility. The facility is non-recourse to Mirant Corporation. The loan agreement for the 2004 GBPC facility contains a number of covenants, including (i) restrictions on change of control and sales of assets; (ii) restrictions on capital expenditures; (iii) limitations on transactions with affiliates; (iv) limitations on the incurrence of new debt; and (v) limitations on dividends. In addition, the credit facility includes a debt service coverage maintenance covenant and a tangible net worth maintenance covenant. The Company was in compliance with the covenants as of December 31, 2004.

13. Income Taxes

The provision (benefit) for income taxes from continuing operations is as follows (in millions):

	Years Ended December 31,
	2004			2003		2002
Current Provision (Benefit):
United States	$	(32	)	$	2	$	(114	)
Foreign	69			78		35
Subtotal	37			80		(79		)
Deferred Provision:
United States	—			14		877
Foreign	50			32		151
Subtotal	50			46		1,028
Provision for income taxes	$	87		$	126	$	949

A reconciliation of the Company’s federal statutory income tax provision to the effective income tax provision for continuing operations adjusted for restructuring items for the years ended December 31, 2004, 2003 and 2002 is as follows (in millions):

	2004			2003			2002
United States federal statutory income tax rate	$	(106	)	$	(1,215	)	$	(461	)
State and local income tax, net of federal income taxes	(1		)	(24		)	(30		)
Foreign earnings and dividends taxed at different rates	(64		)	(61		)	(80		)
Impairment of non-deductible goodwill	—			517			—
Residual tax on foreign earnings	93			88			380
Tax credits				—			—
Change in deferred tax asset valuation allowance excluding discontinued operations	139			882			1,088
Other differences, net	26			(61		)	52
Tax Provision	$	87		$	126		$	949

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Sual and Ilijan facilities, respectively. The amount of benefit from these holiday incentives is $54 million, $50 million, and $69 million for 2004, 2003, and 2002, respectively.

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and their respective tax bases which give rise to deferred tax assets and liabilities are as follows (in millions):

	Years Ended December 31,
	2004				2003
Deferred Tax Assets:
Obligations under energy delivery and purchase commitments		$	329			$	453
Employee benefits		45				24
Reserves		248				240
Accumulated other comprehensive income		29				2
Operating loss carryforwards		1,413				1,182
Unrealized foreign exchange losses		88				113
Property and intangible assets		762				685
Deferred cost		50				18
Energy marketing and risk management contracts		2				10
Other		118				153
Subtotal		3,084				2,880
Valuation allowance		(2,369		)		(2,207		)
Net deferred tax assets		$	715			$	673
Deferred Tax Liabilities:
Tax accrued on foreign earnings		(621		)		(568		)
Other		(121		)		(105		)
Total		(742		)		(673		)
Net deferred taxes		$	(27	)		$	—

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

As of December 31, 2004, the Company has approximately $2.8 billion of U.S. federal net operating loss (“NOL”) carryforwards for financial reporting purposes. Similarly, there are approximately $3.9 billion of state NOL carryforwards. The ultimate utilization of the Company’s NOLs will depend on several factors, such as the amount of the Company’s debt that is cancelled through the bankruptcy proceedings and the financial plan contained in the proposed Plan. If a portion of the debt is cancelled, the amount of the cancelled debt will reduce tax attributes such as NOLs and tax basis on fixed assets which, depending on the proposed Plan and certain tax elections, could partially or fully utilize the available NOLs. In

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addition, the Company has approximately $705 million of foreign net operating loss carryforwards with varying expiration dates which are available to offset future taxable income in those jurisdictions. A significant portion of the deferred tax assets related to these foreign losses are also subject to a valuation allowance.

The Company has negotiated a settlement agreement with the Internal Revenue Service (IRS) for certain tax liabilities arising from their audit of the Company’s federal income tax returns for tax years when it was a subsidiary of the Southern Company. This agreement results in an assessment of $39 million including interest. The Company has provided adequate tax provisions in prior years for the recognition of this liability.

The Company has contingent liabilities related to tax uncertainties arising in the ordinary course of business. The Company periodically assesses its contingent liabilities in connection with these uncertainties based upon the latest information available. For those uncertainties where it is probable that a loss has occurred and the loss or range of loss can be reasonably estimated, a liability is recorded on the consolidated financial statements. As additional information becomes available, the assessment and estimates of such liabilities are adjusted accordingly.

14. Employee Benefit Plans

Mirant offers pension benefits to its domestic nonunion and union employees through various defined benefit and defined contribution pension plans. These benefits are based on pay, service history and age at retirement. Defined benefit pensions are not provided for nonunion employees hired after April 1, 2000 who participate in a profit sharing arrangement. Most pension benefits are provided through tax-qualified plans that are funded in accordance with Employee Retirement Income Security Act of 1974 (“ERISA”) and IRS requirements. Certain executive pension benefits that cannot be provided by the tax-qualified plans are provided through unfunded non-tax-qualified plans. In August 2004, these non-tax qualified plans were approved for continuation by the Bankruptcy Court for eligible employees and directors actively employed on July 9, 2004. These plans are currently not approved by the Bankruptcy Court for former employees and such balances remain as claims against the estate. The measurement date for the domestic benefit plans is September 30 for each year presented.

Grand Bahama Power participates in defined benefit, trusteed, non-contributory pension plans for all nonunion and union employees. Plan benefits are based on the employees’ years of service, age at retirement, and average compensation for the highest five years out of the ten years immediately preceding retirement. Plan assets are primarily invested in equity and debt securities. The measurement date for Grand Bahama Power is December 31 for each year presented.

Jamaica Public Service Company (“JPS”) participates in a defined benefit, trusteed, contributory pension plan covering all categories of permanent employees. Benefits earned are based on years of service, age at retirement, and the highest average annual salary during any consecutive three-year period. The measurement date for JPS is December 31 for each year presented.

The rates assumed in the actuarial calculations for measuring year-end pension obligations as of their respective measurement dates were as follows:

	Domestic				JPS				Grand Bahamas
	2004		2003		2004		2003		2004		2003
Discount rate	5.73	%	6.00	%	10.00	%	9.00	%	6.75	%	6.75	%
Rate of compensation increase	3.00		3.75		8.00		7.00		5.00		5.00

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The following tables show the collective actuarial results for the defined benefit pension plans of Mirant (in millions):

	Domestic Tax- Qualified						Domestic Non-Tax- Qualified						International
	2004			2003			2004			2003			2004			2003
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	186		$	159		$	7		$	11		$	57		$	54
Service cost	9			9			1			1			1			2
Interest cost	11			10			0			1			5			4
Benefits paid	(5		)	(3		)	—			—			(6		)	(2		)
Actuarial loss	(4		)	17			—			10			(4		)	6
Special termination benefits	—			—			—			—			—			—
Amendments	5			(6		)	1			1			—			—
Employee contributions	—			—			—			—			2			2
Plan curtailment	—			—			—			—			(4		)	—
Impact of foreign exchange rates	—			—			—			—			(1		)	(9		)
Liability settled	—			—			—			(17		)	—			—
Benefit obligation, end of year	$	202		$	186		$	9		$	7		$	50		$	57
Changes in Plan Assets:
Fair value of plan assets, beginning of year	$	72		$	54		$	—		$	—		$	80		$	73
Return on plan assets	8			10			—			—			20			17
Settlement	—			—			—			(17		)	—			—
Impact of foreign exchange rates	—			—			—			—			(1		)	(13		)
Employee contributions	—			—			—			—			2			2
Employer contributions	14			11			—			17			2			3
Benefits paid	(5		)	(3		)	—			—			(6		)	(2		)
Fair value of plan assets, end of year	$	89		$	72		$	—		$	—		$	97		$	80
Funded Status:
Funded status at end of year	$	(113	)	$	(114	)	$	(9	)	$	(7	)	$	47		$	23
Unrecognized prior service cost	4			(1		)	2			1			3			4
Unrecognized net loss (gain)	10			15			4			4			(21		)	(6		)
Net amount recognized	(99		)	(100		)	(3		)	(2		)	29			21
Intangible asset	—			—			(2		)	(1		)	—			—
Additional minimum liability reflected in accumulated other comprehensive income	—			—			(2		)	(2		)	—			—
Total liability recognized	(99		)	(100		)	(7		)	(5		)	29			21
Fourth quarter funding	2			2			—			—			—			—
Total (liability) asset recognized on the consolidatedbalance sheets	$	(97	)	$	(98	)	$	(7	)	$	(5	)	$	29		$	21
Unfunded accumulated benefit obligation	$	(70	)	$	(63	)	$	(7	)	$	(5	)	60
Accumulated benefit obligation	159			135			7			5			37

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The components of the net periodic cost of Mirant’s pension plans for the years ended December 31, 2004, 2003 and 2002 are shown below (in millions).

	2004			2003			2002
Service cost	$	13		$	13		$	12
Interest cost	17			15			15
Expected return on plan assets	(15		)	(12		)	(11		)
Curtailment gain	(4		)	—			(4		)
Settlement loss	—			9			—
Employee contributions	(2		)	(2		)	(2		)
Special termination benefits	—			—			2
Net amortization(1)	0			1			1
Net periodic pension cost	$	9		$	24		$	13
Other comprehensive expense related to additional minimum pension liability	$	—		$	—		$	2

(1) Amount includes unrecognized transition obligation or asset, prior service cost and actuarial gains or losses.

The rates assumed in the actuarial calculations for measuring pension cost each year were as follows:

	Domestic						JPS						Grand Bahamas
	2004		2003		2002		2004		2003		2002		2004		2003		2002
Discount rate	6.00	%	6.75	%	7.50	%	9.00	%	9.00	%	9.00	%	6.75	%	7.00	%	7.00	%
Rate of compensation increase	3.75		3.75		4.50		7.00		7.00		7.00		5.00		5.00		5.00
Expected return on plan assets	8.50		8.50		9.00		10.00		10.00		10.00		6.25		6.25		7.25

In determining the long-term rate of return for plan assets, historical markets and current market factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined and consideration of diversification and portfolio rebalancing is given. Peer data and historical returns are reviewed to check for reasonableness and appropriateness.

The following table shows the target allocation and percentage of fair value of plan assets by asset category for Mirant’s domestic qualified pension plans for 2004 and 2003:

	2004						2003
	Target Allocation			Percentage of Fair Value of Plan Assets			Target Allocation			Percentage of Fair Value of Plan Assets
Domestic equity		55	%		56	%		55	%		55	%
International equity		15			16			15			15
Fixed income		30			28			30			30
Total		100	%		100	%		100	%		100	%

For the domestic qualified pension plans, Mirant uses a mix of equities and fixed income investments in an attempt to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. Equity investments are diversified across U.S. and non-U.S. stocks. For U.S. stocks, Mirant employs a passive approach by investing in an index that mirrors the Russell 3000 Index. For non-U.S. stocks, Mirant is invested in the Invesco International Equity Fund that is benchmarked against the Europe-Australia-Far East (“EAFE”) Index. Fixed income investments include a passive bond market index fund which seeks to replicate the Lehman Brothers Aggregate Bond Index. Investment risk is monitored on an ongoing basis through quarterly portfolio reviews and annual pension liability measurements.

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The investments held by Mirant’s international plans are subject to country-specific regulations. Approximately 97% of the international plan assets are associated with the JPS pension plan. As of December 31, 2004, those assets were invested as follows:

	December 31, 2004
Equity Securities		14	%
Government of Jamaica Debt Securities		68
Real Estate		13
Cash Equivalents		5
Total		100	%

During 2005, Mirant expects to contribute approximately $14 million to the domestic qualified pension plans, approximately $0.5 million to the domestic non-tax-qualified pension plans, and approximately $2.3 million to international pension plans. Additionally, Mirant expects the following benefits to be paid from the pension plans (in millions).

Projected Benefit Payments to Plan Participants	Domestic Tax- Qualified			Domestic Non-Tax- Qualified		International
2005		$	5.1		$0.5		$	1.4
2006		5.4			0.2		1.5
2007		5.8			0.2		1.7
2008		6.4			0.2		2.0
2009		6.9			0.3		2.2
2010 through 2014		54.0			2.1		15.2

Other Postretirement Benefits

Mirant also provides certain medical care and life insurance benefits for eligible retired domestic employees which are accounted for on an accrual basis using an actuarial method that recognizes the net periodic costs as employees render service to earn the postretirement benefits. The measurement date for these domestic other post-retirement benefit plans is September 30 for each year presented.

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003. This act expands Medicare, primarily by adding a prescription drug benefit starting in 2006 and is expected to reduce the Company’s cost of providing prescription drug benefits for Medicare-eligible retirees. On July 1, 2004, Mirant measured a reduction of $6 million in the Accumulated Post-Retirement Benefit Obligation reflecting the expected impact of the Act. Accordingly, Mirant also recorded a reduction in the net expense for Mirant’s postretirement benefit plans of $0.4 million for the six month period after this re-measurement through the end of the fiscal year.

In measuring the accumulated postretirement benefit obligation at year-end, the weighted average medical care cost trend rate for pre-age 65 participants and post-age 65 participants was assumed to be 11.00% and 14.00%, respectively, for 2005, decreasing gradually to 5.00% for both pre-age 65 participants and post-age 65 participants through the year 2011 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would correspondingly increase or decrease the accumulated benefit obligation at September 30, 2004 by $10 million and $12 million, respectively.

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Weighted average rates assumed in the actuarial calculations for other postretirement benefit obligations as of their respective measurement dates were as follows:

	2004		2003
Discount rate	5.73	%	6.00	%
Rate of compensation increase	3.00		3.75

The following table shows the actuarial calculations for other postretirement benefit obligations as of their respective measurement dates (in millions):

	2004		2003
Change in Benefit Obligation:
Benefit obligation, beginning of year	$117		$97
Service cost	4		4
Interest cost	7		6
Actuarial loss	12		13
Amendments	(3	)	(2	)
Settlements	—		—
Plan curtailment	—		—
Net benefits paid	(2	)	(1	)
Benefit obligation, end of year	$135		$117
Funded Status:
Funded status at end of year	$(135	)	$(117	)
Unrecognized net loss	44		33
Unrecognized past service cost	(2	)	1
Net amount recognized	$(93	)	$(83	)

The domestic postretirement benefits were unfunded at December 31, 2003 and 2002. The components of the net expense for Mirant’s postretirement benefit plans during the years ended December 31 are shown below (in millions).

	2004		2003		2002
Service cost	$	4	$	4	$	3
Interest cost	7		7		6
Curtailment loss	—		—		2
Settlement gain	—		—		(1		)
Net amortization	1		1		1
Net postretirement benefit expense	$	12	$	12	$	11

In measuring the cost of postretirement benefits for 2004, the weighted average medical care cost trend rate for pre-age 65 participants and post-age 65 participants was assumed to be 7.78% and 9.80%, respectively, for 2004, decreasing gradually to 5.50% for both pre-age 65 participants and post-age 65 participants through the year 2008 and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1% would correspondingly increase or decrease the aggregate of the service and interest cost components of the annual postretirement benefit cost in 2004 by $1 million.

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Other weighted average rates assumed in the actuarial calculations for Mirant’s postretirement benefit costs during the years ended December 31 are shown below:

	2004		2003		2002
Assumed discount rate	6.00	%	6.75	%	7.50	%
Assumed rate of compensation increases	3.75		3.75		4.50

Mirant expects to contribute approximately $3.5 million to pay other post-retirement benefits for retired domestic employees in 2004. Additionally, Mirant expects the following net benefits to be paid from the post-retirement benefit plans:

Projected Benefit Payments to Plan Participants	Net Employer Benefits Before Reflecting Government Subsidies			Government Provided Subsidy for Prescription Drug Benefits				Net Employer Benefits After Reflecting Government Subsidies
Fiscal 2005		$	3.5		$	0.0			$	3.5
Fiscal 2006		4.1			0.0				4.1
Fiscal 2007		4.7			0.0				4.7
Fiscal 2008		5.4			(0.1		)		5.3
Fiscal 2009		6.3			(0.1		)		6.2
Fiscal Years 2010 through 2014		46.1			(1.2		)		44.9

JPS provides certain medical care and life insurance benefits for its eligible retired employees. At December 31, 2004, the accumulated postretirement benefit obligation was $9 million based on a discount rate of 10%, rate of compensation increase of 8% and an assumed annual increase in health care costs of 9%.

An increase or decrease in the assumed annual rate of increase in health care costs of 1% would correspondingly increase or decrease the accumulated benefit obligation for JPS at December 31, 2004 by $2.2 million and $1.7 million, respectively.

The postretirement benefits provided by JPS were unfunded at December 31, 2004.

Grand Bahama Power does not provide postretirement benefits other than pensions for its employees.

Stock-Based Compensation

Stock option grants have been made from Mirant’s Omnibus Incentive Compensation Plan. Options are granted with a 10-year term. Generally, options vest equally on each of the first, second and third anniversaries of the grant date. Options are nontransferable, except upon the death of the option holder. The exercise price of options granted is equal to the stock price on the date of grant.

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A summary of options granted, exercised and forfeited is as follows:

	Options		Weighted Average Exercise Price
Outstanding at December 31, 2001	15,322,159			$	21.93
Granted	7,838,765			$	9.08
Exercised	(42,731	)		$	3.35
Forfeited	(2,453,392	)		$	16.95
Outstanding at December 31, 2002	20,664,801			$	17.69
Granted	7,669,891			$	1.62
Exercised	—			$	—
Forfeited	(7,124,021	)		$	14.56
Outstanding at December 31, 2003	21,210,671			$	12.93
Granted	—			$	—
Exercised	—			$	—
Forfeited	(5,677,939	)		$	12.39
Outstanding at December 31, 2004	15,532,732			$	13.12
Options exercisable at December 31, 2004	11,563,358			$	16.34

The following table provides information with respect to stock options outstanding at December 31, 2004:

	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Exercise Price			Weighted Average Remaining Contractual Life		Number of Options	Weighted Average Exercise Price
$0.00-$7.86	4,397,108		$	1.66		7.7	1,573,200		$	1.76
$7.87-$19.65	5,815,892		$	11.90		5.0	4,670,426		$	12.59
$19.66-27.51	5,278,759		$	23.85		4.6	5,278,759		$	23.85
$27.52-$39.30	40,973		$	34.64		6.2	40,973		$	34.64
Total	15,532,732		$	13.12		5.6	11,563,358		$	16.34

No stock options were granted during 2004. The weighted average fair value at date of grant for options granted during 2003 and 2002 was $1.19 and $5.80, respectively, and was estimated using the Black-Scholes option valuation model with the following weighted average assumptions:

	2004		2003		2002
Expected life in years		—	5		5
Risk free interest rate		—	2.82	%	4.34	%
Volatility		—	98.00	%	75.00	%
Dividend yield		—	—		—

Phantom Stock and Restricted Stock

During 2004, no phantom stock or restricted stock was granted. During 2003 and 2002, Mirant made awards of 4,725,000 shares and 1,244,185 shares of phantom stock and restricted stock, respectively, to certain officers and employees. The phantom stock awards are payable in cash based upon the price of Mirant common stock on the vesting date. The outstanding phantom stock grants vest over time between March 2005 and February 2007. The restricted stock awards are paid in shares of Mirant common stock. One-half of the restricted stock awards vest in shares on each of the first and second anniversary dates of

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the grant date. Compensation expense recognized for the phantom stock and restricted stock plans during 2004, 2003 and 2002 was approximately $610 thousand, $2 million, and $5 million respectively. A summary of phantom stock and restricted stock awarded is as follows:

	Phantom Stock			Restricted Stock
Outstanding at December 31, 2001		94,362			—
Granted		944,185			300,000
Vested		(377,674	)		—
Forfeited		(129,413	)		—
Outstanding at December 31, 2002		531,460			300,000
Granted		4,425,000			300,000
Vested		(1,132,366	)		—
Forfeited		(568,895	)		(300,000	)
Outstanding at December 31, 2003		3,255,199			300,000
Granted		—			—
Vested		(1,671,209	)		—
Forfeited		(661,525	)		(300,000	)
Outstanding at December 31, 2004		922,465			—

Employee Stock Purchase Plan

Under the 2000 Employee Stock Purchase Plan (the “ESPP”), the Company is authorized to issue up to 4,000,000 shares of common stock to its full-time employees, nearly all of whom are eligible to participate. In 2003, an additional 8,000,000 shares of common stock was authorized to be issued under the ESPP. Under the terms of the ESPP, a new purchase cycle starts on May 1 and November 1 of each year and employees of the Company can elect to have up to $10,625 of base and bonus amounts withheld to purchase the Company’s common stock during a purchase cycle. The purchase price of the stock is 85% of the lower of its beginning-of-the-cycle or end-of-cycle market price. Under the ESPP, the Company sold 1,415,859 shares and 985,421 shares to employees in 2003 and 2002 respectively. No shares were sold during 2004 because the ESPP was suspended indefinitely on May 1, 2003.

Employee Savings Plan

The Company maintains an Employee Savings Plan (“ESP”) with a profit sharing arrangement (“PSA”) whereby employees may contribute a portion of their base compensation to the ESP, subject to limits under the Internal Revenue Code. The Company provides a matching contribution each payroll period equal to 75% of the employee’s contributions up to 6% of the employee’s pay for that period (match levels vary by bargaining unit). Under the PSA, the Company contributes a quarterly fixed contribution of 3% of eligible pay and may make an annual discretionary contribution for those employees not accruing a benefit under the defined benefit pension plan. Expenses recognized for the matching and profit sharing contributions were as follows (in millions):

	ESP			PSA
2004		$	5		$	2
2003		6			4
2002		8			8

15. Litigation and Other Contingencies

The Company is involved in a number of significant legal proceedings. In certain cases, plaintiffs seek to recover large and sometimes unspecified damages, and some matters may be unresolved for several years. The Company cannot currently determine the outcome of the proceedings described below or the

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ultimate amount of potential losses and therefore has not made any provision for such matters unless specifically noted below. Pursuant to SFAS No. 5, “Accounting for Contingencies,” management provides for estimated losses to the extent information becomes available indicating that losses are probable and that the amounts are reasonably estimable. Additional losses could have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Effect of Chapter 11 Filings

On the Petition Date, August 18, 2003, October 3, 2003, and November 18, 2003, the Mirant Debtors filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code.

As of the Petition Date, most pending litigation (including some of the actions described below) is stayed, and absent further order of the Bankruptcy Court, no party, subject to certain exceptions, may take any action, again subject to certain exceptions, to recover on pre-petition claims against the Mirant Debtors. One exception to this stay of litigation is for an action or proceeding by a governmental agency to enforce its police or regulatory power. The claims asserted in litigation and proceedings to which the stay applies may be fully and finally resolved in connection with the administration of the bankruptcy proceedings and, to the extent not resolved, will need to be addressed in the Plan. On November 19, 2003, the Bankruptcy Court entered an order staying most litigation pending against current or former officers, directors and managers of the Mirant Debtors arising out of the performance of their duties and against certain potential indemnitees of the Mirant Debtors. The Bankruptcy Court took that action to avoid the risk that the continuation of such litigation would impede the Mirant Debtors’ ability to reorganize or would have a negative impact upon the assets of the Mirant Debtors. At this time, it is not possible to predict the outcome of the Chapter 11 filings or their effect on the business of the Mirant Debtors or outstanding legal proceedings. The Mirant Debtors intend to resolve as many of these claims as possible through the claims resolution process in the bankruptcy proceeding or the Plan.

California and Western Power Markets

The Company is subject to litigation related to its activities in California and the western power markets and the high prices for wholesale electricity experienced in the western markets during 2000 and 2001. Various lawsuits and complaints have been filed by the California Attorney General, the California Public Utility Commission (“CPUC”), the California Electricity Oversight Board (“EOB”) and various states’ rate payers in state and federal courts and with the Federal Energy Regulatory Commission (“FERC”). Most of the plaintiffs in the rate payer suits seek to represent a state-wide class of retail rate payers. In addition, civil and criminal investigations have been initiated by the United States Department of Justice (“DOJ”), the General Accounting Office, the FERC and various states’ attorneys general. These matters involve claims that the Company engaged in unlawful business practices and generally seek unspecified amounts of restitution and penalties, although the damages alleged to have been incurred in some of the suits are in the billions of dollars. One of the suits brought by the California Attorney General seeks an order requiring the Company to divest its California plants. In addition, the Company is subject to the proceedings described below in California Receivables, FERC Show Cause Proceeding Relating to Trading Practices, FERC Investigation Relating to Bidding, and DWR Power Purchases relating to its operations in California and the western power markets. Resolution of these matters, to the extent not fully and finally resolved through either the settlement of certain claims described below in “California Settlement” or the claims process, is subject to resolution of the ongoing litigation for the matters pending in courts and for those matters pending at the FERC to the issuance of final decisions by the FERC.

California Receivables: In 2001, Southern California Edison Company (“SCE”) and Pacific Gas and Electric Company (“PG&E”) suspended payments to the California Power Exchange Corporation (“Cal PX”) and California Independent System Operator Corporation (“CAISO”) for certain power purchases, including purchases from Mirant Americas Energy Marketing. Both the Cal PX and PG&E filed for

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bankruptcy protection in 2001. As discussed below under “California Settlement,” on January 14, 2005, Mirant and certain of its subsidiaries entered into a Settlement and Release of Claims Agreement (the “California Settlement”) with PG&E, SCE, San Diego Gas and Electric Company, the CPUC, the California Department of Water Resources (“DWR”), the EOB and the Attorney General of the State of California (collectively, the “California Parties”) and with the Office of Market Oversight and Investigations of the FERC. If the California Settlement becomes effective, it will result in Mirant Americas Energy Marketing assigning to the California Parties its outstanding receivables for sales made in the Cal PX and CAISO markets from January 1, 2000 through June 20, 2001.

In July 2001, the FERC issued an order requiring proceedings (the “FERC Refund Proceedings”) to determine the amount of any refunds and amounts owed for sales made to the CAISO or the Cal PX from October 2, 2000 through June 20, 2001 (the “Refund Period”). Various parties have appealed these FERC orders to the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) seeking review of a number of issues, including changing the Refund Period to include periods prior to October 2, 2000 and expanding the sales of electricity subject to potential refund to include bilateral sales made to the DWR. Any such expansion of the Refund Period or the types of sales of electricity potentially subject to refund could significantly increase the refund exposure of Mirant Americas Energy Marketing in this proceeding. Although Mirant Americas Energy Marketing is the Mirant entity that engaged in transactions with the CAISO and the Cal PX, the orders issued by the FERC in the refund proceedings, and the filings made by other parties in those proceedings, generally refer to the Mirant entity involved as Mirant without being more specific. Mirant believes that the Mirant entity that would actually be liable to third parties for any refunds determined by the FERC to be owed, or that would be due any receivables found to be owed to Mirant, is Mirant Americas Energy Marketing. Agreements that were in effect at the time of the transactions at issue between Mirant Americas Energy Marketing and the Mirant Americas Generation subsidiaries that own Mirant’s generating facilities in California would shift some of the economic burden of such refunds or the benefit of such receivables from Mirant Americas Energy Marketing to those Mirant Americas Generation subsidiaries. On December 12, 2002, the ALJ determined the preliminary amounts currently owed to and by each entity acting as a scheduling coordinator in the CAISO and Cal PX markets, including Mirant Americas Energy Marketing. Based on the ALJ’s determination, the initial amounts owed to Mirant Americas Energy Marketing totaled approximately $122 million, which is net of refunds owed by Mirant Americas Energy Marketing to the CAISO and the Cal PX. The ALJ decision indicated that the amounts did not reflect the final mitigated market clearing prices, interest that would be applied under the FERC’s regulations, offsets for emission costs or the effect of certain findings made by the ALJ in the initial decision. A December 2002 errata issued by the ALJ to his initial decision indicated that the amounts identified by the initial decision as being owed to Mirant Americas Energy Marketing and other participants in the Cal PX market failed to reflect an adjustment for January 2001 that the ALJ concluded elsewhere in his initial decision should be applied. If that adjustment is applied, the net amount owed Mirant Americas Energy Marketing after taking into account the proposed refunds would increase by approximately $37 million.

On March 26, 2003, the FERC largely adopted the findings of the ALJ made in his December 12, 2002 order with the exception that the FERC concluded that the price of gas used in calculating the mitigated market prices used to determine refunds should not be based on published price indices. Instead, the FERC ruled that the price of gas should be based upon the price at the producing area plus transportation costs. This adjustment by the FERC to the refund methodology is expected to reduce the net amount that would remain owed to Mirant Americas Energy Marketing after taking into account any refunds. Based solely on the FERC staff’s formula, the amount of the reduction could be as much as approximately $110 million, which would reduce the net amount owed to Mirant Americas Energy Marketing to approximately $49 million. The FERC indicated that it would allow any generator that can demonstrate it actually paid a higher price for gas to recover the differential between that higher price and the proxy price for gas adopted by the FERC. Mirant Americas Energy Marketing’s actual cost of gas used

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to make spot sales of electricity was higher than the amounts calculated under the staff’s formula, which differential, if accepted by the FERC, would decrease significantly the $110 million and increase the resulting net amount owed to Mirant Americas Energy Marketing, although the amount of such potential decrease that will be accepted by the FERC and the resulting net amount owed to Mirant Americas Energy Marketing cannot at this time be determined. On October 16, 2003, the FERC issued an order addressing motions for rehearing filed with respect to its March 26, 2003 order, and in that October 16, 2003 order the FERC changed how certain power sales made to the CAISO were to be treated. Mirant Americas Energy Marketing estimates that the effect of the October 16, 2003 order will be to increase the net amounts owed to Mirant Americas Energy Marketing by $27 million. On May 12, 2004, the FERC issued an order on rehearing of the October 16, 2003 order that further modified how certain power sales made to the CAISO are to be treated and that may reduce significantly the potential benefit to Mirant Americas Energy Marketing of the October 16, 2003 order. In another order issued May 12, 2004, the FERC also further refined the methodology to be used to determine the costs of gas that a generator can recover where it can demonstrate that it paid a higher price for gas than the proxy price for gas previously adopted by the FERC in its March 23, 2003 order, and those changes may have the effect of reducing the costs that Mirant Americas Energy Marketing is able to recover. Mirant Americas Energy Marketing sought rehearing of the May 12, 2004 order addressing the recovery of fuel costs, but the FERC denied that request for rehearing on September 24, 2004. Mirant Americas Energy Marketing is unable at this time to quantify further the impact of the May 12, 2004 orders.

In the July 25, 2001 order, the FERC also ordered that a preliminary evidentiary proceeding be held to develop a factual record on whether there had been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest from December 25, 2000 through June 20, 2001. In that proceeding, the California Attorney General, the CPUC and the EOB filed to recover certain refunds from parties, including Mirant Americas Energy Marketing, for bilateral sales of electricity to the DWR at the California/Oregon border, claiming that such sales took place in the Pacific Northwest. The refunds sought from Mirant Americas Energy Marketing totaled approximately $90 million. If Mirant Americas Energy Marketing were required to refund such amounts, subsidiaries of Mirant Americas Generation could be required under inter-company agreements with Mirant Americas Energy Marketing to refund amounts previously received from Mirant Americas Energy Marketing pursuant to sales made on their behalf by Mirant Americas Energy Marketing during the refund period. In addition, these Mirant Americas Generation subsidiaries would be owed amounts for refunds received by Mirant Americas Energy Marketing related to purchases made on their behalf by Mirant Americas Energy Marketing from other sellers in the Pacific Northwest. In an order issued June 25, 2003, the FERC ruled that no refunds were owed and terminated the proceeding. On November 10, 2003, the FERC denied requests for rehearing filed by various parties. Various parties have appealed the FERC’s decision to the Ninth Circuit.

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On September 9, 2004 the Ninth Circuit reversed the FERC’s dismissal of a complaint filed by the California Attorney General in 2002 that sought refunds for transactions conducted in markets administered by the CAISO and the Cal PX outside the Refund Period set by the FERC and for transactions between the DWR and various owners of generation and power marketers, including Mirant Americas Energy Marketing and subsidiaries of Mirant Americas Generation. The Ninth Circuit remanded the proceeding to the FERC for it to determine what remedies, including potential refunds, are appropriate where entities, including Mirant Americas Energy Marketing, purportedly did not comply with certain filing requirements for transactions conducted under market-based rate tariffs. The FERC’s actions on remand could materially increase the potential exposure of Mirant Americas Energy Marketing to liability for refunds in the proceedings described above relating to sales made to the CAISO or the Cal PX, including sales occurring before October 2, 2000, bilateral sales to DWR and bilateral sales in the Pacific Northwest. On October 25, 2004, Mirant Americas Energy Marketing and other defendants filed a petition for rehearing with the Ninth Circuit.

As discussed below under “California Settlement,” once effective, it will result in the release of most of Mirant Americas Energy Marketing’s potential liability in the FERC Refund Proceedings and the other FERC proceedings described in this section. Under the California Settlement, the California Parties will release Mirant and its subsidiaries from any liability to the California Parties related to sales of electricity and natural gas in the western markets from January 1, 1998 through July 14, 2003, including any claims for refunds in the FERC Refund Proceedings or in any proceedings conducted by FERC as a result of the Ninth Circuit’s ruling with respect to the complaint filed by the California Attorney General. Also, the California Parties will assume the obligation of Mirant Americas Energy Marketing to pay any refunds determined by the FERC to be owed by Mirant Americas Energy Marketing to other parties for transactions in the CAISO and Cal PX markets during the Refund Period. Some of the consideration to be received by the California Parties under the settlement will be available to other market participants that choose to opt into the settlement. Any market participant that elects to opt into the settlement will give releases of liability to Mirant Americas Energy Marketing that are the same as those given by the California Parties. Subject to applicable bankruptcy law, however, Mirant Americas Energy Marketing will continue to be liable for any refunds that FERC determines it to owe (1) to participants in the Cal PX and CAISO markets that are not California Parties (or that do not elect to opt into the settlement) for periods outside of the Refund Period and (2) to participants in bilateral transactions with Mirant Americas Energy Marketing that are not California Parties (or that do not elect to opt into the settlement).

FERC Show Cause Proceeding Relating to Trading Practices: On June 25, 2003, the FERC issued a show cause order (the “Trading Practices Order”) to more than fifty parties, including Mirant Americas Energy Marketing and subsidiaries of Mirant Americas Generation, that a FERC staff report issued on March 26, 2003 identified as having potentially engaged in one or more trading strategies of the type employed by Enron Corporation and its affiliates (“Enron”), as described in the Enron memos released by the FERC in May 2002. The Trading Practices Order identified certain specific trading practices that the FERC indicated could constitute gaming or anomalous market behavior in violation of the CAISO and Cal PX tariffs. The Trading Practices Order requires the CAISO to identify transactions between January 1, 2000 and June 20, 2001 that may involve the identified trading strategies, and then requires the applicable sellers involved in those transactions to demonstrate why those transactions were not violations of the Cal PX and CAISO tariffs. On September 30, 2003, the Mirant entities filed with the FERC for approval of a settlement agreement (the “Trading Settlement Agreement”) entered into between certain Mirant entities and the FERC Trial Staff, under which Mirant Americas Energy Marketing would pay $332,411 to settle the show cause proceeding, except for the issue related to selling of ancillary services, which is discussed below. In a November 14, 2003 order in a different proceeding, the FERC ruled that certain allegations of improper trading conduct with respect to the selling of ancillary services during 2000 should be resolved in the show cause proceeding. On December 19, 2003, the Mirant entities filed with the FERC for approval of an amendment to the Trading Settlement Agreement reached with the FERC Trial Staff with respect to

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the sale of ancillary services under which the FERC would have an allowed unsecured claim in Mirant Americas Energy Marketing’s bankruptcy proceeding for $3.67 million in settlement of the allegations with respect to the sale of ancillary services (the “Ancillary Amount”). That settlement must be approved by the FERC and the Bankruptcy Court to become effective. The Mirant entities are in the process of obtaining FERC approval and will seek approval from the Bankruptcy Court thereafter. On March 11, 2004, the ALJ recommended that the FERC approve the settlement, finding that the settlement amounts were reasonable. The ALJ, however, suggested that approval of the settlement be conditioned on the Ancillary Amount being treated as an administrative claim or a setoff rather than as an allowed pre-petition claim.

As discussed below under “California Settlement,” if the California Settlement becomes effective, it will result in the California Parties withdrawing their opposition to the Trading Settlement Agreement as amended and supporting approval of the Trading Settlement Agreement as proposed by the Mirant entities that are parties to the Trading Settlement Agreement and the FERC Trial Staff without change or modification.

FERC Investigation Relating to Bidding: On June 25, 2003, the FERC issued an order (the “Bidding Order”) initiating an investigation by its staff into bidding practices in the Cal PX and CAISO markets between May 1, 2000 and October 1, 2000 of more than fifty parties, including Mirant Americas Energy Marketing. These entities were previously identified in a report issued by the FERC Staff on March 26, 2003 as having bid generation resources to the Cal PX and CAISO at prices unrelated to costs. The Bidding Order requires those entities, including Mirant Americas Energy Marketing, to demonstrate why bids in the Cal PX and CAISO markets from May 1, 2000 through October 1, 2000 that were in excess of $250 per MWh did not constitute a violation of the CAISO and Cal PX tariffs. If the FERC finds that Mirant Americas Energy Marketing engaged in bidding practices that violated the Cal PX or CAISO tariffs between May 1, 2000 through October 1, 2000, the FERC could require the disgorgement of profits made as a result of those bids and could impose other non-monetary penalties. While Mirant Americas Energy Marketing believes its bidding practices were legitimate and that it did not violate the appropriate tariffs, the standards by which the FERC will ultimately judge Mirant Americas Energy Marketing ‘s bidding practices are unclear. Depending on the standards applied by the FERC and if Mirant Americas Energy Marketing is found by the FERC to have violated the Cal PX or CAISO tariffs, the amount of any disgorgement of profits required or other remedy imposed by the FERC could have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

DWR Power Purchases: On May 22, 2001, Mirant Americas Energy Marketing entered into a 19-month agreement with the DWR to provide the State of California with approximately 500 MW of electricity during peak hours through December 31, 2002 (the “DWR Contract”). On February 25, 2002, the CPUC and the EOB filed separate complaints at the FERC against Mirant Americas Energy Marketing and other sellers of energy under long-term agreements with the DWR, alleging that the terms of these contracts were unjust and unreasonable and that the contracts should be abrogated or the prices under the contracts should be reduced. The complaints allege that the prices the DWR was forced to pay pursuant to these long-term contracts were unreasonable due to dysfunctions in the California market and the alleged market power of the sellers. On June 26, 2003, the FERC issued an order dismissing the complaints filed by the CPUC and the EOB against Mirant Americas Energy Marketing. On November 10, 2003, the FERC denied motions for rehearing filed by the CPUC and the EOB. The CPUC and EOB have appealed the FERC’s decision to the Ninth Circuit.

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Parties of any liability with respect to the DWR Contract and the dismissal by the CPUC and the EOB of their appeal of the FERC’s decision dismissing their complaints.

Reliability Must Run Agreements Proceeding. Certain of the generating facilities acquired by subsidiaries of Mirant Americas Generation from PG&E are operated subject to reliability-must-run agreements (“RMR Agreements”), which those subsidiaries assumed from PG&E. These agreements allow the CAISO to require the Mirant Americas Generation subsidiaries, under certain conditions, to operate these facilities to support the California electric transmission system. The rates that the Mirant Americas Generation subsidiaries could charge the CAISO under those agreements, where they were also making sales into the market and were retaining the revenues from those sales, were the subject of an ongoing disputed rate proceeding before the FERC at the time of the acquisition of the plants from PG&E and were being collected subject to refund. For the plants that are subject to the RMR Agreements and from which the Mirant Americas Generation subsidiaries have exercised their rights to also make market sales, the Mirant Americas Generation subsidiaries have been collecting from the CAISO since April 1999 an amount equal to 50% of the annual fixed revenue requirement (the “Annual Requirement”) of those plants. The amounts the Mirant Americas Generation subsidiaries collect from the CAISO are subject to refund pending final review and approval by the FERC. While the CAISO is the party to the RMR Agreements with the Mirant Americas Generation subsidiaries, the CAISO’s obligations under those agreements are funded by PG&E, and PG&E is the real party in interest with respect to any refunds owed by the Mirant Americas Generation subsidiaries for sales made previously under those agreements. In June 2000, the ALJ issued a decision finding that the amount the Mirant Americas Generation subsidiaries should be allowed to charge the CAISO for such plants was approximately 3½% on average of the Annual Requirement. In July 2000, the Mirant Americas Generation subsidiaries sought review by the FERC of the ALJ decision, and a decision is pending at the FERC.

The Mirant Americas Generation subsidiaries recognize revenue related to these agreements based on the rates ruled to be reasonable by the ALJ. If the Mirant Americas Generation subsidiaries are unsuccessful in seeking modification of the ALJ’s decision by the FERC, they will be required to refund amounts collected in excess of those rates for the period from June 1, 1999. For the Potrero plant and Pittsburg Units 1 through 4 the period for which such refunds would be owed would run through December 31, 2001, for Mirant America Generation’s other California plants except Pittsburg Unit 5 the refund period would run through December 31, 2002, and for Pittsburg Unit 5 the refund period would run through December 31, 2003. Amounts collected in excess of those rates and other significantly smaller amounts collected under the RMR Agreements that are also subject to refund due to other issues pending at the FERC totaled $293 million, of which $288 million is included in liabilities subject to compromise and $5 million is deferred and included in revenues subject to refund in the accompanying consolidated balance sheet as of December 31, 2004 and December 31, 2003. In addition, Mirant Americas Generation records accrued interest on such amounts, which amounted to $42 million and is included in liabilities subject to compromise in the accompanying consolidated balance sheets as of December 31, 2004 and December 31, 2003, respectively.

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Americas Generation, Mirant California Investments, Inc., Mirant California, LLC, Mirant Delta, LLC, Mirant Potrero, LLC, Mirant Special Procurement, Inc., Mirant Services, LLC, and Mirant Americas Development, Inc. (collectively, the “Mirant Settling Parties”). The “California Parties” are PG&E, SCE, San Diego Gas and Electric Company, the CPUC, the DWR, the EOB and the Attorney General of the State of California. The effectiveness of the California Settlement is conditioned upon its approval by the CPUC, the Bankruptcy Court, the bankruptcy court having jurisdiction over PG&E’s bankruptcy proceedings initiated in 2001, and the FERC. While CPUC has approved the California Settlement, as signified by its execution of the California Settlement, the other approvals have not yet been obtained.

If the California Settlement becomes effective, (1) Mirant Americas Energy Marketing and the other Mirant Settling Parties will assign to the California Parties all receivables owed to Mirant Americas Energy Marketing for transactions in the markets administered by the Cal PX or the CAISO for the period January 1, 2000 through June 20, 2001, which are currently estimated by the parties to the California Settlement to be approximately $283 million, and (2) the California Parties will receive an allowed, unsecured claim against Mirant Americas Energy Marketing in its Chapter 11 case for $175 million and the DWR will receive an additional allowed, unsecured claim against Mirant Americas Energy Marketing of $2.25 million. In return, the California Parties will release all claims they may have against the Mirant Settling Parties related to sales of electricity or natural gas at wholesale in western markets in the period from January 1, 1998 through July 14, 2003, including all such claims filed by the California Parties in the Mirant Debtors’ Chapter 11 cases, in proceedings currently pending before the FERC, or in four pending suits filed by the California Attorney General. Mirant estimates that, excluding duplicative claims, this settlement will compromise the bulk of the California energy market claims at issue in the FERC Refund Proceedings. Also, the California Parties will assume Mirant Americas Energy Marketing’s obligation to pay any refunds determined by the FERC to be owed by Mirant Americas Energy Marketing to other parties for transactions in the CAISO and Cal PX markets during the Refund Period. Subject to applicable bankruptcy law, Mirant Americas Energy Marketing will continue to be liable for any refunds that the FERC determines it to owe to (1) participants in the Cal PX or CAISO markets other than the California Parties for periods outside the Refund Period or (2) parties with which Mirant Americas Energy Marketing engaged in bilateral electricity or natural gas transactions other than the California Parties.

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FERC of the conduct of the Mirant Settling Parties in the western energy markets in 2000 and 2001, including the pending investigation pursuant to the Bidding Order.

The California Settlement will also resolve all claims asserted by PG&E against Mirant Delta,, Mirant Potrero, and the other Mirant Settling Parties in the Chapter 11 cases or in proceedings before the FERC that relate to refunds potentially owed as described under “Reliability-Must-Run Agreements Proceeding” above. Under the California Settlement, PG&E will release Mirant Delta and Mirant Potrero from any potential refund liability under the RMR Agreements for the period prior to September 30, 2004, and the claims filed by PG&E in the Chapter 11 cases seeking to recover refunds from Mirant Delta and Mirant Potrero for sales made under the RMR Agreements will be withdrawn with prejudice. Although the California Settlement will not result in the withdrawal of the claims filed in the Chapter 11 cases by the CAISO, under the terms of the California Settlement, the FERC’s approval of the California Settlement will constitute its direction to CAISO to conform its books and records to the terms of the California Settlement and to withdraw with prejudice all claims filed by it in the Chapter 11 cases that seek to recover amounts related to sales made under the RMR Agreements in the period prior to September 30, 2004. In addition, the CAISO has separately agreed with Mirant to release its claims upon the California Settlement becoming effective.

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effective by January 1, 2006 and has not been terminated, the first power purchase agreement will be extended through December 31, 2006 and the second agreement will start January 1, 2007 if the settlement becomes effective.

Accounting Impact of California Settlement. At December 31, 2004, the Company had recorded receivables and related reserves associated with amounts due to Mirant Americas Energy Marketing from the CAISO and Cal PX related to the period from October 2000 to June 2001 and reserves related to refunds under the PMR Agreements in amounts that substantially correspond to the claims and other consideration contemplated by the California Settlement. At this time, the Company anticipates that the California Settlement will ultimately result in a small net gain.

Shareholder-Bondholder Litigation

Mirant Securities Consolidated Action. Twenty lawsuits have been filed since May 2002 against Mirant and four of its officers alleging, among other things, that the defendants violated federal securities laws by making material misrepresentations and omissions to the investing public regarding Mirant’s business operations and future prospects during the period from January 19, 2001 through May 6, 2002 due to potential liabilities arising out of its activities in California during 2000 and 2001. The complaints seek unspecified damages, including compensatory damages, and the recovery of reasonable attorneys’ fees and costs. These suits have been consolidated into a single action.

In November 2002, the plaintiffs filed an amended complaint that added as defendants Southern, the directors of Mirant immediately prior to its initial public offering of stock, and various firms that were underwriters for the initial public offering by the Company. In addition to the claims set out in the original complaint, the amended complaint asserts claims under the Securities Act of 1933, alleging that the registration statement and prospectus for the initial public offering of Mirant’s stock misrepresented and omitted material facts. On July 14, 2003, the district court dismissed the claims asserted by the plaintiffs based on the Company’s California business activities but allowed the case to proceed on the plaintiffs’ other claims. This action is stayed as to Mirant by the filing of its Chapter 11 proceeding. On November 19, 2003, the Bankruptcy Court entered an order staying this action also with respect to the other defendants to avoid the suit’s impeding Mirant’s ability to reorganize or having a negative effect upon Mirant’s assets. The Bankruptcy Court has modified the stay to allow the plaintiffs to proceed with discovery of documentary materials from Mirant and the other defendants. On December 11, 2003, the plaintiffs filed a proof of claim against the estate of Mirant, which was subsequently withdrawn on or about October 10, 2004. Because of the stay applicable to the litigation, Mirant has not yet been released as a defendant in the consolidated lawsuits.

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Company also provide for Mirant to indemnify such firms against any losses arising out of any acts or omissions by Mirant and its subsidiaries.

Shareholder Derivative Litigation. Four purported shareholders’ derivative suits have been filed against Mirant, its directors and certain officers of the Company. Two of those suits have been consolidated. These lawsuits allege that the directors breached their fiduciary duty by allowing the Company to engage in alleged unlawful or improper practices in the California energy markets in 2000 and 2001. The Company practices alleged in these lawsuits largely mirror those alleged with respect to the Company’s activities in California in the shareholder litigation discussed above. One suit also alleges that the defendant officers engaged in insider trading. The complaints seek unspecified damages on behalf of the Company, including attorneys’ fees, costs and expenses and punitive damages. These actions are stayed as to Mirant by the filing of its Chapter 11 proceeding. The plaintiffs have not filed a claim in the Bankruptcy Court against the Company. On November 19, 2003, the Bankruptcy Court entered an order staying these actions also with respect to the individual defendants to avoid the suits impeding Mirant’s ability to reorganize or having a negative effect upon Mirant’s assets. On December 8, 2003, the court in the Cichocki suit took notice of the Bankruptcy Court’s Order dated November 19, 2003 staying the litigation and administratively closed the action.

ERISA Litigation. On April 17, 2003 and June 3, 2003, purported class action lawsuits alleging violations of the Employee Retirement Income Security Act (“ERISA”) were filed in the United States District Court for the Northern District of Georgia (the “ERISA Litigation”). The ERISA Litigation names as defendants Mirant Corporation, certain of its current and former officers and directors, and Southern. The plaintiffs, who seek to represent a putative class of participants and beneficiaries of Mirant’s 401(k) plans (the “Plans”), allege that defendants breached their duties under ERISA by, among other things, (1) concealing information from the Plans’ participants and beneficiaries; (2) failing to ensure that the Plans’ assets were invested prudently; (3) failing to monitor the Plans’ fiduciaries; and (4) failing to engage independent fiduciaries to make judgments about the Plans’ investments. The plaintiffs seek unspecified damages, injunctive relief, attorneys’ fees and costs. On September 2, 2003, the District Court issued an order consolidating the two suits. On September 23, 2003, the plaintiffs filed an amended and consolidated complaint. The amended and consolidated complaint asserted similar factual allegations as the previously filed lawsuits and added as defendants T. Rowe Price Trust Company and certain additional current and former officers of the Company. The consolidated action is stayed as to Mirant by the filing of its Chapter 11 proceeding. On November 19, 2003, the Bankruptcy Court entered an order staying this action also with respect to the other defendants to avoid the suit impeding the ability of Mirant to reorganize or having a negative effect upon Mirant’s assets. By agreement, however, the suit has been allowed to proceed through the filing of, and ruling by the district court upon, motions to dismiss. On January 9, 2004, T. Rowe Price Trust Company answered the amended and consolidated complaint. All other defendants filed motions on that date seeking dismissal of the plaintiffs’ claims for failure to state a claim upon which relief can be granted. On February 19, 2004, the plaintiffs dismissed their claims against Southern without prejudice. On June 14, 2004, the plaintiffs filed a motion seeking to amend their consolidated complaint to add as defendants Mirant Services, LLC and its board of managers.

On August 4, 2004, the United States District Court for the Northern District of Georgia entered an order staying the ERISA Litigation until the Bankruptcy Court lifts the stays resulting from the filing of Mirant’s bankruptcy proceedings and the order entered by the Bankruptcy Court on November 19, 2003 staying the action with respect to the other defendants. In the order issued August 4, 2004, the district court also denied the motions to dismiss filed by various defendants, including Mirant, and the motion filed by the plaintiffs seeking to amend their consolidated complaint to add as defendants Mirant Services, LLC and its board of managers. With respect to both motions, the district court granted the party filing the motion leave to refile the motion once the stays have been lifted by the Bankruptcy Court.

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Mirant Americas Generation Bondholder Suit. On June 10, 2003, certain holders of senior notes of Mirant Americas Generation maturing after 2006 filed a complaint in the Court of Chancery of the State of Delaware, California Public Employees’ Retirement System, et al. v. Mirant Corporation, et al., that named as defendants Mirant, Mirant Americas, Inc, Mirant Americas Generation, certain past and present Mirant directors, and certain past and present Mirant Americas Generation managers. Among other claims, the plaintiffs assert that a restructuring plan pursued by the Company prior to its filing a petition for reorganization under Chapter 11 of the Bankruptcy Code was in breach of fiduciary duties allegedly owed to them by Mirant, Mirant Americas, Inc. and Mirant Americas Generation’s managers. In addition, plaintiffs challenge certain dividends and distributions made by Mirant Americas Generation. Plaintiffs seek damages in excess of one billion dollars. Mirant has removed this suit to the United States District Court for the District of Delaware. This action is stayed with respect to the Mirant entities that are defendants by the filing of the Chapter 11 proceedings of these entities. On November 19, 2003, the Bankruptcy Court entered an order staying this action also with respect to the individual defendants to avoid the suit impeding the ability of the Mirant Debtors to reorganize or having a negative effect upon the assets of the Mirant Debtors. The committee representing unsecured creditors of Mirant Americas Generation filed a motion in Mirant’s bankruptcy proceedings seeking to pursue claims against Mirant, Mirant Americas, Inc. certain past and present Mirant directors, and certain past and present Mirant Americas Generation managers similar to those asserted in this suit. The Bankruptcy Court ruled that while the committee has standing to assert claims on behalf of the estate of Mirant Americas Generation, no such claims could be filed without the Bankruptcy Court’s approval and no motions seeking such approval could be filed at least through April 2004. No such motion has been filed with the Bankruptcy Court since April 2004, and the Bankruptcy Court has not authorized any such litigation at this time.

Mirant Americas Generation Securities Class Action. On June 11, 2003, a purported class action lawsuit alleging violations of Sections 11 and 15 of the Securities Act of 1933 was filed in the Superior Court of Fulton County, Georgia entitled Wisniak v. Mirant Americas Generation, LLC, et al. The lawsuit names as defendants Mirant Americas Generation and certain current and former officers and managers of Mirant Americas Generation. The plaintiff seeks to represent a putative class of all persons who purchased debt securities of Mirant Americas Generation pursuant to or traceable to an exchange offer completed by Mirant Americas Generation in May 2002 in which $750 million of bonds registered under the Securities Act were exchanged for $750 million of previously issued senior notes of Mirant Americas Generation. The plaintiff alleges, among other things, that Mirant Americas Generation’s restatement in April 2003 of prior financial statements rendered the registration statement filed for the May 2002 exchange offer materially false. The complaint seeks damages, interest and attorneys’ fees. The defendants have removed the suit to the United States District Court for the Northern District of Georgia. This action is stayed as to Mirant Americas Generation by the filing of its Chapter 11 proceeding. On November 19, 2003, the Bankruptcy Court entered an order staying this action also with respect to the individual defendants to avoid the suit impeding the ability of Mirant Americas Generation to reorganize or having a negative effect upon its assets. On December 8, 2003, the district court took notice of the Bankruptcy Court’s Order dated November 19, 2003 staying the litigation and administratively closed the action. On December 16, 2003, the plaintiff dismissed Mirant Americas Generation as a defendant,

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without prejudice, and filed a proof of claim against Mirant Americas Generation in the bankruptcy proceedings asserting the same claims set forth in the lawsuit.

Mirant Americas Generation and the plaintiff have entered into a stipulation of settlement of the Wisniak suit and the claim filed against Mirant Americas Generation that was approved by the Bankruptcy Court on January 19, 2005. Under the terms of the stipulation of settlement, the plaintiff will seek certification of a class by the district court that will receive $2.25 million to be paid by insurers for Mirant Americas Generation, and an allowed, unsecured claim for $2 million against Mirant subordinated to the claims of its other unsecured creditors. Members of the plaintiff class will have the opportunity to opt out of the settlement, and if class members who choose to opt out own in the aggregate more than 1% of the Mirant Americas Generation bonds that are the subject of the suit, then the Mirant defendants have the option to withdraw from the settlement. The stipulation of settlement must also be approved by the district court to become effective.

U.S. Government Inquiries

SEC Investigation: In August 2002, Mirant received a notice from the Division of Enforcement of the Securities and Exchange Commission (“SEC”) that it was conducting an investigation of Mirant. The Division of Enforcement has asked for information and documents relating to various topics such as accounting issues (including accounting issues announced by Mirant on July 30, 2002 and August 14, 2002), energy trading matters (including round trip trades), Mirant’s accounting for transactions involving special purpose entities, and information related to shareholder litigation. In late June 2003, the Division of Enforcement advised Mirant that its investigation of Mirant had become a formal investigation in February 2003. Mirant intends to continue to cooperate fully with the SEC.

Department of Justice Inquiries: In 2002 the Company was contacted by the DOJ regarding the Company’s disclosure of accounting issues, energy trading matters and allegations contained in the amended complaint discussed above in Mirant Securities Consolidated Action that Mirant improperly destroyed certain electronic records related to its activities in California. The Company has been asked to provide copies of the same documents requested by the SEC in their inquiry described above in SEC Investigation, and the Company intends to continue to cooperate fully with the DOJ. The DOJ has advised Mirant that it does not intend to take further action with respect to the allegations of improper destruction of electronic records.

In November 2002, Mirant received a subpoena from the DOJ, acting through the United States Attorney’s office for the Northern District of California, requesting information about its activities and those of its subsidiaries for the period since January 1, 1998. The subpoena requested information related to the California energy markets and other topics, including the reporting of inaccurate information to the trade press that publish natural gas or electricity spot price data. The subpoena was issued as part of a grand jury investigation. Mirant has continued to receive additional requests for information from the United States Attorney’s office, and it intends to continue to cooperate fully with the United States Attorney’s office in this investigation.

CFTC Inquiry: In 2002, the Commodity Futures Trading Commission (“CFTC”) asked Mirant Americas Energy Marketing for information about certain buy and sell transactions occurring during the period from January 1, 1999 through June 17, 2002. Mirant Americas Energy Marketing provided information regarding such trades to the CFTC, none of which it considers to be wash trades. In March 2003, Mirant Americas Energy Marketing received a subpoena from the CFTC requesting a variety of documents and information related to Mirant Americas Energy Marketing’s trading of electricity and natural gas and its reporting of transactional information to energy industry publications that prepare price indices for electricity and natural gas in the period from January 1, 1999 through the date of the subpoena. In December 2004, Mirant and Mirant Americas Energy Marketing entered into a settlement with the CFTC that resolves the CFTC’s inquiry into whether Mirant Americas Energy Marketing misrepresented

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natural gas trading information in 2000 and 2001. Pursuant to the settlement, Mirant and Mirant Americas Energy Marketing consented to the entry of an order by the CTFC in which it makes findings, which are neither admitted or denied by Mirant and Mirant Americas Energy Marketing, that (1) from January 2000 through December 2001, certain Mirant Americas Energy Marketing natural gas traders (i) knowingly reported inaccurate price, volume, and/or counterparty information regarding natural gas cash transactions to publishers of natural gas indices; and (ii) inaccurately reported to index publishers transactions observed in the market as Mirant Americas Energy Marketing transactions and (2) from January to October 2000, certain Mirant Americas Energy Marketing west region traders knowingly delivered the false reports in an attempt to manipulate the price of natural gas. Under the settlement, the CFTC received a subordinated allowed, unsecured claim against Mirant Americas Energy Marketing of $12.5 million in the Chapter 11 proceedings.

Department of Labor Inquiries: On August 21, 2003, the Company received a notice from the Department of Labor (the “DOL”) that it was commencing an investigation pursuant to which it was undertaking to review various documents and records relating to the Mirant Services Employee Savings Plan and the Mirant Services Bargaining Unit Employee Savings Plan. The DOL has interviewed Mirant personnel regarding those plans. The Company intends to continue to cooperate fully with the DOL.

PEPCO Litigation

In 2000, Mirant purchased certain power generating assets and certain other assets from PEPCO, including certain power purchase agreements (“PPAs”). Under the terms of the Asset Purchase and Sale Agreement (the “APSA”) Mirant and PEPCO entered into a contractual arrangement (the “Back-to-Back Agreement”) with respect to certain PPAs, including PEPCO’s long-term PPAs with Ohio Edison Company and Panda-Brandywine L.P. (“Panda”) under which (1) PEPCO agreed to resell to Mirant all “capacity, energy, ancillary services and other benefits” to which it is entitled under those agreements; and (2) Mirant agreed to pay PEPCO each month all amounts due from PEPCO to Panda or Ohio Edison for the immediately preceding month associated with such capacity, energy, ancillary services and other benefits. The Panda and Ohio Edison PPAs run until 2021 and 2005, respectively. Under the Back-to-Back Agreement, Mirant is obligated to purchase power from PEPCO at prices that are significantly higher than existing market prices for power.

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On December 9, 2004, the district court held that the Back-to-Back Agreement was a part of and not severable from, and therefore could not be rejected apart from, the APSA. The district court also noted that if the Fifth Circuit overturned the district court’s ruling with respect to severability, the Back-to-Back Agreement should be rejected only if Mirant can prove that the Back-to-Back Agreement burdens the bankrupt estates; that, after scrutiny and giving significant weight to the comments of the FERC relative to the effect of rejection on the public interest, the equities balance in favor of rejecting the Back-to-Back Agreement; and that rejection of the Back-to-Back Agreement would further the Chapter 11 goal of permitting the successful rehabilitation of the Mirant Debtors. The Mirant Debtors have appealed the district court’s December 9, 2004, decision to the Fifth Circuit and requested that the Fifth Circuit hear this appeal on an expedited basis. On March 8, 2005, the Fifth Circuit denied Mirant’s request to have the appeal expedited.

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Administrative Expense Motion, and dismissed PEPCO’s appeal of the January 19 order denying the Administrative Expense Motion as moot. The Mirant Debtors on March 4, 2005 filed a motion requesting the district court to reconsider its order of March 1, 2004 or alternatively to stay that order while the Mirant Debtors appeal it to the Fifth Circuit. On March 7, 2005, the district court modified the March 1 order to require PEPCO to file a response to the Mirant Debtors’ motion for reconsideration by March 14 and to delay until March 18, 2005, the date by which the Mirant Debtors are to pay past-due, unpaid obligations under the Back-to-Back Agreement.

Enron Bankruptcy Proceedings

Since December 2, 2001, Enron and a number of its subsidiaries have filed for bankruptcy. As of December 31, 2004, the total amount owed to Mirant by Enron was approximately $69 million. Mirant has filed formal claims in the Enron bankruptcy proceedings. Mirant has recorded an allowance for potential bad debts of $64 million as of December 31, 2004. Due to the approval of Enron’s plan of reorganization in the third quarter of 2004 and the status of the Company’s claims against Enron, the Company reduced its allowance by $10 million in the third quarter of 2004. This amount is reflected as a reduction of operations and maintenance expense in the consolidated statements of operations for the year ended December 31, 2004.

EcoElectrica Litigation

In March 2002, two subsidiaries of Edison International (collectively “EME”) filed suit alleging Mirant breached its agreement to purchase EME’s 50% interest in EcoElectrica Holdings Ltd., the owner of a 540 MW cogeneration facility in Puerto Rico. On April 29, 2003, EME amended its complaint to assert additional claims for fraudulent misrepresentation and concealment, conspiracy to defraud, and negligent misrepresentation. EME seeks compensatory damages in excess of $50 million, punitive and exemplary damages of an unspecified amount, interest and attorneys’ fees. EME has filed proofs of claim in the bankruptcy proceedings against Mirant and certain of its subsidiaries seeking damages based on the

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same allegations. Mirant has entered into a settlement in principle with EME that will result in EME receiving an allowed, unsecured claim against Mirant for $7 million. That settlement is currently being documented and is subject to the approval of the Bankruptcy Court.

At the same time Mirant and its subsidiaries entered into the contract with EME, they entered into a separate agreement with a subsidiary of Enron Corporation (“Enron”) to purchase an additional 47.5% ownership interest in EcoElectrica. That purchase also was not completed, and the Enron subsidiary has filed claims against Mirant in its Chapter 11 proceeding asserting damages for breach of the purchase agreement with Enron. Mirant has entered into a settlement in principle with Enron that will result in Enron receiving an allowed, unsecured claim against Mirant for $12.25 million. That settlement is currently being documented and is subject to the approval of the Bankruptcy Court and of the United States Bankruptcy Court for the Southern District of New York, before which Enron’s bankruptcy proceedings are pending.

Environmental Liabilities

EPA Information Request. In January 2001, the Environmental Protection Agency (the “EPA”) issued a request for information to Mirant concerning the air permitting and air emission control implications under the EPA’s new source review regulations promulgated under the Clean Air Act (“NSR”) of past repair and maintenance activities at Mirant Potomac River, LLC’s Potomac River plant in Virginia and Mirant Americas Generation’s Chalk Point, Dickerson and Morgantown plants in Maryland. The requested information concerns the period of operations that predates the Company’s ownership and lease of the plants. Mirant has responded fully to this request. Under the sales agreement with PEPCO for those plants, PEPCO is responsible for fines and penalties arising from any violation associated with historical operations prior to Mirant’s acquisition of the plants. If a violation is determined to have occurred at any of the plants, the Mirant entity owning the plant may be responsible for the cost of purchasing and installing emission control equipment, the cost of which may be material. If such violation is determined to have occurred after Mirant acquired the plants or, if occurring prior to the acquisition, is determined to constitute a continuing violation, the Mirant entity owning the plant at issue would also be subject to fines and penalties by the state or federal government for the period subsequent to its acquisition of the plant, the cost of which may be material.

Potomac River Notice of Violation. On September 10, 2003, the Virginia Department of Environmental Quality (“ Virginia DEQ”) issued a Notice of Violation (“NOV”) to Mirant Potomac River, LLC (“Mirant Potomac”) alleging that it violated its Virginia Stationary Source Permit to Operate by emitting nitrogen oxide (“NOx”) in excess of the “cap” established by the permit for the 2003 summer ozone season. Mirant Potomac responded to the NOV, asserting that the cap is unenforceable and that it can comply through the purchase of emissions credits and raising other equitable defenses. Virginia’s civil enforcement statute provides for injunctive relief and penalties. On January 22, 2004, the EPA issued an NOV to Mirant Potomac alleging the same violation of its Virginia Stationary Source Permit to Operate as set out in the NOV issued by the Virginia DEQ. On September 27, 2004, Mirant Potomac, Mirant Mid-Atlantic, the Virginia DEQ, the Maryland Department of the Environment, the DOJ and the EPA entered into, and filed for approval with the United States District Court for the Eastern District of Virginia, a consent decree that, if approved, will resolve Mirant Potomac’s potential liability for matters addressed in the NOVs previously issued by the Virginia DEQ and the EPA. The consent decree requires Mirant Potomac and Mirant Mid-Atlantic to install pollution control equipment at Mirant Potomac’s Potomac River plant and at the Morgantown plant leased by Mirant Mid-Atlantic in Maryland; to comply with declining system-wide ozone season NOx emissions caps from 2004 through 2010; to comply with system-wide annual NOx emissions caps starting in 2004; to meet seasonal system average emissions rate targets in 2008; and to pay civil penalties and perform supplemental environmental projects in and around the Potomac River plant expected to achieve additional environmental benefits. Except for the installation of the controls planned for the Potomac River units and the installation of selective catalytic reduction

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(“SCR”) or equivalent technology at Mirant Mid-Atlantic’s Morgantown Units 1 and 2 in 2007 and 2008, the consent decree does not obligate the Mirant entities to install specifically designated technology, but rather to reduce emissions sufficiently to meet the various NOx caps. Moreover, as to the required installations of SCRs at Morgantown, Mirant Mid-Atlantic may choose not to install the technology by the applicable deadlines and leave the units off either permanently or until such time as the SCRs are installed. The aggregate amount of the civil penalties to be paid and costs to be incurred by Mirant Potomac for the supplemental environmental projects is $1.5 million. The consent decree is subject to the approval of the district court and the Bankruptcy Court.

Mirant Potomac Downwash Study. On September 23, 2004, the Virginia DEQ and Mirant Potomac entered into an order by consent with respect to the Potomac River plant under which Mirant Potomac agrees to perform a modeling analysis to assess the effect of “downwash” from the plant (1) on ambient concentrations of sulfur dioxide (“SO2”), nitrogen dioxide (“NO2”), carbon monoxide (“CO”) and particulate matter less than or equal to 10 micrometers (“PM10”) for comparison to the applicable national ambient air quality standards (“NAAQS”) and (2) on ambient concentrations of mercury for comparison to Virginia Standards of Performance for Toxic Pollutants. Downwash is the effect that occurs when aerodynamic turbulence induced by nearby structures causes pollutants from an elevated source, such as a smokestack, to be mixed rapidly toward the ground resulting in higher ground level concentrations of pollutants. If the modeling analysis indicates that emissions from the facility may cause exceedances of the NAAQS for SO2, NO2, CO or PM10, or exceedances of mercury compared to Virginia Standards of Performance for Toxic Pollutants, the consent order requires Mirant Potomac to submit to the Virginia DEQ a plan and schedule to eliminate and prevent such exceedances on a timely basis. Upon approval by the Virginia DEQ of the plan and schedule, the approved plan and schedule is to be incorporated by reference into the consent order. The financial and operational implications of the results of the downwash study are not known at this time. However, to the extent that the downwash study indicates that emissions from the Potomac River plant exceed either the NAAQS or the Virginia Standards of Performance for Toxic Pollutants, the remedial actions required could include material modifications to the plant or to its operation.

Mirant NY-Gen Pipeline Leak. Mirant NY-Gen, LLC discovered a leaking underground pipeline at the Hillburn generating facility in Ramapo, New York. The underground line was used for supplying kerosene fuel to the gas turbines located on site. After testing in December 2003 revealed a potential leak, the line was removed from service and plans were undertaken to excavate and sample portions of the line to determine the extent of the line damage and the possible soil contamination. In the summer of 2004 soil contamination was discovered and a subsequent testing of portions of the line revealed a small hole. Currently, investigations are continuing to determine the extent of contamination and possible remedial activities to clean up the area. Due to the ongoing evaluation to determine the extent of the contamination, the cost of remediation is unknown at this time.

New York Tax Proceedings

Mirant Americas Generation’s subsidiaries that own generating plants in New York are or were (in the settled proceedings discussed below) the petitioners in forty-one proceedings (“Tax Certiorari Proceedings”) initially brought in various New York state courts challenging the assessed value of those

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generating plants determined by their respective local taxing authorities. Mirant Bowline has challenged the assessed value of the Bowline generating facility and the resulting local tax assessments paid for tax years 1995 through 2003. Mirant Bowline succeeded to rights held by Orange & Rockland Utilities, Inc. for the tax years prior to its acquisition of the Bowline Plant in 1999 under its agreement with Orange & Rockland for the purchase of that plant. Mirant Lovett has initiated proceedings challenging the assessed value of the Lovett facility for each of the years 2000 through 2003. Mirant NY-Gen, LLC (“Mirant NY-Gen” and collectively with Mirant Bowline and Mirant Lovett, the “New York Debtors”) has settled its tax certiorari proceedings with respect to the combustion turbine and hydroelectric facilities it owns for each of the years 2000 through 2003. If the remaining Tax Certiorari Proceedings result in a reduction of the assessed value of the generating facility at issue in each proceeding, the New York Debtor owning the facility would be entitled to a refund with interest of any excess taxes paid for those tax years.

On September 30, 2003, the Mirant Debtors filed a motion (the “Tax Determination Motion”) with the Bankruptcy Court requesting that it determine what the property tax liability should have been for the Bowline generating facility in each of the years 1995 through 2003, for the Lovett generating facility in each of the years 2000 through 2003, for generating facilities owned by Mirant NY-Gen in each of the years 2000 through 2003. The bases for the relief requested in the Tax Determination Motion on behalf of each of the New York Debtors were that the assessed values of generating facilities located in New York made by the relevant taxing authorities had no justifiable basis and were far in excess of their actual value. The local taxing authorities have opposed the Tax Determination Motion, arguing that the Bankruptcy Court either lacks jurisdiction over the matters addressed by the Tax Determination Motion or should abstain from addressing those issues so that they can be addressed by the state courts in which the Tax Certiorari Proceedings described in the preceding paragraph were originally filed.

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

Over the past year, all of the tax certiorari proceedings related to the generating facilities owned by Mirant NY-Gen have been resolved on terms favorable to the New York Debtors, but the tax certiorari proceedings related to the Bowline and Lovett generating facilities remain unresolved.

Utility Choice Suit

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prices. The complaint asserts various causes of action, including without limitation claims under the federal and Texas antitrust acts and the federal Racketeer Influenced and Corrupt Organizations (RICO) Act, as well as state law claims for fraud, negligent misrepresentation, and promissory estoppel. The plaintiffs seek lost profits and other compensatory damages of an unspecified amount, treble damages, exemplary damages and attorneys’ fees.

City of Alexandria Zoning Action

On December 18, 2004, the City Council for the City of Alexandria, Virginia (the “City Council”) adopted certain zoning ordinance amendments recommended by the City Planning Commission that result in the zoning status of Mirant Potomac’s generating plant being changed from “noncomplying use” to “nonconforming use subject to abatement.” Under the nonconforming use status, unless Mirant Potomac applies for and is granted a special use permit for the plant during the seven-year abatement period, the operation of the plant must be terminated within a seven-year period, and no alterations that directly prolong the life of the plant will be permitted during the seven-year period. Typically, the City Council grants special use permits with various conditions and stipulations as to the permitted use.

On January 18, 2005, Mirant Potomac and Mirant Mid-Atlantic filed a complaint against the City of Alexandria and the City Council in the Circuit Court for the City of Alexandria. The complaint seeks to overturn the actions taken by the City Council on December 18, 2004 changing the zoning status of Mirant Potomac’s generating plant and approving revocation of the 1989 SUPs, on the grounds that those actions violated federal, state and city laws. The complaint asserts, among other things, that the actions taken by the City Council constituted unlawful spot zoning, were arbitrary and capricious, constituted an unlawful attempt by the City Council to regulate emissions from the plant, and violated Mirant Potomac’s due process rights. Mirant Potomac and Mirant Mid-Atlantic request the court to enjoin the City of Alexandria and the City Council from taking any enforcement action against Mirant Potomac or from requiring it to obtain a special use permit for the continued operation of its generating plant.

Other Legal Matters

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

Tax Matters

The Company has contingent liabilities relating to taxes arising in the ordinary course of business. The Company periodically assesses its contingent liabilities in connection with these matters based upon the latest information available. For those matters where it is probable that a loss has been incurred and the loss or range of loss can be reasonably estimated, a liability is recorded on the consolidated financial statements. As additional information becomes available, the assessment and estimates of such liabilities are adjusted accordingly.

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16. Commitments and Contingencies

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

Cash Collateral and Letters of Credit

In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, the Company often is required to provide trade credit support to its counterparties or make deposits with brokers. In addition, the Company often is required to provide trade credit support for access to the transmission grid, to participate in power pools, to fund debt service reserves and for other operating activities. Trade credit support includes cash collateral, letters of credit and financial guarantees. In the event of default by the Company, the counterparty can draw on a letter of credit or apply cash collateral held to satisfy the existing amounts outstanding under an open contract. The Company’s outstanding issued letters of credit totaled $242 million as of December 31, 2004, of which $205 million were issued under pre-petition credit facilities and the remaining $37 million were issued under the DIP Facility. Upon their expiration in 2005, these letters of credit may be renewed or replaced with another form of credit support to the counterparty, if required, or under certain circumstances, the letters of credit could be partially or fully drawn upon by the counterparty.

Following is a summary of cash collateral posted with counterparties and brokers and letters of credit issued as of December 31, 2004 and 2003 (in millions):

	As of December 31,
	2004			2003
Cash collateral posted—energy trading and marketing		$	392		$	347
Cash collateral posted—debt service reserve		210			54
Cash collateral posted—other operating activities		63			5
Letters of credit—energy trading and marketing(1)		160			270
Letters of credit—debt service reserve(1)		74			234
Letters of credit—other operating activities(1)		8			97
Total		$	907		$	1,007

(1) The amounts above represent letters of credit issued under Mirant Corporation credit facilities. There are additional letters of credit issued under local credit facilities at some of our international subsidiaries that are not included in the amounts above.

Contractual Obligations

As of December 31, 2004, Mirant has the following annual commitments under various agreements (in millions):

Fiscal Year Ended:	2005		2006		2007		2008		2009		Thereafter			Total
Long-term service agreements	26		32		36		46		44			426		610
Fuel and transportation commitments	335		252		111		4		4			35		741
Operating leases	147		145		144		150		166			2,029		2,781
Power purchase agreements (Note 17)	211		52		52		52		52			625		1,044
Total minimum payments	$	719	$	481	$	343	$	252	$	266		$	3,115	$	5,176

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Mirant is in the process of evaluating all of the Mirant Debtors executory contracts in order to determine which contracts will be assumed, assumed and assigned, or rejected. Once the evaluation is complete with respect to each particular contract, the Company expects to file an appropriate motion with the Bankruptcy Court seeking approval to assume or reject the contract. The court will then determine to grant or deny such motions. See Note 3 for a discussion of Mirant’s rejected contracts.

Long-Term Service Agreements

As of December 31, 2004, the total estimated commitments for long-term service agreements (“LTSAs”) associated with turbines installed or in storage were approximately $610 million. These commitments are payable over the terms of the respective agreements, which range from ten to twenty years. These agreements have terms that allow for cancellation of the contract by the Company upon the occurrence of several major events during the term of the contracts. Estimates for future commitments for the LTSAs are based on the stated payment terms in the contracts at the time of execution. These payments are subject to an annual inflationary adjustment. If the Company were to cancel these contracts due to the aforementioned major events, the estimated commitments for the remaining LTSAs would be reduced.

As part of the Chapter 11 process, Mirant rejected its LTSAs and entered into new agreements on June 16, 2004 related to certain of its combustion turbine generation facilities. The new agreements provide more favorable terms, including reduced pricing and increased flexibility to modify terms based upon market conditions. Under the terms of the previous LTSAs, Mirant had prepaid future maintenance services at certain generating facilities. The Company recognized a $33 million charge in reorganization items, net in the consolidated statement of operations for the year ended December 31, 2004 as a result of forfeited prepayments and impairments of certain purchased intangible assets related to the previous LTSAs.

Also as part of the Chapter 11 process, Mirant rejected its LTSA associated with the Wrightsville generation facility on September 30, 2004. The Company recognized a $3 million charge in reorganization items, net for the year ended December 31, 2004 for forfeited prepayments and the expected cost of settling the vendor’s claim as a result of the contract rejection.

Fuel and Transportation Commitments

In April 2002, Mirant Mid-Atlantic entered into a long-term fuel purchase agreement. The fuel supplier converts coal feedstock received at the Company’s Morgantown facility into a synthetic fuel. Under the terms of the agreement, Mirant Mid-Atlantic is required to purchase a minimum of 2.4 million tons of fuel per annum through December 2007. Minimum purchase commitments became effective upon the commencement of the synthetic fuel plant operation at the Morgantown facility in July 2002. The purchase price of the fuel varies with the delivered cost of the coal feedstock. Based on current coal prices, it is expected that as of December 31, 2004, total estimated minimum commitments under this agreement were $320 million.

In addition to the coal commitment described above, Mirant has approximately $326 million in purchase commitments related to an arrangement between Mirant Americas Energy Marketing and the synthetic fuel supplier whereby the synthetic fuel supplier is required to purchase coal directly from the coal supplier. Mirant Americas Energy Marketing’s minimum coal purchase commitments are reduced to the extent that the synthetic fuel supplier purchases coal under this arrangement.. As of December 31, 2004, Mirant has approximately $95 million in purchase commitments under fuel purchase and transportation agreements, which are in effect through 2029.

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Operating Leases

Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively. As of December 31, 2004, the total notional minimum lease payments for the remaining life of the leases was approximately $2.5 billion. Rent expenses associated with the Morgantown and Dickerson operating leases totaled approximately $103 and $96 million for the years ended December 31, 2004 and 2003, respectively. Mirant Mid-Atlantic remitted all required lease payments through December 31, 2004.

These leases are part of a leveraged lease transaction. Three series of certificates were issued and sold pursuant to a Rule 144A offering and, subsequently, exchanged for certificates issued pursuant to an exchange offer registered under the Securities Act of 1933 (the “Securities Act”). These certificates are interests in pass through trusts that hold the lessor notes issued by the owner lessors. Mirant Mid-Atlantic pays rent to an indenture trustee, who in turn makes payments of principal and interest to the pass through trusts and remits remaining balances to the lessors for the benefit of the owner participants. As of August 27, 2003, Mirant Mid-Atlantic had less than 300 holders of record. Therefore, Mirant Mid-Atlantic notified the SEC that it would no longer be a voluntary reporting entity under the Securities Act of 1934 (the “Exchange Act”). Under the terms of the leases, Mirant Mid-Atlantic is required to amend the rent schedule to the leases to reflect an increase in rental payments commensurate with the 0.5% increase in interest on the lessor notes that is payable by the lessors so long as Mirant Mid-Atlantic is not a reporting entity under the Exchange Act. On September 15, 2004, the Bankruptcy Court granted a motion filed by the respective landlords for the leased assets seeking to compel Mirant Mid-Atlantic to pay the incremental rent. On September 25, 2004, the Debtors filed a motion for rehearing with respect to the order compelling Mirant Mid-Atlantic to pay the incremental rent, which was denied on October 28, 2004. Mirant Mid-Atlantic appealed that decision of the Bankruptcy Court on November 5, 2004. No hearing on the appeal has been scheduled with the District Court at this time. If Mirant Mid-Atlantic were to continue its status as not being a voluntary reporting entity under the Exchange Act for the remainder of the terms of the leveraged leases, the additional rent expense would be approximately $54 million over the remaining terms of the leases as of December 31, 2004. As a result of the Bankruptcy Court’s granting the motion compelling Mirant Mid-Atlantic to pay the incremental rent, Mirant Mid-Atlantic recognized additional operations and maintenance expense of approximately $7 million for year ended December 31, 2004 in the consolidated statements of operations.

On August 31, 2004, Mirant Mid-Atlantic and certain other Debtors filed a complaint with the Bankruptcy Court commencing an adversary proceeding seeking to recharacterize its obligations under its leveraged lease financing as indebtedness, and seeking other declaratory relief relating to the impact of the leases on Mirant Mid-Atlantic if the leases are not recharacterized. Resolution of those additional issues raised in the complaint are necessary to the decision whether to assume or reject the leases if the leases are determined to be “true leases” rather than a financing arrangement. In the event the Bankruptcy Court recharacterizes the leases as indebtedness, the treatment of the resulting indebtedness would be addressed in a proposed Plan of reorganization of Mirant Mid-Atlantic. This recharacterization may require the Company to re-evaluate the accounting for the leases and record the indebtedness as a pre-petition liability on the Company’s consolidated balance sheets. The Company then also would record the leased assets in property, plant and equipment. In the event the leases are found to be true leases and it is determined that the leases should be assumed or should be assumed and assigned, Mirant Mid-Atlantic would require Bankruptcy Court approval to do so and, subject to certain exceptions set forth in the Bankruptcy Code would need to cure certain of the existing defaults under the leases (unless such defaults are duly waived by the requisite owner lessors and certificate holders). If Mirant Mid-Atlantic cannot assume the leases or if, subject to Bankruptcy Court approval, Mirant Mid-Atlantic determines in its business judgment that the leases should be rejected, the owner lessors would be entitled to a return of the leased assets and a claim for damages, if any, arising from such rejection, subject to the limitation on allowed claims under

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Section 502(b)(6) of the Bankruptcy Code applicable to leases of real property. Any claims arising on account of rejection would be subject to compromise in Mirant Mid-Atlantic’s Chapter 11 case. The impact of any of these events would be reflected in Mirant’s financial statements if and when the events occur.

On October 22, 2004 the owner lessors and the indenture trustee for the certificate holders each filed separate motions to dismiss the entire Chapter 11 case of Mirant Mid-Atlantic, alleging that Mirant Mid-Atlantic is solvent and that the Chapter 11 filing with respect to Mirant Mid-Atlantic was in “bad faith.” The motions were denied following a hearing on January 6, 2005. The owner lessors and indenture trustee for the certificate holders have sought leave to appeal that decision. In the unlikely event that the owner lessors and the indenture trustee are successful on appeal, then the Chapter 11 case of Mirant Mid-Atlantic would be dismissed as would be the complaint filed by Mirant Mid-Atlantic on August 31, 2004 (as subsequently amended) and it would be unlikely that Mirant Mid-Atlantic could recharacterize the leveraged lease transaction as a financing, or reject the leases and receive the benefit of the cap on damages in Section 502(b)(6) of the Bankruptcy Code.

In a second set of motions filed on October 25, 2004, the owner lessors and the indenture trustee for the certificate holders each moved to dismiss all the claims for relief contained in the complaint filed on August 31, 2004 other than the claim seeking recharacterization on the grounds that the additional claims for relief were premature and were seeking “advisory opinions” which courts are not free to give. The hearing on these two motions occurred on January 6, 2005. The Bankruptcy Court denied the motions in part and granted them in part, allowing certain of the claims for relief that were challenged by the owner lessors and the indenture trustee to proceed, while others were dismissed without prejudice to being refiled in the future. Therefore, the Debtors who were plaintiffs in the original complaint filed an amended complaint on February 9, 2005. Trial is scheduled to begin on March 29, 2005.

As a result of Mirant Mid-Atlantic’s bankruptcy filing, a lease event of default has occurred under the leases. The leases provide that, upon a lease event of default, the owner lessors’ remedies include (1) terminating the leases and repossessing the leased assets, (2) selling their interests in the leased assets, (3) demanding payment by Mirant Mid-Atlantic of the excess, if any, of the termination value over the fair market sales value of the leased assets or the discounted fair market rental value of the leased assets and (4) demanding payment of the termination value mitigated by a sale of the leased assets for the account of Mirant Mid-Atlantic. The termination value for the leases was approximately $1.4 billion at December 31, 2004 and generally decreases over time. The ability of the owner lessors to exercise their remedies under the leases is currently stayed as a result of Mirant Mid-Atlantic’s Chapter 11 filing.

Mirant has commitments under other operating leases with various terms and expiration dates. Minimum lease payments under non-cancelable operating leases approximate $40 million in 2005, $40 million in 2006, $32 million in 2007, $30 million in 2008, $23 million in 2009 and $159 million thereafter. Expenses associated with these commitments totaled approximately $45 million, $37 million and $53 million during 2004, 2003 and 2002, respectively.

See Note 3 for discussion of a contractual obligation relating to the sale of an asset that has been reclassified as liabilities subject to compromise.

17. Power Purchase Agreements and Obligations Under Energy Delivery and Purchase Commitments

Under the asset purchase and sale agreement for the PEPCO generating assets, Mirant assumed and recorded net obligations of approximately $2.4 billion representing the estimated fair value (at the date of acquisition) of out-of-market energy delivery and power purchase agreements (“PPAs”), which consisted of five PPAs and two transition power agreements (“TPAs”). The estimated fair value of the contracts was derived using forward prices obtained from brokers and other external sources in the market place including brokers and trading platforms/exchanges such as NYMEX and estimated load information.

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The PPAs are for a total capacity of 735 MW and expire over periods through 2021. Upon adoption of SFAS No. 133 on January 1, 2001, each PPA contract was evaluated to determine whether it met the definition of a derivative contract under the standard. PPAs determined to be derivative instruments are recorded on the balance sheet at fair value, with changes in fair value recorded currently in generation revenue. The Company recognized $168 million, $171 million and $35 million of unrealized gains during 2004, 2003 and 2002, respectively, in connection with the PPAs. At December 31, 2004, the estimated commitments under the PPA agreements were $1.0 billion based on the total remaining MW commitment at contractual prices. As of December 31, 2004, the fair value of the PPAs recorded in liabilities subject to compromise in the consolidated balance sheet totaled $540 million, of which $80 million would have been classified as current.

As discussed in Note 15, “Litigation and Other Contingencies,” on December 23, 2003, Mirant’s motion to reject the Back-to-Back Agreement related to the PPAs was denied by the federal district court in Texas. In December 2004, we notified PEPCO and the Bankruptcy Court that we are suspending all future payments under the Back-to-Back Agreement absent further order of the Court. For 2004, the suspended payment amount was $16 million.

The TPAs state that Mirant will sell a quantity of MWhs over the life of the contracts based on PEPCO’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. The proportion of MWhs supplied under the District of Columbia agreement was 36%. As actual MWhs are purchased or sold under these agreements, Mirant amortizes a ratable portion of the obligation as an increase in revenues. The Company recorded, as an adjustment of revenues, amortization of the TPA obligation of approximately $344 million, $426 million and $423 million during the years ended December 31, 2004, 2003 and 2002, respectively. The remaining TPA obligation will be amortized as an increase in revenue through January 2005. As of December 31, 2004, the remaining obligations for the TPAs recorded in transition power agreements and other obligations totaled $9 million, all of which is classified as current.

On October 24, 2003, Mirant and PEPCO reached a settlement, subject to Bankruptcy Court approval, whereby, the contracted prices for power delivered under the TPAs were increased by $6.40 per MWh and the TPAs were assumed. In addition, the settlement agreement grants an allowed pre-petition general unsecured claim related to the amendment of these agreements in the amount of $105 million. On November 19, 2003, the Bankruptcy Court approved the settlement and the assumption of the amended TPAs. Mirant recorded a liability for this claim on its consolidated balance sheet as of December 31, 2003. As a result of the amendment of the TPA’s, Mirant reduced its liability for transition power agreements in an amount equal to the allowed pre-petition claim, which resulted in a reduction in TPA amortization recognized as revenues for 2004 and January 2005.

Other obligations totaled $10 million, of which $5 million is classified as current liabilities. These obligations are related primarily to out-of-market gas transportation and power sales agreements, and are recorded in transition power agreements and other obligations in the consolidated balance sheet at December 31, 2004.

18. Related-Party Arrangements and Transactions

Other Agreements

Prior to the sale of its investment in Perryville in June 2002, Mirant entered into various agreements with, or with respect to its investment in, Perryville, including a tolling agreement which was entered into in April 2001. Costs under the tolling agreement were approximately $5 million in 2002. Prior to the sale of its 50% ownership interest in Perryville, Mirant accounted for its investment under the equity method. Management believes the costs under the Perryville tolling agreement are substantially similar to costs the

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Company would have incurred with an unrelated party. Mirant completed the sale of its 50% ownership interest in Perryville in June 2002. See Note 3 for further discussion.

Prior to its sale in October 2003, Mirant had an operating and maintenance contract with respect to its investment in the Birchwood generating plant. Mirant had a 50% ownership interest in Birchwood and accounted for its investment under the equity method. Fees paid to Mirant under the Birchwood operating and maintenance contract were approximately $7 million in 2003 and $8 million in 2002. Management believes that the fees paid by Birchwood for these services are equivalent to the fees that would be charged by an unrelated party.

In May 2003, Mirant announced that it had entered an agreement to sell all but one half of one percent of its 50% ownership interest in the Birchwood generating plant located near Fredricksburg, Virginia. On October 9, 2003, the Bankruptcy Court entered an order approving the consummation of the sale, which was completed on October 31, 2003.

19. Loss Per Share

Mirant calculates basic loss per share by dividing the loss available to common stockholders by the weighted average number of common shares outstanding. Diluted loss per share gives effect to dilutive potential common shares, including stock options, convertible notes and debentures and convertible trust preferred securities. The following table shows the computation of basic and diluted loss per share for 2004, 2003 and 2002 (in millions, except per share data).

	2004			2003			2002
Loss from continuing operations	$	(410	)	$	(3,632	)	$	(2,340	)
Discontinued operations	(66		)	(174		)	(98		)
Cumulative effect of changes in accounting principles	—			(29		)	—
Net loss	$	(476	)	$	(3,835	)	$	(2,438	)
Basic and diluted:
Weighted average shares outstanding	405.5			405.0			402.2
Loss per share from:
Continuing operations	$	(1.01	)	$	(8.97	)	$	(5.82	)
Discontinued operations	(0.16		)	(0.43		)	(0.24		)
Cumulative effect of changes in accounting principles	—			(0.07		)	—
Net loss	$	(1.17	)	$	(9.47	)	$	(6.06	)

The following potential common shares were excluded from the earnings per share calculations (in millions):

	2004	2003	2002
Out-of-the-money options	16.8	23.3	20.7
Shares issuable upon conversion of debt	58.6	59.8	35.6
Shares issuable upon conversion of convertible preferred securities	12.5	12.5	12.5
Total	87.9	95.6	68.8

As discussed in note 3, the Company plans to cancel the common stock as part of our proposed Plan.

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Stock-Based Compensation

Mirant accounts for its stock-based employee compensation plans under the intrinsic-value method of accounting for recognition, but discloses fair value pro forma information. Under this method, compensation expense for employee stock options is recorded on the date of grant only if the current market price of the underlying stock exceeds the exercise price. The following table illustrates the effect on net loss if the fair-value-based method had been applied to all outstanding and unvested stock based awards in each period (in millions, except per share data). See also Note 14.

	December 31,
	2004				2003			2002
Net loss, as reported		$	(476	)	$	(3,835	)	$	(2,438	)
Deduct: Total stock-based employee compensation expense determined under fair-value- based method for all awards, net of related tax effects		(12		)	(27		)	(24		)
Pro forma net loss		$	(488	)	$	(3,862	)	$	(2,462	)
Loss per share:
Basic and diluted—as reported		$	(1.17	)	$	(9.47	)	$	(6.06	)
Basic and diluted—pro forma		$	(1.20	)	$	(9.54	)	$	(6.12	)

20. Segment Reporting

The Company has two reportable segments: North America and International. The North America segment consists of the Company’s power generation and energy trading and marketing operations in the United States and Canada. The International segment includes power generation in the Philippines and generation, transmission and distribution operations in the Caribbean. The Company’s reportable segments are strategic businesses that are geographically separated and managed independently. Certain corporate costs, including corporate overhead and interest, are not allocated to a reporting segment. In 2002, the Company closed its European trading operations and sold its European and Chinese distribution and generation assets. Prior to the sale of these assets, these operations are reflected in the International segment. The accounting policies of the segments are the same as those described in Note 2 “Accounting and Reporting Policies.”

In 2003, certain corporate costs were not allocated to a reporting segment. Beginning January 1, 2004, the Company changed its allocation methodology related to corporate overhead expenses to better reflect its operating structure. As a result, substantially all of the operating expenses are now allocated to the Company’s North America and International segments. The new methodology allocates costs using several methods but is primarily based on gross margin, property, plant and equipment balances, and labor costs. The allocation methodology may be subject to further change during the Chapter 11 reorganization process.

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Business Segments

	North America			International				Corporate and Eliminations				Consolidated
	(In millions)
2004:
Operating Revenues:
Generation		$	3,486		$	477			$	—			$	3,963
Integrated utilities and distribution		—			573				—				573
Net trading revenue		36			—				—				36
Total operating revenues		3,522			1,050				—				4,572
Cost of fuel, electricity and other products		2,326			294				—				2,620
Gross margin		1,196			756				—				1,952
Operating Expenses:
Operations and maintenance		730			295				(21		)		1,004
Depreciation and amortization		165			122				21				308
Goodwill impairment losses		—			582				—				582
Other impairment losses and restructuring charges		9			1				13				23
Loss on sales of assets, net		50			2				1				53
Total operating expenses		954			1,002				14				1,970
Operating income (loss)		$	242		$	(246	)		$	(14	)		$	(18	)
Total other expense, net													(25		)
Loss from continuing operations before reorganization items and income taxes													(43		)
Reorganization items, net													259
Provision for income taxes													87
Minority interest													21
Loss from continuing operations													$	(410	)
Total assets		$	9,354		$	4,730			$	(2,660	)		$	11,424
Gross property additions		99			57				3				159
Investment in equity method affiliates		6			231				11				248

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	North America				International			Corporate and Eliminations				Consolidated
	(In millions)
2003:
Operating Revenues:
Generation		$	4,138			$	502		$	—			$	4,640
Integrated utilities and distribution		—				523			—				523
Net trading revenue		(1		)		—			—				(1		)
Total operating revenues		4,137				1,025							5,162
Cost of fuel, electricity and other products		2,904				280			—				3,184
Gross margin		1,233				745			—				1,978
Operating Expenses:
Operations and maintenance		701				257			127				1,085
Depreciation and amortization		200				116			24				340
Goodwill impairment losses		2,067				—			—				2,067
Long-lived asset impairment losses		1,338				1			—				1,339
Other impairment losses and restructuring charges		19				13			25				57
(Gain) loss on sales of assets, net		(38		)		1			(9		)		(46		)
Total operating expenses		4,287				388			167				4,842
Operating (loss) income		$	(3,054	)		$	357		$	(167	)		(2,864		)
Total other expense, net													(317		)
Loss from continuing operations before reorganization items and income taxes													(3,181		)
Reorganization items, net													290
Provision for income taxes													126
Minority interest													35
Loss from continuing operations													$	(3,632	)
Total assets		$	9,443			$	5,147		$	(2,257	)		$	12,333
Gross property additions		271				206			16				493
Investment in equity method affiliates		7				168			92				267

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	North America				International				Corporate and Eliminations				Consolidated
	(In millions)
2002:
Operating Revenues:
Generation		$	3,352			$	525			$	—			$	3,877
Integrated utilities and distribution		—				485				—				485
Net trading revenue		341				—				—				341
Total operating revenues		3,693				1,010				—				4,703
Cost of fuel, electricity and other products		2,254				228				—				2,482
Gross margin		1,439				782				—				2,221
Operating Expenses:
Operations and maintenance		770				322				117				1,209
Depreciation and amortization		149				116				17				282
Goodwill impairment losses		—				697				—				697
Long-lived asset impairment losses		509				101				—				610
Other impairment losses and restructuring charges		270				65				28				363
Gain on sales of assets, net		(5		)		(36		)		—				(41		)
Total operating expenses		1,693				1,265				162				3,120
Operating loss		$	(254	)		$	(483	)		$	(162	)		(899		)
Total other expense, net														(417		)
Loss from continuing operations before income taxes														(1,316		)
Provision for income taxes														949
Minority interest														75
Loss from continuing operations														$	(2,340	)
Total assets		$	15,293			$	4,622			$	(492	)		$	19,423
Gross property additions		1,342				160				10				1,512
Investment in equity method affiliates		96				187				13				296

Geographic Areas

	Revenue
		International
	North America	The Philippines		Jamaica		All Other	Total	Consolidated
	(In millions)
2004	$3,522		$487		$495	$68	$1,050		$4,572
2003	$4,137		$505		$455	$65	$1,025		$5,162
2002	$3,693		$537		$427	$46	$1,010		$4,703

	Long-Lived Assets
			International
	North America	The Philippines		Jamaica		All Other	Total	Consolidated
	(In millions)
2004	$4,317		$1,522		$568	$114	$2,204		$6,521
2003	$4,496		$2,178		$571	$110	$2,859		$7,355

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21. Quarterly Financial Data (Unaudited)

Summarized quarterly financial data for 2004, 2003 and 2002 is as follows (in millions):

	Operating Revenue			Operating Income (Loss)			Income (Loss) Before Cumulative Effect of Changes in Accounting Principles				Consolidated Net Income (Loss)				Basic and Diluted Income (Loss) Per Common Share
2004:
March		$	1,184	$	140			$	30			$	30			$	0.07
June		1,264		166				32				32				0.08
September		1,121		147				32				32				0.08
December		1,003		(471		)		(570		)		(570		)		(1.40		)
2003:
March		$	1,506	$	176			$	—			$	(28	)		$	(0.07	)
June		1,250		(2,038		)		(2,202		)		(2,202		)		(5.44		)
September		1,595		279				(33		)		(33		)		(0.08		)
December		811		(1,281		)		(1,571		)		(1,572		)		(3.88		)

Financial data for the quarters ended December 31, 2004 and June 30, 2003 reflect goodwill impairment charges discussed in Note 8. Financial data for the quarter ended December 31, 2003 reflects the long-lived asset impairment charge discussed in Note 7.

22. Valuation and Qualifying Accounts

	Years Ended December 31, 2004, 2003 and 2002
				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)
2004		$	206		$	6		$	32			$	(10	)		$	234
2003		198			9			—				(1		)		206
2002		197			1			—				—				198
Provision for uncollectible accounts (noncurrent)
2004		$	205		$	—		$	(34	)		$	(10	)		$	161
2003		104			130			—				(29		)		205
2002		114			14			—				(24		)		104

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

· provide reasonable assurance as to the detection of fraud.

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we carried out an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004. In conducting our assessment, management utilized the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2004.

Our independent registered public accounting firm, KPMG LLP, has issued reports on management’s assessment of internal control over financial reporting and our consolidated financial statements. KPMG LLP’s reports can be found on pages F-91 and F-92.

PART III

Item 10. Directors and Executive Officers of the Registrant

Set forth below is a description of the business experience during the past five years or more of the directors and executive officers of the Company, their positions and offices with the Company, and other biographical information. In accordance with Mirant’s Bylaws, each director shall hold office until the next election of the class for which such director shall have been chosen, and until his or her successor has been elected and qualified, or until his or her earlier death, resignation or removal. Ms. Fuller and Messrs. Lesar and Robinson serve in the class of 2004; Messrs. Dahlberg, Eizenstat and McCullough serve in the class of 2005; and Messrs. Correll and McDonald serve in the class of 2006. Because of its bankruptcy, the Company did not hold an annual meeting in 2004 and has not scheduled an annual meeting for 2005; therefore, the directors in the classes of 2004 and 2005 are serving until the next election. Officers are elected by our board of directors to hold office until their successors are elected and have qualified or until their removal, resignation, death or disqualification.

Name	Age	Position and Experience
A.D. Correll	63	Director since 2000 Chairman of the Board, and Chief Executive Officer of Georgia-Pacific Corporation, manufacturers and distributors of building products, pulp, and paper. He was appointed to his current position in 1993. He also served as President from 1991 until September 2002. He is a director of Georgia-Pacific Corporation, Norfolk Southern Corporation, and SunTrust Banks, Inc.
A.W. Dahlberg	64	Director since 1996 Chairman of the Board of Mirant. He was appointed to his current position in August 2000. He served as Chairman of the Board of the Southern Company from 1995 until April 2001, during which time Southern Company was the parent of Mirant. He also served as Chief Executive Officer of Southern Company from 1995 until March 2001. He is a director of Equifax, Inc.

Stuart E. Eizenstat	61	Director since 2001 Partner of Covington & Burling where he has headed the law firm’s international practice since 2001. He served as Deputy Secretary of the United States Department of the Treasury from July 1999 to January 2001. He was Under Secretary for Economics, Business, and Agricultural Affairs of the United States Department of State from 1997 to July 1999 and Under Secretary for International Trade of the United States Department of Commerce from 1996 to 1997. He served as U.S. Ambassador to the European Union from 1993 to 1996 and was President Carter’s Chief Domestic Policy Advisor from 1977 to 1981. He is a trustee of BlackRock Funds.
S. Marce Fuller	44	President, Chief Executive Officer and Director since July 1999 Served as President and Chief Executive Officer of Mirant’s Mirant Americas Energy Marketing subsidiary from September 1997 to July 1999 and Executive Vice President of Mirant from October 1998 to July 1999. She is a director of Curtiss-Wright Corporation and EarthLink, Inc.
David J. Lesar	51	Director since 2000 Chairman, President and Chief Executive Officer of Halliburton Company, diversified energy services, engineering and construction company. He was President and Chief Operating Officer of Halliburton Company from June 1997 until August 2000, when he was appointed to his current position. He is a director of Halliburton Company and Lyondell Chemical Company.
Robert F. McCullough	62	Director since February 2003 Senior partner and former Chief Financial Officer of AMVESCAP plc, independent global investment managers. He served as Director and CFO of AMVESCAP from 1996 until April 2004. He is a director of Acuity Brands, Inc.
James F. McDonald	64	Director since 2001 Chairman, President and Chief Executive Officer of Scientific-Atlanta, Inc., broadband equipment, software and services provider. He has served as President and Chief Executive Officer since 1993 and Chairman of the Board of Scientific-Atlanta since November 2000. He is a director of Burlington Resources, Inc., NDCHealth Corporation, and Scientific-Atlanta, Inc.
Ray M. Robinson	57	Director since 2001 Chairman of the East Lake Community Foundation in Atlanta. He was Vice Chairman of the East Lake Community Foundation from May 2003 until October 2003, when he was appointed to his present position. He was President of the Southern Region of AT&T Corporation from 1996 until his retirement in May 2003. He is a director of Aaron Rents, Inc., Acuity Brands, Inc., Avnet, Inc., Citizens Trust Bank and Choice Point Inc.

M. Michele Burns	47	Executive Vice President, Chief Financial Officer and Chief Restructuring Officer Elected Executive Vice President and Chief Financial Officer in May 2004 and Chief Restructuring Officer in August 2004. Prior to joining Mirant she was Executive Vice President and Chief Financial Officer of Delta Air Lines, Inc. from August 2000 to May 2004; Senior Vice President—Finance and Treasurer from February 2000 to August 2000; Vice President—Finance and Treasurer from September 1999 to February 2000 and Vice President—Corporate Tax from January 1999 to September 1999.
Curtis A. Morgan	44	Executive Vice President and Chief Operating Officer Elected Executive Vice President, North America effective August 25, 2003 and Executive Vice President and Chief Operating Officer in June 2004. Prior to Joining Mirant, he was President, East Region, Reliant Energy Wholesale Group, where he was responsible for Reliant assets and markets in the mid-Western and Eastern United States from September 2000 to July 2003. He was Senior Vice President, Corporate Planning and Development, Reliant Energy from March 1998 to September 2000.
Vance N. Booker	51	Senior Vice President, Administration Elected Senior Vice President in August 1999. Served as Vice President, Administration from June 1996 to August 1999.
Douglas L. Miller	54	Senior Vice President and General Counsel Elected Senior Vice President and General Counsel in October 1999. From 1997 until he joined the Company in 1999, Mr. Miller was managing partner of the Troutman Sanders LLP Hong Kong office.
Dan Streek	43	Vice President and Controller Elected Vice President and Controller effective February 20, 2003. Prior to joining Mirant, he served as Chief Financial Officer of Aquila, Inc., a global energy company, from August 2001 to November 2002; Senior Vice President, Finance of Aquila Merchant Services, Inc. from January 2000 to August 2001 and Vice President and Assistant Controller for Aquila, Inc. from July 1998 to January 2000.

Director Independence

We have adopted criteria for independence contained in our Corporate Governance Guidelines that supplement the criteria established for director independence by the New York Stock Exchange. Our Board has determined that all of our non-management directors are independent under the rules of the New York Stock Exchange and these supplemental independence criteria.

Family Relationships—None.

Certain Legal Proceedings

On July 14, 2003, Mirant and most of its domestic subsidiaries filed for reorganization under Chapter 11 of the United States Bankruptcy Code. Certain of Mirant’s officers are also officers or

directors of other subsidiaries that filed for reorganization under Chapter 11. As such, each of the Company’s executive officers has been associated with a corporation that filed a petition under the federal bankruptcy laws within the last five years.

Ms. Fuller served as an executive officer of Mobile Energy Services Company, LLC (“Mobile Energy”) from July 1995 to July 2001, and as an executive officer of its parent company Mobile Energy Services Holdings, Inc. (“MESH”) from February 1995 to January 1999. Mobile Energy owns a generating facility, which provides power and steam to a tissue mill in Mobile, Alabama. Mobile Energy and MESH filed for bankruptcy on January 14, 1999 in response to the announcement by its then largest customer, a pulp mill, of plans to cease operations in September 1999. A plan of reorganization for Mobile Energy and MESH was approved by the Bankruptcy Court and became effective December 16, 2003.

Audit Committee and Designated Audit Committee Financial Experts

Mirant has a standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act, and its members are Messrs. McCullough, Lesar and Eisenstat. The Board of Directors has evaluated the members of the Audit Committee, and determined that each member is independent, as independence for audit committee members is defined under the listing standards of the New York Stock Exchange and Item 7(d)(3)(iv) of Schedule 14A of the Exchange Act. The Board also has determined that each member of the Audit Committee is financially literate and has designated Messrs. Lesar and McCullough as “audit committee financial experts” as defined in SEC regulations.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires all executive officers, directors and persons who are the beneficial owners of more than 10% of the common stock of the Company to file reports of ownership with the SEC indicating their ownership of the Company’s equity securities and to report any changes in that ownership. Specific due dates for these reports have been established, and the Company is required to report in this Annual Report on Form 10-K any failure to comply therewith during the fiscal year ended December 31, 2004. Based on copies of the reporting forms received by it or on the written representations from certain reporting persons that no Form 5 (Annual Statement of Changes in Beneficial Ownership) were required to be filed under applicable rules of the SEC, the Company believes that all reporting requirements under Section 16(a) for the fiscal year 2004 were met in a timely manner by our directors, executive officers and greater than 10% beneficial owners with the following executions: Mr Streek did not timely file two Form 4s, and Ms. Fuller, Mr. Booker, Mr. Miller and Mr. John W. Ragan, a former executive officer of the Company, each did not timely file a Form 4. Subsequently, all such Form 4 reports have been filed.

Code of Ethics for Senior Financial Officers

Mirant has adopted a code of ethics that applies to its Chief Executive Officer, Chief Financial Officer, Senior Vice President—Finance, Treasurer, Chief Risk Officer, Vice President—Tax, and Controller. A copy of the code of ethics for senior financial officers is posted on Mirant’s website at www.mirant.com and also will be provided without charge upon request made in writing to the Corporate Secretary at 1155 Perimeter Center West, Atlanta, GA 30338. Mirant intends to post any amendments and waivers to the code of ethics for senior financial officers on its website.

Shareholder Nominees to Board of Directors

We have not yet adopted procedures by which shareholders may recommend director candidates for consideration by our Nominating and Governance Committee because we are not holding annual shareholders’ meetings while we are under Chapter 11 protection.

Item 11. Executive Compensation

Summary Compensation Table

This table sets forth cash and non-cash compensation paid to or accrued for the past three years for the five most highly compensated executive officers of Mirant serving as of December 31, 2004.

	Annual Compensation					Long-Term Compensation
Name and Principal Position	Year	Salary ($)	Bonus ($)(1)	Other Annual Compensation ($)(2)		Restricted Stock Awards ($)(3)		Number of Securities Underlying Stock Options (#)(6)		All Other Compensation ($)(7)
S. M. Fuller	2004	841,803	850,000		38,736		—		—		38,731
President & CEO	2003	800,000	173,643		100,303		1,620,000		500,000		37,125
	2002	800,000	—		170,057		4,173,023		425,000		36,000
M. M. Burns EVP, CFO & Chief Restructuring Officer(4)	2004	401,639	2,186,100		18,000		—		—		23,798
C. A. Morgan	2004	427,350	543,483		18,000		—		—		32,559
EVP& COO(5)	2003	156,822	124,000		—		—		—		8,331
D. L. Miller	2004	375,000	298,313		18,000		—		—		28,956
SVP & General	2003	349,795	62,708		—		395,000		125,000		36,364
Counsel	2002	300,000	120,000		905		323,640		50,000		53,476
V. N. Booker	2004	280,000	229,740		18,000		—		—		12,844
SVP Administration	2003	267,301	140,500		—		233,000		75,000		12,956
	2002	250,000	87,500		—		341,620		53,000		10,875

(1) 2004 Bonuses in this column include a payment to Ms. Burns and a payment to Mr. Morgan. To hire Ms. Burns from her former employer in May 2004, Mirant paid $1,500,000 as the first of three potential “make-whole payments” at the commencement of her prior employment. These payments are intended to replace value Ms. Burns lost by terminating her employment. The remaining two payments to Ms. Burns will be made over the next two years. During 2004, Mr. Morgan received two retention payments worth $100,000, which had been agreed to at the commencement of his employment in August 2003.

(2) During a portion of 2004, and all of 2003 and 2002, Mirant owned fractional shares of a business aircraft which Ms. Fuller used at a cost to Mirant of $17,736, $79,704 and $140,020, respectively. Mirant no longer owns any shares in an aircraft.

(3) During 2004, Mirant did not grant any Restricted Stock Units. The values shown reflect the value of the restricted stock unit on the date of the grant. No dividends are paid on restricted stock units. Over the past three years, Mirant has granted three types of Restricted Stock, described as follows: Performance Restricted Stock Units: Granted in 2002 and 2001, these vest 20% each time Mirant’s stock price increases 20% over the price on the day of grant. The stock price targets that must be met for the remaining restricted stock to vest range from $14.53 to $51.02 per share. Restricted Stock Units paid in cash: Granted in 2003, these units are payable in cash based upon the price of Mirant common stock on the vesting date. The outstanding units from these grants vest over time between March 2005 and February 2007. Restricted Stock Units paid in stock: Granted in 2003, these units are paid in shares of stock. One-half of these units vest in shares on each of the first and second anniversary dates of the grant date.

(4) Ms. Burns first became an executive officer of Mirant on May 20, 2004.

(5) Mr. Morgan first became an executive officer of Mirant on August 25, 2003.

(6) Mirant does not have any long-term incentive plans other than stock options and restricted stock, therefore no LTIP Payout is included in the table.

(7) Includes contributions to the Mirant Services Employee Savings Plan (“ESP”), Profit Sharing Arrangement within the Mirant Services Employee Savings Plan (“Profit Sharing”), as well as non-pension related accruals under the Supplemental Benefit Plan (“SBP”). The breakout of the 2004 contributions is provided in the following table:

	ESP ($)		Profit Sharing ($)		SBP ($)
S. M. Fuller		9,225		—	29,506
M. M. Burns		4,228		6,150	13,420
C. A. Morgan		9,225		6,150	17,184
D. L. Miller		9,225		6,150	13,581
V. N. Booker		9,225		—	3,619

Stock Option Grant, Exercise and Year-End Values Tables

Mirant did not grant any stock options in 2004.

Aggregated Stock Option Exercises in 2004 and Year-End Option Values

					Number of Securities Underlying Unexercised Options at Year-End			Value of Unexercised In-the-Money Options at Year-End ($)(2)
Name	Number of Shares Acquired on Exercise (#)		Value Realized ($)(1)		Exercisable	Unexercisable		Exercisable			Unexercisable
S. M. Fuller		—		—	1,225,660		475,000		$	0		$	0
M. M. Burns		—		—	—		—		$	0		$	0
C. A. Morgan		—		—	—		—		$	0		$	0
D. L. Miller		—		—	232,126		100,000		$	0		$	0
V. N. Booker		—		—	204,677		67,667		$	0		$	0

(1) The Value Realized is ordinary income, before taxes, and represents the amount equal to the excess of the fair market value of the shares or rights at the time of exercise above the exercise price.

(2) These columns represent the excess of the fair market value of Mirant’s common stock of $0.385 per share, as of December 31, 2004, above the exercise price of the options. The amounts under the Exercisable column report the “value” of options that are vested and therefore could be exercised. The Unexercisable column reports the “value” of options that are not vested and therefore could not be exercised as of December 31, 2004.

Long-Term Incentive Plans—Awards in 2004

Mirant did not grant any long-term incentive in 2004.

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Pension Plan Table

The following table shows the estimated annual pension benefit payable (rounded to $000) at normal retirement age (65) under Mirant’s qualified pension plan, non-qualified pension plans and pension-related contracts, based on the stated compensation (rounded to $000) and years of Accredited Service with Mirant’s subsidiaries.

	Years of Accredited Service
Compensation	10		15		20		25		30
$250,000	$	41,100	$	61,150	$	81,300	$	101,850	$	121,600
500,000	83,600		124,900		166,300		208,100		249,100
750,000	126,100		188,650		251,300		314,350		376,600
1,000,000	168,600		252,400		336,300		420,600		504,100
1,250,000	211,100		316,150		421,300		526,850		631,600
1,500,000	253,600		379,900		506,300		633,100		759,100
1,750,000	296,100		443,650		591,300		739,350		886,600

Pension benefits are calculated using a final average pay formula and are based on a single life annuity without reduction for joint and survivor annuities. Compensation for pension purposes is limited to the average of the highest three (five for Mr. Miller) of the final 10 years’ compensation. For Ms. Fuller, compensation is base salary plus the excess of short-term incentive compensation over 10 percent of base salary. For the other executive officers listed in the Summary Compensation Table, it is base salary plus the excess of short-term incentive compensation over 15 percent of base salary. Accredited service at December 31, 2004, is as follows: Ms. Fuller—19.3; Mr. Miller—5.6; and Mr. Booker—28.3. Ms. Burns and Mr. Morgan are excluded from the table because they are not eligible to receive a defined benefit pension; they are covered under a defined contribution program.

In 2002 and 2003 the Company purchased individual annuity contracts for certain employees who were eligible for non-tax qualified pension plans and met certain age, years of service and benefit requirements. These annuities provide the same after-tax benefit at retirement and offset amounts otherwise payable by the Company under existing non-tax qualified pension plans. They are not intended to increase a participant’s pension benefit.

Compensation of Directors

Only non-employee directors are compensated for Board service. The pay components are annual retainers of $70,000 and meeting fees of $2,500 for each Board meeting attended and $1,250 for each committee or other meeting attended.

The Board of Directors met 10 times in 2004. Each director attended more than 85 percent of meetings of the Board and committees on which he or she served.

The Audit Committee met 15 times, the Compensation Committee met 8 times, the Third Party Claims Committee met 7 times and the Nominating and Governance Committee met 5 times. There is no pension plan for non-employee directors.

Mr. Dahlberg, as the non-employee Chairman of the Board, receives the same annual retainer and meeting fees as the other non-employee directors. Until April 2004, Mirant owned fractional shares of a business aircraft. Mr. Dahlberg’s personal use of such aircraft cost Mirant $10,004 in 2004. Mirant no longer owns any shares of the aircraft.

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Employment Contracts, Termination of Employment and Change-in-Control Agreements

Certain contracts that were entered into prior to Mirant’s bankruptcy filing are considered pre-petition, and as such, the Company may decide either to accept or reject these contracts as part of the bankruptcy proceedings based on a cost benefit analysis of the individual agreements. Additionally, any such claims with respect to such pre-petition agreements are subject to Bankruptcy Court approval and the Court may limit the amount of such claims.

Employment Contracts

Mirant has entered into employment agreements with certain of the executive officers named in the Summary Compensation Table. The compensation provided for in each employment agreement is discussed below. The amounts granted under these agreements are forfeited upon termination for cause or resignation. Amounts are paid immediately if the employee dies, becomes disabled, or is terminated without cause. The Board is solely responsible for administering these agreements.

Ms. Fuller—Effective December 30, 2004, Mirant entered into a Separation Agreement and Release of Certain Claims with Ms. Fuller. In general, the agreement provides for the payment by Mirant of a lump sum separation payment to Ms. Fuller of $3.4 million upon the termination of Ms. Fuller’s active employment with Mirant. In addition, the agreement provides that Ms. Fuller will be paid her 2004 short-term incentive at her target incentive amount of $850,000. In exchange, Ms. Fuller releases all rights and claims under her change-in-control agreement with Mirant, which would have provided severance protection of three times base salary and bonus.

The terms of the agreement were approved by the Bankruptcy Court in the Northern District of Texas pursuant to an Order issued in the Court on September 2, 2004 and were agreed to by all of the Statutory Committees. Ms. Fuller is not covered under the Key Employee Retention Program as detailed below.

Ms. Fuller and Mr. Booker do not have employment agreements.

Ms. Burns—Effective April 14, 2004, Mirant entered into an employment agreement with M. Michele Burns. This agreement provides for compensation and benefits during the three-year term of the agreement, commencing on May 1, 2004. Under the terms of the agreement, Ms. Burns’ base salary is $600,000 a year and Mirant evaluates Ms. Burns’s compensation on a yearly basis. In addition, Ms. Burns’s target bonus level during the term of her employment will be no less than 75% of base salary with a maximum of two times the target. Upon joining Mirant in May 2004, Ms. Burns received a make-whole payment of $1.5 million. Contingent on her continued employment, Ms. Burns will receive additional make-whole payments of $1 million on April 1, 2005 and $500,000 on April 1, 2006. Upon emergence from Chapter 11, Ms. Burns will receive a bonus of not less than $1.2 million. Retention bonuses in the amount of $500,000 each will be awarded on April 1, 2006 and April 1, 2007. Additionally, Ms. Burns is eligible to receive the equivalent of her base salary under the same terms as those in place for the Company’s Key Employee Retention Program (“KERP”), as approved by the Bankruptcy Court.

Mr. Morgan—Effective September 1, 2003, Mirant entered into an employment agreement with Curtis A. Morgan. This agreement provides for compensation and benefits during the two-year term of the agreement. Under the terms of the agreement, Mr. Morgan’s base salary will be at least $360,000 a year and Mirant evaluates Mr. Morgan’s compensation on a yearly basis. In addition, Mr. Morgan’s target bonus is 65% of base salary with a maximum of two times the target according to Mirant’s Short-Term Incentive Program. Mr. Morgan received lump sum retention bonuses of $50,000 each on January 1, 2004 and May 1, 2004. Mr. Morgan was also eligible to receive two additional lump sum retention bonuses of $50,000 on September 1, 2004 and $100,000 on January 1, 2005, which he waived as part of his inclusion in the KERP as discussed below.

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On June 28, 2004, Mr. Morgan was promoted to Executive Vice President and Chief Operations Officer.

Mr. Miller—Effective October 1, 1999, Mirant entered into an employment agreement with Douglas L. Miller, which expired October 1, 2004. This agreement provides for compensation and benefits during the five-year term of the agreement. Under the terms of the agreement, because Mr. Miller was still employed by the Company on September 30, 2004, his retirement payments will be calculated with five years of additional service included in the pension and supplemental executive retirement plan calculations.

Key Employee Retention Program

On or around September 23, 2004, the Company entered into a Key Employee Retention Program and Change in Control Release Agreement with Mr. Booker, Mr. Miller, and Mr. Morgan.

In general, the Agreement provides for the waiver and termination of any change in control rights and agreements that the employee may have against the Company in exchange for the employee’s participation in the KERP and the KERP Enhanced Severance Program, both as previously adopted by the Bankruptcy Court on August 11, 2004. The Agreement also provides for the waiver of any previously awarded retention or severance benefits and of any administrative claims that the employee may have had on account of any retention agreement, employment agreement, severance agreement and/or other employee benefit plan.

As participants in the KERP, each of Messrs. Booker, Miller and Morgan was eligible to receive up to 100% of their base salary if a plan of reorganization is filed with the Bankruptcy Court by a specified date. If the plan had not been filed by a specified date, the total payout percentage would have decreased by 10%. The amounts are payable 15% upon the filing of the plan of reorganization, 35% upon a confirmation of a plan of reorganization, and 50% at the effective date of a plan of reorganization. The plan of reorganization was filed on January 19, 2005, which was in line with the Court approved deadline, thus the applicable executive officers will receive full awards.

As part of the Key Employee Retention Program and Change in Control Release Agreement, each of the above named executive officers is eligible for the KERP Enhanced Severance Program until one-year after emergence from Chapter 11. In the event of termination without cause, including a constructive termination, each are eligible for a severance payment equal to 24 months’ base salary plus target short-term incentive and 24 months of medical benefits.

Ms. Fuller is not a participant in this program.

Change In Control Arrangements

Mr. Booker, Ms. Fuller, and Mr. Miller had change in control agreements that were effective upon a change in control of Mirant. As part of the bankruptcy proceedings and either under the terms of the Key Employee Retention Agreement or an individual separation agreement, each individual has waived their rights to their individual Change-in-Control agreement.

Ms. Burns’s employment agreement provides that if a change in control occurs and her employment terminates within one year of such change in control by reason of her discharge other than for cause or by reason of her resignation for good reason, including because of a material change in job responsibilities, then Ms. Burns is entitled to a separation payment equal to two times annual base salary and bonus, plus certain other accrued obligations and make-whole payments.

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Compensation Committee Interlocks and Insider Participation—None

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

This table shows the number of shares owned by directors and executive officers as of December 31, 2004. The shares owned by all directors and executive officers as a group constituted less than one percent of the total number of shares of Mirant common stock outstanding as of December 31, 2004. Mirant has no known beneficial owner of more than 5% of Mirant common stock.

	Total Beneficial Ownership(1)		Common Shares Beneficially Owned(2)			Non-Convertible Economic Interests(3)		Shares Individuals Have Rights to Acquire within 60 days(4)
A. D. Correll		127,217		33,736			93,481		—
A. W. Dahlberg		194,969		90,851			104,118		—
Stuart E. Eizenstat		35,882		—			35,882		—
S. Marce Fuller		2,657,642		37,714			1,085,935		1,533,993
David J. Lesar		77,197		5,000	(5)		72,197		—
Robert F. McCullough		2,762		1,000			1,762		—
James F. McDonald		29,540		29,540			—		—
Ray M. Robinson		32,684		2,500			30,184		—
M. Michele Burns		—		—			—		—
Curtis A. Morgan		—		—			—		—
Douglas L. Miller		371,700		10,014			71,227		290,459
Vance N. Booker		327,556		4,641			75,571		247,344
Directors and Executive Officers as a Group (13 people)		3,857,149		214,996			1,570,357		2,071,796

(1) “Beneficial ownership” means the sole or shared power to vote, or to direct the voting of, a security, or sole or shared investment power with respect to a security, or any combination thereof. This column includes ownership interests in Mirant Common Shares, Non-Convertible Economic Interests, and Shares Individuals Have Rights to Acquire within 60 days (as of 3/1/2005).

(2) Indicates shares of Mirant common stock beneficially owned. Shares indicated are included in the Total Beneficial Ownership column.

(3) Indicates stock units and performance restricted stock units held in various benefit plans. Although these rights track the market value of Mirant common stock, they are payable in cash and are not convertible into common stock. Shares indicated are included in the Total Beneficial Ownership column.

(4) Indicates shares of Mirant common stock that certain directors and executive officers have the right to acquire within 60 days, by exercising stock options. The numbers and values of exercisable stock options as of December 31, 2004 are shown in Item 11. Shares indicated are included in the Total Beneficial Ownership column.

(5) Includes 5,000 shares held by a Family Limited Partnership. Mr. Lesar disclaims beneficial ownership of 71.06% of these shares.

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Securities Authorized for Issuance Under Equity Compensation Plans

The following table indicates the compensation plans under which equity securities of Mirant are authorized for issuance as of December 31, 2004:

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)(1)
Equity compensation plans approved by security holders		15,532,732		$	13.12		23,957,405
Equity compensation plans not approved by security holders		—		—			—
Total		15,532,732		$	13.12		23,957,405

(1) Includes 8,685,294 shares subject to issuance under the Mirant Corporation Employee Stock Purchase Plan.

Item 13. Certain Relationships and Related Transactions

Certain principals, or employees, of Alix Partners, LLC (“Alix Partners”), a management consulting firm, served in the role of Chief Restructuring Officer and in various other financial professional roles during 2003 and 2004. Mirant has retained Alix Partners to provide certain financial expertise to assist the Company during the pendency of its bankruptcy case. During 2003 and 2004, Mirant incurred fees and expenses totaling $7.8 million and $9.6 million, respectively, payable to AlixPartners. Mirant expects to continue to incur fees with AlixPartners during the pendency of its bankruptcy case.

Item 14. Principal Accountant Fees and Services

The following table presents fees for professional audit services and other services rendered by KPMG LLP (in millions):

	2004		2003
Audit Fees(1)	$	12.9	$	12.9
Audit-Related Fees(2)	0.6		0.6
Tax Fees(3)	0.6		1.0
All Other Fees(4)	0.4		0.4
Total	$	14.5	$	14.9
Reaudit Fees(5)	$	—	$	9.1

(1) Audit fees and expenses represent fees billed and expected to be billed for professional services rendered in connection with: (a) audits and reviews of the 2004 and 2003 Mirant Corporation consolidated financials in accordance with standards of the Public Company Accounting Oversight Board; (b) audits of various Mirant subsidiary financial statements required by statute or regulation; (c) consultations on accounting matters reflected in the financial statements; and (d) attestation services with respect to securities offerings and SEC filings.

(2) Audit-related fees represent fees billed for professional services rendered in connection with: (a) audits of Mirant’s employee benefit plans; (b) internal control reviews; (c) accounting consultation on the implementation of Sarbanes-Oxley Section 404; (d) audits of Mirant subsidiaries not required

105

by statute or regulation (domestic and foreign); and (e) document production in connection with legal subpoenas related to various Mirant litigation matters.

(3) Tax fees represent fees billed for professional services rendered in connection with: (a) tax compliance; (b) consultations related to tax audits and appeals; and (c) technical tax advice on rulings from taxing authorities.

(4) All other fees represent fees billed for professional services rendered with respect to various tax aspects of Mirant’s Sarbanes-Oxley Section 404 implementation.

(5) Reaudit fees represent fees billed for professional services rendered in connection with the reaudits and rereviews of the Mirant Corporation and subsidiaries 2002, 2001 and 2000 consolidated financial statements, in accordance with auditing standards generally accepted in the United States of America.

Audit Committee Pre-Approval

The Audit Committee has pre-approved all audit services and permitted non-audit services provided by the independent auditors, and the compensation, fees and terms for such services. The Committee also has approved an Independent Auditor Policy which requires Committee pre-approval of the compensation and terms of service for audit services provided by the independent auditors and any changes in terms and compensation resulting from changes in audit scope, company structure or other matters. The Policy also requires pre-approval by the Audit Committee or its Chairman, the independent auditor’s lead partner, Mirant’s Chief Financial Officer or Controller, and Mirant’s Corporate Secretary of the compensation and terms of service for any permitted non-audit services provided by the independent auditors. Any proposed non-audit services exceeding the pre-approved fee levels require pre-approval by the Audit Committee or its Chairman. The Controller reports quarterly to the Audit Committee on the services performed and fees incurred by the independent auditors for audit and permitted non-audit services during the prior quarter.

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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		www.mirant.com
(Registrant’s Telephone Number, Including Area Code)		Web Page

		Page
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002		F-2
Consolidated Balance Sheets as of December 31, 2004 and 2003		F-3
Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2004, 2003 and 2002		F-4
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2004, 2003 and 2002		F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002		F-5
Notes to Consolidated Financial Statements		F-6
Reports of Registered Independent Public Accounting Firm		F-77 and F-78

		Page
	PART I
Item 1.	Business	5
Item 2.	Properties	27
Item 3.	Legal Proceedings	29
Item 4.	Submission of Matters to a Vote of Security Holders	55
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	56
Item 6.	Selected Financial Data	57
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	58
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	90
Item 8.	Financial Statements and Supplementary Data	93
Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	94
Item 9A.	Controls and Procedures	94
	PART III
Item 10.	Directors and Executive Officers of the Registrant	95
Item 11.	Executive Compensation	99
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	104
Item 13.	Certain Relationships and Related Transactions	105
Item 14.	Principal Accountant Fees and Services	105
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	107

Exhibit No.				Exhibit Name
2.1*				Joint Chapter 11 Plan of Reorganization for Mirant Corporation and its Affiliated Debtors (Designated on Form 8-K filed January 19, 2005 as Exhibit 2.1).
3.1*				Restated Certificate of Incorporation (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 3.1)
3.2*				Bylaws of the Company (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 3.2)
4.1*				Specimen Stock Certificate (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 4.1)
4.2*				Certificate of Trust (Designated on Form S-1 in Registration No. 333-41680 as Exhibit 4.2)
4.3*				Trust Agreement (Designated on Form S-1 in Registration No. 333-41680 as Exhibit 4.3)
4.4*				Certificate of Designation of Series A Preferred Stock (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 4.11)
4.5*				Certificate of Designation of Series B Preferred Stock (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 4.12)
4.6*				Rights Agreement between Southern Energy, Inc. (now Mirant Corporation) and ChaseMellon Shareholder Services, L.L.C. (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 4.13)
10.1*				Form of Master Separation and Distribution Agreement (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 10.1)
10.2*				Form of Transitional Services Agreement (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 10.2)
10.3*				Form of Indemnification and Insurance Matters Agreement (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 10.3)
10.4*				Form of Technology and Intellectual Property Ownership and Licenses Agreement (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 10.4)
10.5*				Form of Confidential Disclosure Agreement (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 10.5)
10.6*				Form of Employee Matters Agreement (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 10.6)
10.7*				Form of Amendment Number One to the Employee Matters Agreement (Designated on Form 10-K filed March 21, 2001 as Exhibit 10.7)
10.8*				Form of Tax Indemnification Agreement (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 10.7)
10.9*				Form of Registration Rights Agreement (Designated on Form S-1 in Registration No. 333-35390 as Exhibit 10.8)
10.10*				Form of Mirant Corporation Employee Stock Purchase Plan

10.11*		Form of Amended and Restated Mirant Corporation Omnibus Incentive Compensation Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.29)
10.12*		Form of Amended and Restated Mirant Services Supplemental Executive Retirement Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.31)
10.13*		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)
10.14*		First Amendment to Mirant Corporation Deferred Compensation Plan for Directors and Select Employees (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.56)
10.15*		Form of Mirant Services Supplemental Benefit Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.57)
10.16*		First Amendment to the Mirant Services Supplement Benefit Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.58)
10.17*		Form of Mirant Services Supplemental Compensation Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.59)
10.18*		First Amendment to the Mirant Services Supplemental Compensation Plan (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.60)
10.19*		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)
10.20*		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)
10.21*		Employment Agreement with Douglas L. Miller (Designated on Form 10-K filed March 11, 2002 as Exhibit 10.63)
10.22*		Mirant Corporation—Four Year Credit Agreement (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.67)
10.23*		Mirant Corporation—364-Day Credit Facility (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.68)
10.24*		Mirant Corporation—Facility C Credit Agreement (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.69)
10.25*		Mirant Americas Generation, LLC—Facility B Credit Agreement (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.70)
10.26*		Mirant Americas Generation, LLC—Facility C Credit Agreement (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.71)
10.27*		Second Amendment to the Mirant Services Supplemental Benefit Plan (Designated on Form 10-K filed April 29, 2003 as Exhibit 10.72)
10.28*		Employment Agreement with Daniel Streek (Designated on Form 10-K filed April 29, 2003 as Exhibit 10.83 )
10.29*		Second Amendment to the Mirant Services Supplemental Compensation Plan (Designated on Form 10-K filed April 29, 2003 as Exhibit 10.84)
10.30*		Third Amendment to the Amended and Restated Mirant Services Supplemental Executive Retirement Plan (Designated on Form 10-Q filed October 27, 2003 as Exhibit 10.86)
10.31*		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)
10.32*		Debtor-In-Possession Credit Agreement (Designated on Form 10-Q filed December 19, 2003 as Exhibit 10.88)
10.33*		Employment Agreement with Curt Morgan (Designated on Form 10-Q filed December 19, 2003 as Exhibit 10.89)

10.34*		Key Employee Retention Program and Change in Control Release Agreement with Curt Morgan (Designated on Form 8-K filed September 24, 2004 as Exhibit 99.1)
10.35*		Key Employee Retention Program and Change in Control Release Agreement with Douglas L. Miller (Designated on Form 8-K filed September 24, 2004 as Exhibit 99.2)
10.36*		Key Employee Retention Program and Change in Control Release Agreement with Vance N. Booker (Designated as Exhibit 99.3 on Form 8-K filed September 24, 2004 as Exhibit 99.3)
10.37*		Key Employee Retention Program and Change in Control Release Agreement with Aldie Warnock (Designated on Form 8-K filed September 24, 2004 as Exhibit 99.4)
10.38*		Separation Agreement and Release of Certain Claims with S. Marce Fuller (Designated on Form 8-K filed December 30, 2004 as Exhibit 99.1)
10.39		California Settlement Agreement dated January 13, 2005
10.40		Third Amendment to the Mirant Services Supplemental Benefit Plan
10.41		Third Amendment to the Mirant Services Supplemental Compensation Plan
10.42		Fourth Amendment to the Amended and Restated Mirant Services Supplemental Executive Retirement Plan
10.43		Third Amendment to the Mirant Corporation Deferred Compensation Plan for Directors and Select Employees
10.44*		Employment Agreement with M. Michele Burns (Designated on Form 10-Q filed August 9, 2004 as Exhibit 10.1)
10.45*		Employment Agreement with Loyd Alderman Warnock (Designated on Form 10-Q filed August 9, 2004 as Exhibit 10.2)
10.46		2005 Short-term Incentive Plan Description
10.47		2005 Named Executive Officer Base Compensation and Short-term Incentive Targets
16.1*		Arthur Andersen LLP letter to the Securities and Exchange Commission dated May 15, 2002 (Designated on Form 8-K filed May 15, 2002 Exhibit 16.1)
21.1		Subsidiaries of Registrant
24.1		Power of Attorney
31.1		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a))
31.2		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a))
32.1		Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))
32.2		Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))

	MIRANT CORPORATION
	By:	/s/ S. MARCE FULLER
		President and Chief Executive Officer

	Signatures		Title
*		Chairman of the Board
A. W. Dahlberg
/s/ S. MARCE FULLER		President, Chief Executive Officer and Director (Principal
S. Marce Fuller		Executive Officer)
/s/ M. MICHELE BURNS		Executive Vice President and Chief Financial Officer
M. Michele Burns		(Principal Financial Officer)
/s/ DAN STREEK		Vice President and Controller (Principal Accounting Officer)
Dan Streek
*		Director
A. D. Correll
*		Director
Stuart E. Eizenstat
*		Director
David J. Lesar
*		Director
James F. McDonald
*		Director
Ray M. Robinson
*		Director
Robert F. McCullough